Attached files

file filename
EX-31.02 - EXHIBIT 31.02 - XCEL ENERGY INCxcelex3102q12017.htm
EX-99.01 - EXHIBIT 99.01 - XCEL ENERGY INCxcelex9901q12017.htm
EX-32.01 - EXHIBIT 32.01 - XCEL ENERGY INCxcelex3201q12017.htm
EX-31.01 - EXHIBIT 31.01 - XCEL ENERGY INCxcelex3101q12017.htm

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
FORM 10-Q
(Mark One)
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2017
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number: 001-3034
Xcel Energy Inc.
(Exact name of registrant as specified in its charter)
Minnesota
 
41-0448030
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
 
 
414 Nicollet Mall
 
 
Minneapolis, Minnesota
 
55401
(Address of principal executive offices)
 
(Zip Code)
(612) 330-5500
(Registrant’s telephone number, including area code)

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer x
 
Accelerated filer ¨
Non-accelerated filer ¨
 
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 April 24, 2017
Common Stock, $2.50 par value
 
507,762,881 shares

 



TABLE OF CONTENTS

PART I
FINANCIAL INFORMATION
 
Item 1 —

 

 

 

 

 

 

Item 2 —

Item 3 —

Item 4 —

 
 
 
PART II
OTHER INFORMATION
 
Item 1 —

Item 1A —

Item 2 —

Item 6 —

 
 
 

 
 
 
 
Certifications Pursuant to Section 302
1

 
Certifications Pursuant to Section 906
1

 
Statement Pursuant to Private Litigation
1


This Form 10-Q is filed by 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); Public Service Company of Colorado (PSCo); and Southwestern Public Service Company (SPS).  Xcel Energy Inc. and its consolidated subsidiaries are also referred to herein as Xcel Energy.  NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are also referred to collectively as utility subsidiaries.  The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin, which is operated on an integrated basis and is managed by NSP-Minnesota, is referred to collectively as the NSP System. Additional information on the wholly owned subsidiaries is available on various filings with the Securities and Exchange Commission (SEC).



PART I — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(amounts in thousands, except per share data)

 
 
Three Months Ended March 31
 
 
2017
 
2016
Operating revenues
 
 
 
 
Electric
 
$
2,299,060

 
$
2,185,119

Natural gas
 
625,703

 
565,689

Other
 
21,659

 
21,465

Total operating revenues
 
2,946,422

 
2,772,273

 
 
 
 
 
Operating expenses
 
 
 
 
Electric fuel and purchased power
 
925,221

 
861,852

Cost of natural gas sold and transported
 
365,134

 
312,117

Cost of sales — other
 
8,587

 
8,245

Operating and maintenance expenses
 
586,430

 
577,410

Conservation and demand side management program expenses
 
67,533

 
57,436

Depreciation and amortization
 
365,204

 
320,020

Taxes (other than income taxes)
 
142,094

 
145,323

Total operating expenses
 
2,460,203

 
2,282,403

 
 
 
 
 
Operating income
 
486,219

 
489,870

 
 
 
 
 
Other income, net
 
6,446

 
4,250

Equity earnings of unconsolidated subsidiaries
 
7,875

 
13,182

Allowance for funds used during construction — equity
 
14,313

 
13,113

 
 
 
 
 
Interest charges and financing costs
 
 
 
 
Interest charges — includes other financing costs of $5,858 and $6,336, respectively
 
165,934

 
156,443

Allowance for funds used during construction — debt
 
(7,022
)
 
(5,990
)
Total interest charges and financing costs
 
158,912

 
150,453

 
 
 
 
 
Income before income taxes
 
355,941

 
369,962

Income taxes
 
116,664

 
128,650

Net income
 
$
239,277

 
$
241,312

 
 
 
 
 
Weighted average common shares outstanding:
 
 
 
 
Basic
 
508,278

 
508,667

Diluted
 
508,774

 
509,150

 
 
 
 
 
Earnings per average common share:
 
 
 
 
Basic
 
$
0.47

 
$
0.47

Diluted
 
0.47

 
0.47

 
 
 
 
 
Cash dividends declared per common share
 
$
0.36

 
$
0.34

 
 
 
 
 
See Notes to Consolidated Financial Statements


3


XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
(amounts in thousands)

 
 
Three Months Ended March 31
 
 
2017
 
2016
Net income
 
$
239,277

 
$
241,312

 
 
 
 
 
Other comprehensive income
 
 
 
 
 
 
 
 
 
Pension and retiree medical benefits:
 
 
 
 
Amortization of losses included in net periodic benefit cost, net of tax of $615 and $142, respectively
 
948

 
211

 
 
 
 
 
Derivative instruments:
 
 
 
 
Net fair value decrease, net of tax of $0 and $(2), respectively
 

 
(4
)
Reclassification of losses to net income, net of tax of $534 and $604, respectively
 
825

 
938

 
 
825

 
934

 
 
 
 
 
Other comprehensive income
 
1,773

 
1,145

Comprehensive income
 
$
241,050

 
$
242,457

 
 
 
 
 
See Notes to Consolidated Financial Statements




4


XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(amounts in thousands)
 
Three Months Ended March 31
 
2017
 
2016
Operating activities
 
 
 
Net income
$
239,277

 
$
241,312

Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
Depreciation and amortization
368,880

 
323,761

Conservation and demand side management program amortization
755

 
1,162

Nuclear fuel amortization
30,852

 
25,750

Deferred income taxes
193,740

 
160,379

Amortization of investment tax credits
(1,278
)
 
(1,307
)
Allowance for equity funds used during construction
(14,313
)
 
(13,113
)
Equity earnings of unconsolidated subsidiaries
(7,875
)
 
(13,182
)
Dividends from unconsolidated subsidiaries
11,754

 
11,481

Share-based compensation expense
17,953

 
13,099

Net realized and unrealized hedging and derivative transactions
4,177

 
5,576

Other

 
(388
)
Changes in operating assets and liabilities:
 
 
 
Accounts receivable
(4,959
)
 
(4,780
)
Accrued unbilled revenues
174,387

 
129,444

Inventories
88,355

 
88,570

Other current assets
(76,758
)
 
(16,635
)
Accounts payable
(121,390
)
 
(22,063
)
Net regulatory assets and liabilities
17,863

 
34,404

Other current liabilities
(42,270
)
 
(32,442
)
Pension and other employee benefit obligations
(148,565
)
 
(118,774
)
Change in other noncurrent assets
263

 
(1,196
)
Change in other noncurrent liabilities
(12,693
)
 
(8,508
)
Net cash provided by operating activities
718,155

 
802,550

 
 
 
 
Investing activities
 
 
 
Utility capital/construction expenditures
(749,073
)
 
(700,319
)
Allowance for equity funds used during construction
14,313

 
13,113

Purchases of investment securities
(172,738
)
 
(109,373
)
Proceeds from the sale of investment securities
167,645

 
104,280

Investments in WYCO Development LLC and other
(2,571
)
 
(260
)
Other, net
(5,315
)
 
(1,548
)
Net cash used in investing activities
(747,739
)
 
(694,107
)
 
 
 
 
Financing activities
 
 
 
Proceeds from (repayments of) short-term borrowings, net
213,000

 
(663,000
)
Proceeds from issuance of long-term debt

 
747,127

Repayments of long-term debt
(217
)
 
(333
)
Repurchases of common stock
(2,943
)
 
(789
)
Dividends paid
(172,456
)
 
(162,410
)
Other
(18,291
)
 
(12,487
)
Net cash provided by (used in) financing activities
19,093

 
(91,892
)
 
 
 
 
Net change in cash and cash equivalents
(10,491
)
 
16,551

Cash and cash equivalents at beginning of period
84,476

 
84,940

Cash and cash equivalents at end of period
$
73,985

 
$
101,491

 
 
 
 
Supplemental disclosure of cash flow information:
 
 
 
Cash paid for interest (net of amounts capitalized)
$
(174,381
)
 
$
(164,511
)
Cash received for income taxes, net

 
7,414

 
 
 
 
Supplemental disclosure of non-cash investing and financing transactions:
 
 
 
Property, plant and equipment additions in accounts payable
$
185,617

 
$
192,818

Issuance of common stock for reinvested dividends and equity awards
11,673

 
7,703

 
 
 
 
See Notes to Consolidated Financial Statements

5


XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(amounts in thousands, except share and per share data)

 
March 31, 2017
 
Dec. 31, 2016
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
73,985

 
$
84,476

Accounts receivable, net
781,248

 
776,289

Accrued unbilled revenues
555,445

 
729,832

Inventories
519,081

 
604,226

Regulatory assets
360,309

 
363,655

Derivative instruments
20,885

 
38,224

Prepaid taxes
176,998

 
106,697

Prepayments and other
145,203

 
138,682

Total current assets
2,633,154

 
2,842,081

 
 
 
 
Property, plant and equipment, net
33,158,384

 
32,841,750

 
 
 
 
Other assets
 
 
 
Nuclear decommissioning fund and other investments
2,187,946

 
2,091,858

Regulatory assets
3,009,825

 
3,080,867

Derivative instruments
48,681

 
50,189

Other
247,351

 
248,532

Total other assets
5,493,803

 
5,471,446

Total assets
$
41,285,341

 
$
41,155,277

 
 
 
 
Liabilities and Equity
 
 
 
Current liabilities
 
 
 
Current portion of long-term debt
$
755,448

 
$
255,529

Short-term debt
605,000

 
392,000

Accounts payable
861,506

 
1,044,959

Regulatory liabilities
186,926

 
220,894

Taxes accrued
544,177

 
457,392

Accrued interest
151,929

 
172,901

Dividends payable
182,795

 
172,456

Derivative instruments
26,706

 
26,959

Other
393,489

 
503,953

Total current liabilities
3,707,976

 
3,247,043

 
 
 
 
Deferred credits and other liabilities
 
 
 
Deferred income taxes
6,999,546

 
6,784,319

Deferred investment tax credits
61,937

 
63,216

Regulatory liabilities
1,400,234

 
1,383,212

Asset retirement obligations
2,815,677

 
2,782,229

Derivative instruments
143,684

 
148,146

Customer advances
189,984

 
195,214

Pension and employee benefit obligations
964,398

 
1,112,366

Other
235,333

 
223,965

Total deferred credits and other liabilities
12,810,793

 
12,692,667

 
 
 
 
Commitments and contingencies


 


Capitalization
 
 
 
Long-term debt
13,696,461

 
14,194,718

Common stock — 1,000,000,000 shares authorized of $2.50 par value; 507,762,881 and
507,222,795 shares outstanding at March 31, 2017 and Dec. 31, 2016, respectively
1,269,407

 
1,268,057

Additional paid in capital
5,872,933

 
5,881,494

Retained earnings
4,036,352

 
3,981,652

Accumulated other comprehensive loss
(108,581
)
 
(110,354
)
Total common stockholders’ equity
11,070,111

 
11,020,849

Total liabilities and equity
$
41,285,341

 
$
41,155,277

 
 
 
 
See Notes to Consolidated Financial Statements

6


XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED)
(amounts in thousands)

 
Common Stock Issued
 
Retained Earnings
 
Accumulated
Other
Comprehensive
Loss
 
Total
Common
Stockholders’
Equity
 
Shares
 
Par Value
 
Additional Paid In Capital
 
 
 
Three Months Ended March 31, 2017 and 2016
 
 
 
 
 
 
 
 
 
 
Balance at Dec. 31, 2015
507,536

 
$
1,268,839

 
$
5,889,106

 
$
3,552,728

 
$
(109,753
)
 
$
10,600,920

Net income


 


 


 
241,312

 


 
241,312

Other comprehensive income


 


 


 


 
1,145

 
1,145

Dividends declared on common stock


 


 


 
(173,619
)
 


 
(173,619
)
Issuances of common stock
417

 
1,043

 
(3,755
)
 


 


 
(2,712
)
Repurchases of common stock


 


 
(789
)
 


 


 
(789
)
Share-based compensation


 


 
5,377

 


 


 
5,377

Balance at March 31, 2016
507,953

 
$
1,269,882

 
$
5,889,939

 
$
3,620,421

 
$
(108,608
)
 
$
10,671,634

 
 
 
 
 
 
 
 
 
 
 
 
Balance at Dec. 31, 2016
507,223

 
$
1,268,057

 
$
5,881,494

 
$
3,981,652

 
$
(110,354
)
 
$
11,020,849

Net income


 


 


 
239,277

 


 
239,277

Other comprehensive income


 


 


 


 
1,773

 
1,773

Dividends declared on common stock


 


 


 
(183,815
)
 


 
(183,815
)
Issuances of common stock
611

 
1,527

 
3,510

 


 


 
5,037

Repurchases of common stock
(71
)
 
(177
)
 
(2,943
)
 


 


 
(3,120
)
Share-based compensation


 


 
(9,128
)
 
(762
)
 


 
(9,890
)
Balance at March 31, 2017
507,763

 
$
1,269,407

 
$
5,872,933

 
$
4,036,352

 
$
(108,581
)
 
$
11,070,111

 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements
 
 
 
 
 
 
 
 
 
 
 
 


7


XCEL ENERGY INC. 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 Xcel Energy Inc. and its subsidiaries as of March 31, 2017 and Dec. 31, 2016; the results of its operations, including the components of net income and comprehensive income, and changes in stockholders’ equity for the three months ended March 31, 2017 and 2016; and its cash flows for the three months ended March 31, 2017 and 2016. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2017 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2016 balance sheet information has been derived from the audited 2016 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2016. These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto, included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2016, filed with the SEC on Feb. 24, 2017. Due to the seasonality of Xcel Energy’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 Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2016, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2.
Accounting Pronouncements

Recently Issued

Revenue Recognition In May 2014, the Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09), which provides a new framework for the recognition of revenue. Xcel Energy 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. Xcel Energy 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. Xcel Energy 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. Xcel Energy expects that as a result of application of accounting principles for rate regulated entities, changes in the fair value of the securities in the nuclear decommissioning fund, currently classified as available-for-sale, will continue to be deferred to a regulatory asset, and 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. Xcel Energy has not yet fully determined the impacts of implementation. However, adoption is expected to occur on Jan. 1, 2019 utilizing the practical expedients provided by the standard. As such, agreements entered prior to Jan. 1, 2017 that are currently considered leases are expected to be recognized on the consolidated balance sheet, including contracts for use of office space, equipment and natural gas storage assets, as well as certain purchased power agreements (PPAs) for natural gas-fueled generating facilities. Xcel Energy expects that similar agreements entered after Dec. 31, 2016 will generally qualify as leases under the new standard, but has not yet completed its evaluation of certain other contracts, including arrangements for the secondary use of assets, such as land easements.

8




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. Xcel Energy has not yet fully determined the impacts of adoption of the standard, but expects that as a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the current ratemaking treatment, and that the impacts of adoption will be limited to changes in classification of non-service costs in the consolidated statement of income. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017.

Recently Adopted

Stock Compensation — In March 2016, the FASB issued Improvements to Employee Share-Based Payment Accounting, Topic 718 (ASU No. 2016-09), which simplifies accounting and financial statement presentation for share-based payment transactions. The guidance requires that the difference between the tax deduction available upon settlement of share-based equity awards and the tax benefit accumulated over the vesting period be recognized as an adjustment to income tax expense. Xcel Energy adopted the guidance in 2016, resulting in immaterial 2016 adjustments to income tax expense and changes in classification of cash flows related to tax withholding in the consolidated statements of cash flows for the years ended Dec. 31, 2016, 2015 and 2014.

3.
Selected Balance Sheet Data
(Thousands of Dollars)
 
March 31, 2017
 
Dec. 31, 2016
Accounts receivable, net
 
 
 
 
Accounts receivable
 
$
832,540

 
$
827,112

Less allowance for bad debts
 
(51,292
)
 
(50,823
)
 
 
$
781,248

 
$
776,289

(Thousands of Dollars)
 
March 31, 2017
 
Dec. 31, 2016
Inventories
 
 
 
 
Materials and supplies
 
$
321,518

 
$
312,430

Fuel
 
150,025

 
181,752

Natural gas
 
47,538

 
110,044

 
 
$
519,081

 
$
604,226

(Thousands of Dollars)
 
March 31, 2017
 
Dec. 31, 2016
Property, plant and equipment, net
 
 
 
 
Electric plant
 
$
38,412,137

 
$
38,220,765

Natural gas plant
 
5,365,655

 
5,317,717

Common and other property
 
1,897,263

 
1,888,518

Plant to be retired (a)
 
22,202

 
31,839

Construction work in progress
 
1,596,909

 
1,373,380

Total property, plant and equipment
 
47,294,166

 
46,832,219

Less accumulated depreciation
 
(14,576,320
)
 
(14,381,603
)
Nuclear fuel
 
2,652,026

 
2,571,770

Less accumulated amortization
 
(2,211,488
)
 
(2,180,636
)
 
 
$
33,158,384

 
$
32,841,750


(a) 
In the fourth quarter of 2017, PSCo expects to both early retire Valmont Unit 5 and convert 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.


9


4.
Income Taxes

Except to the extent noted below, Note 6 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2016 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Tax Loss Carryback Claims — In 2012-2015, Xcel Energy identified certain expenses related to 2009, 2010, 2011, 2013, 2014 and 2015 that qualify for an extended carryback beyond the typical two-year carryback period. As a result of a higher tax rate in prior years, Xcel Energy recognized a tax benefit of approximately $5 million in 2015, $17 million in 2014, $12 million in 2013 and $15 million in 2012.

Federal Audit  Xcel Energy files a consolidated federal income tax return. In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of March 31, 2017, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through 2015 claims. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). In 2016 the IRS audit team and Xcel Energy presented their case to Appeals; however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy’s 2009 through 2011 federal income tax returns, following extensions, expires in December 2017. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of the IRS’s proposed adjustment of the carryback claims.

In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the first quarter of 2017, the IRS proposed an adjustment to tax years 2012 and 2013 that could have impacted Xcel Energy’s net operating loss (NOL) and tax credit carryforwards and effective tax rate (ETR). After additional review, the IRS withdrew their proposed adjustment. As of March 31, 2017, the IRS had not proposed any other material adjustments to tax years 2012 and 2013.

State Audits  Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions of Colorado, Minnesota, Texas, and Wisconsin, and various other state income-based tax returns. As of March 31, 2017, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions were as follows:
State
 
Year
Colorado
 
2009
Minnesota
 
2009
Texas
 
2009
Wisconsin
 
2012

In 2016, Texas began an audit of years 2009 and 2010. As of March 31, 2017, Texas had not proposed any adjustments;
In 2016, Minnesota began an audit of years 2010 through 2014. As of March 31, 2017, Minnesota had not proposed any adjustments;
In 2016, Wisconsin began an audit of years 2012 and 2013. As of March 31, 2017, Wisconsin had not proposed any adjustments; and
As of March 31, 2017, there were no other state income tax audits in progress.

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

A reconciliation of the amount of unrecognized tax benefit is as follows:
(Millions of Dollars)
 
March 31, 2017
 
Dec. 31, 2016
Unrecognized tax benefit — Permanent tax positions
 
$
30.1

 
$
29.6

Unrecognized tax benefit — Temporary tax positions
 
105.3

 
104.1

Total unrecognized tax benefit
 
$
135.4

 
$
133.7



10


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)
 
March 31, 2017
 
Dec. 31, 2016
NOL and tax credit carryforwards
 
$
(45.6
)
 
$
(43.8
)

It is reasonably possible that Xcel Energy’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals and audit progress, the Minnesota, Texas and Wisconsin audits progress, and other state audits resume. As the IRS Appeals and IRS, Minnesota, Texas and Wisconsin audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $60 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 amount of the payable for interest related to unrecognized tax benefits reported are as follows:

(Millions of Dollars)
 
March 31, 2017
 
Dec. 31, 2016
Payable for interest related to unrecognized tax benefits at beginning of period
 
$
(3.4
)
 
$
(0.1
)
Interest expense related to unrecognized tax benefits recorded during the period
 
(0.9
)
 
(3.3
)
Payable for interest related to unrecognized tax benefits at end of period
 
$
(4.3
)
 
$
(3.4
)

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

5.
Rate Matters

Except to the extent noted below, the circumstances set forth in Note 12 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2016, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

NSP-Minnesota

Pending Regulatory Proceeding — Minnesota Public Utilities Commission (MPUC)
 
Minnesota 2016 Multi-Year Electric Rate Case — In November 2015, NSP-Minnesota filed a three-year electric rate case with the MPUC. The rate case is based on a requested return on equity (ROE) of 10.0 percent and a 52.50 percent equity ratio. In December 2015, the MPUC approved interim rates for 2016. The request is detailed in the table below:
Request (Millions of Dollars)
 
2016
 
2017
 
2018
Rate request
 
$
194.6

 
$
52.1

 
$
50.4

Increase percentage
 
6.4
%
 
1.7
%
 
1.7
%
Interim request
 
$
163.7

 
$
44.9

 
N/A

Rate base
 
$
7,800

 
$
7,700

 
$
7,700


Settlement Agreement

In August 2016, NSP-Minnesota and various parties reached a settlement which resolves all revenue requirement issues in dispute. The settlement agreement requires the approval of the MPUC.

11



Key terms of the settlement are listed below:

Four-year period covering 2016-2019;
Annual sales true-up;
ROE of 9.2 percent and an equity ratio of 52.5 percent;
Nuclear related costs will not be considered provisional;
Continued use of all existing riders, however no new riders may be utilized during the four-year term;
Deferral of incremental 2016 property tax expense above a fixed threshold to 2018 and 2019;
Four-year stay out provision for rate cases;
Property tax true-up mechanism for 2017-2019; and
Capital expenditure true-up mechanism for 2016-2019.

(Millions of Dollars, incremental)
 
2016
 
2017
 
2018
 
2019
 
Total
Settlement revenues
 
$
74.99

 
$
59.86

 
$

 
$
50.12

 
$
184.97

NSP-Minnesota’s sales true-up
 
59.95

 

 

 
(0.20
)
 
59.75

   Total rate impact
 
$
134.94

 
$
59.86

 
$

 
$
49.92

 
$
244.72


In March 2017, the Administrative Law Judge (ALJ) recommended that the MPUC approve the settlement as it will contribute to just and reasonable rates and that no objections to the settlement are sufficient to merit rejection. The ALJ also provided recommendations for a majority of the revenue requirement issues in the event the MPUC decides to reject the settlement.

The MPUC is anticipated to hold deliberations on the rate case in May 2017 and issue an order in June 2017.

PSCo

Recently Concluded Regulatory Proceeding — Colorado Public Utilities Commission (CPUC)

Annual Electric Earnings Test — PSCo must share with customers earnings that exceed the authorized ROE of 9.83 percent for 2015 through 2017, as part of an annual earnings test. The 2016 earnings test did not result in a material customer refund obligation as of Dec. 31, 2016. PSCo filed its 2016 earnings test with the CPUC in April 2017. The final sharing obligation will be based on the CPUC approved tariff and could vary from the current estimate.

SPS

Pending Regulatory Proceedings — Public Utility Commission of Texas (PUCT)

Appeal of the Texas 2015 Electric Rate Case Decision — SPS had requested an overall retail electric revenue rate increase of $42.1 million. In 2015, the PUCT approved an overall rate decrease of approximately $4.0 million, net of rate case expenses. In April 2016, SPS filed an appeal, with the Texas State District Court, of the PUCT’s order that had denied SPS’ request for rehearing on certain items in SPS’ Texas 2015 electric rate case related to capital structure, incentive compensation and wholesale load reductions. On March 6, 2017, the Travis County District Court denied SPS’s appeal.  On April 4, 2017, SPS appealed the District Court’s decision to the Court of Appeals.

Texas 2016 Electric Rate Case — In February 2016, SPS filed a retail electric rate case in Texas requesting an overall increase in annual base rate revenue of approximately $71.9 million, or 14.4 percent. The filing is based on a historic test year ended Sept. 30, 2015, a requested ROE of 10.25 percent, an electric rate base of approximately $1.7 billion, and an equity ratio of 53.97 percent. In September 2016, SPS revised its requested rate increase to $61.5 million, along with recovery of rate case expenses, for an overall revised request of $65.5 million.

12



In December 2016, SPS reached a settlement that resolves all issues in the rate case. The total estimated rate impact is $51.8 million. The final rates established in the case are effective retroactive to July 20, 2016. In December 2016, an ALJ approved interim rates, effective as of Dec. 10, 2016. In the fourth quarter of 2016, SPS deferred certain costs associated with this rate case. In January 2017, the PUCT approved the settlement and no refund of interim rates was necessary. In April 2017, SPS filed a surcharge to recover $13.8 million for the additional revenue recovered by applying the final rates to customer billing units for the period of July 20, 2016 through Dec. 9, 2016.

Texas 2016 Transmission Cost Recovery Factor (TCRF) Application — In February 2017, SPS filed with the PUCT to recover additional annual revenue of approximately $16.1 million through its TCRF, or 1.8 percent. The filing is based upon capital transmission additions made during 2016. SPS expects a PUCT decision and implementation of TCRF rates by mid-2017.

Pending Regulatory Proceeding — New Mexico Public Regulation Commission (NMPRC)

New Mexico 2016 Electric Rate Case — In November 2016, SPS filed an electric rate case with the NMPRC seeking an increase in base rates of approximately $41.4 million, representing a total revenue increase of approximately 10.9 percent. The rate filing is based on a requested ROE of 10.1 percent, an equity ratio of 53.97 percent, an electric rate base of approximately $832 million and a future test year ending June 30, 2018.

SPS has excluded fuel and purchased power costs from base rates. This base rate case also takes into account the decline in sales of 380 MW in 2017 from certain wholesale customers and seeks to adjust the service life of SPS’ Tolk power plant to a remaining life through 2030 based on the investments to provide cooling water and the risks of investments in additional environmental controls.

The major components of the requested rate increase are summarized below:
(Millions of Dollars)
 
Request
Capital expenditures
 
$
20.1

Allocator changes, including wholesale load reductions
 
11.5

Transmission expense, net of revenue, including charges paid to Southwest Power Pool, Inc. (SPP) for construction of regionally shared transmission projects
 
4.7

Depreciation, including adjustment of service life for the Tolk generating station
 
3.6

Rate case expenses
 
1.1

Other, net
 
0.4

Requested rate increase
 
$
41.4


On April 10, 2017, the hearing examiner determined that SPS’ rate filing was deficient, and recommended the NMPRC extend the procedural schedule by one month and restart the suspension period once it is determined that the deficiencies are resolved. On April 19, 2017, the NMPRC ruled to dismiss SPS’ rate case and required SPS to refile a future test year rate case. SPS filed a motion for reconsideration on April 21, 2017 and the NMPRC is expected to consider that motion on May 10, 2017.

Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Midcontinent Independent System Operator, Inc. (MISO) ROE Complaints/ROE Adder — In November 2013, a group of customers filed a complaint at the FERC against MISO transmission owners (TOs), including NSP-Minnesota and NSP-Wisconsin. The complaint argued for a reduction in the ROE in transmission formula rates in the MISO region from 12.38 percent to 9.15 percent, a prohibition on capital structures in excess of 50 percent equity, and the removal of ROE adders (including those for Regional Transmission Organization (RTO) membership and for being an independent transmission company), effective Nov. 12, 2013.

In December 2015, an ALJ recommended the FERC approve a ROE of 10.32 percent using a FERC ROE methodology adopted in June 2014, which the FERC upheld in an order issued in September 2016. This ROE is applicable for the 15 month refund period from Nov. 12, 2013 to Feb. 11, 2015, and prospectively from the date of the FERC order. The total prospective ROE is 10.82 percent, which includes a 50 basis point adder for RTO membership.

13



In February 2015, a second complaint seeking to reduce the MISO ROE from 12.38 percent to 8.67 percent prior to any adder was filed with the FERC, resulting in a second period of potential refund from Feb. 12, 2015 to May 11, 2016. The MPUC, the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission and the Minnesota Department of Commerce joined a joint complainant/intervenor initial brief recommending an ROE of approximately 8.81 percent. FERC staff recommended a ROE of 8.78 percent. The MISO TOs recommended a ROE of 10.92 percent. In June 2016, the ALJ recommended a ROE of 9.7 percent, the midpoint of the upper half of the discounted cash flow (DCF) range, applying the June 2014 FERC ROE methodology. A decision was expected later in 2017, but could be delayed by the lack of a quorum at the FERC.

On April 14, 2017 the D.C. Circuit Court of Appeals vacated and remanded the June 2014 FERC decision, previously made in a New England ROE case. The court decision found that the FERC in that case had not established that the prior ROE was unjust and unreasonable, and that the FERC also failed to adequately support the newly approved ROE. The New England ROE ruling was then the basis for the ROE methodology used in the MISO complaint cases. The court found that the ROE methodology used in the New England ROE case was inadequate because it relied on approaches other than the DCF model. The impact of this court decision on the pending MISO complaint cases is uncertain.

As of March 2017, NSP-Minnesota has recognized a current liability for the Nov. 12, 2013 to Feb. 11, 2015 complaint period based on the 10.32 percent ROE provided in the FERC order. This liability is net of refunds processed during the first quarter of 2017. NSP-Minnesota has also recognized a current liability representing the best estimate of the final ROE for the Feb. 12, 2015 to May 11, 2016 complaint period.

Southwest Power Pool , Inc. (SPP) Open Access Transmission Tariff (OATT) Upgrade Costs — Under the SPP OATT, costs of participant-funded, or “sponsored,” transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade.  The SPP OATT has allowed SPP to collect charges since 2008, but SPP had not been charging its customers for these upgrades. 

In April 2016, SPP filed a request with the FERC for a waiver that would allow SPP to recover the charges not billed since 2008.  The FERC approved the request in July 2016.  SPS and certain other parties requested rehearing of the FERC order.  In November 2016, SPP billed SPS a net amount, for the period from 2008 through August 2016, of $12.8 million for these charges, to be paid over a five-year period commencing November 2016. In October 2016, SPS filed applications for deferred accounting and future recovery of related costs in Texas and New Mexico. In December 2016, SPS’ New Mexico application was consolidated with its base rate case and in March 2017, SPS withdrew its Texas application and will address the issue in its next base rate case. SPS anticipates these SPP charges authorized by FERC will be recoverable through regulatory mechanisms.

6.
Commitments and Contingencies

Except to the extent noted below and in Note 5 above, the circumstances set forth in Notes 12, 13 and 14 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2016, 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 Xcel Energy’s financial position.

PPAs

Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from independent power producing entities for which the utility subsidiaries are required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. These specific PPAs create a variable interest in the associated independent power producing entity.

The Xcel Energy utility subsidiaries had approximately 3,537 megawatts (MW) of capacity under long-term PPAs as of March 31, 2017 and Dec. 31, 2016, with entities that have been determined to be variable interest entities. Xcel Energy has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. These agreements have expiration dates through 2041.


14


Guarantees and Bond Indemnifications

Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities under specified agreements or transactions. The guarantees and bond indemnities issued by Xcel Energy Inc. guarantee payment or performance by its subsidiaries. As a result, Xcel Energy Inc.’s exposure under the guarantees and bond indemnities is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum guarantee or indemnity amount. As of March 31, 2017 and Dec. 31, 2016, Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements.

The following table presents guarantees and bond indemnities issued and outstanding for Xcel Energy:
(Millions of Dollars)
 
March 31, 2017
 
Dec. 31, 2016
Guarantees issued and outstanding
 
$
18.6

 
$
18.8

Current exposure under these guarantees
 
0.1

 
0.1

Bonds with indemnity protection
 
43.6

 
43.0


Other Indemnification Agreements

Xcel Energy Inc. and its subsidiaries provide indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold. Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. The maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated.

Environmental Contingencies

Ashland Manufactured Gas Plant (MGP) Site — NSP-Wisconsin has been named a potentially responsible party (PRP) for contamination at a site in Ashland, Wis. The Ashland/Northern States Power Lakefront Superfund Site (the Site) includes NSP-Wisconsin property, previously operated as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park); and an area of Lake Superior’s Chequamegon Bay adjoining the park.

In 2012, NSP-Wisconsin agreed to remediate the Phase I Project Area (which includes the Upper Bluff and Kreher Park areas of the Site), under a settlement agreement with the United States Environmental Protection Agency (EPA). The current cost estimate for the cleanup of the Phase I Project Area is approximately $77.2 million, of which approximately $57.2 million has been spent.

NSP-Wisconsin performed a wet dredge pilot study in 2016 and demonstrated that a wet dredge remedy can meet the performance standards for remediation of the Sediments. As a result, the EPA authorized NSP-Wisconsin to extend the wet dredge pilot to additional areas of the Site. In January 2017, NSP-Wisconsin agreed to remediate the Phase II Project Area (the Sediments), under a settlement agreement with the EPA. The settlement was approved by the U.S. District Court for the Western District of Wisconsin. NSP-Wisconsin has initiated field activities to perform a full scale wet dredge remedy of the Sediments in 2017, with performance of restoration activities in 2018.

At March 31, 2017 and Dec. 31, 2016, NSP-Wisconsin had recorded a total liability of $62.1 million and $64.3 million, respectively, for the entire site.

NSP-Wisconsin has deferred the unrecovered portion of the estimated Site remediation costs as a regulatory asset. The Public Service Commission of Wisconsin (PSCW) has consistently authorized NSP-Wisconsin rate recovery for all remediation costs incurred at the Site. In 2012, the PSCW agreed to allow NSP-Wisconsin to pre-collect certain costs, to amortize costs over a ten-year period and to apply a three percent carrying cost to the unamortized regulatory asset. In April 2016, NSP-Wisconsin filed a limited natural gas rate case for recovery of additional expenses associated with remediating the Site. In December 2016, the PSCW issued a written order approving the requested increase in annual recovery of MGP clean-up costs from $7.6 million in 2016 to $12.4 million in 2017.


15


Fargo, N.D. MGP Site — In May 2015, underground pipes, tars and impacted soils were discovered in a right-of-way in Fargo, N.D. that appeared to be associated with a former MGP operated by NSP-Minnesota or prior companies. NSP-Minnesota removed impacted soils and other materials from the right-of-way and commenced an investigation of the historic MGP and adjacent properties (the Fargo MGP Site). NSP-Minnesota has recommended that targeted source removal of impacted soils and historic MGP infrastructure should be performed. The North Dakota Department of Health approved NSP-Minnesota’s proposed cleanup plan in January 2017. The timing and final scope of remediation is dependent on whether current property owners will agree to provide reasonable access to NSP-Minnesota to perform and implement the approved cleanup plan.

NSP-Minnesota has initiated insurance recovery litigation in North Dakota. The U.S. District Court for the District of North Dakota agreed to the parties’ request for a stay of the litigation until May 2017.

As of March 31, 2017 and Dec. 31, 2016, NSP-Minnesota had recorded a liability of $11.1 million and $11.3 million, respectively, for the Fargo MGP Site. In December 2015, the NDPSC approved NSP-Minnesota’s request to defer costs associated with the Fargo MGP Site, resulting in deferral of all investigation and response costs with the exception of approximately 12 percent allocable to the Minnesota jurisdiction. Uncertainties related to the liability recognized include obtaining access to perform the approved remediation, final designs that will be developed to implement the approved cleanup plan and the potential for contributions from entities that may be identified as PRPs.

Other MGP and Landfill Sites — Xcel Energy is currently involved in investigating and/or remediating several other MGP and landfill sites. Xcel Energy has identified nine sites across its service territories in addition to the sites in Ashland, Wis. and Fargo, N.D., where former MGP or landfill disposal activities have or may have resulted in site contamination and are under current investigation and/or remediation. At some or all of these sites, there are other parties that may have responsibility for some portion of any remediation. Xcel Energy anticipates that the majority of the investigation or remediation at these sites will continue through at least 2018. Xcel Energy had accrued $2.9 million and $2.0 million for these sites at March 31, 2017 and Dec. 31, 2016, respectively. There may be insurance recovery and/or recovery from other PRPs to offset any costs incurred. Xcel Energy anticipates that any significant amounts incurred will be recovered from customers.

Environmental Requirements

Water and Waste
Federal Clean Water Act (CWA) Waters of the United States Rule In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) published a final rule that significantly 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. The executive order directs the agencies to consider interpreting the term “Waters of the U.S.” in a manner that is more narrow than the final rule. In March 2017, the EPA and the Corps published formal notice of the agencies’ intent to review the final rule and engage in further rulemaking.

16


Federal CWA Effluent Limitations Guidelines (ELG) In 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals.
 
Xcel Energy estimates that the capital cost to comply with the ELG rule for Colorado will range from $21 million to $32 million;
The estimated compliance cost for NSP-Minnesota’s Allen S. King Plant is approximately $10 million;
Xcel Energy continues to evaluate the cost of compliance at its other NSP-Minnesota and NSP-Wisconsin facilities potentially affected by this rule; and
The anticipated costs of compliance with the final rule at SPS are not expected to have a material impact on the results of operations, financial position or cash flows.

Xcel Energy believes that compliance costs would be recoverable through regulatory mechanisms. Consolidated challenges to the rule are being heard by the Fifth Circuit Court of Appeals.  On April 12, 2017, the EPA issued an administrative stay to delay the ELG rule’s compliance deadlines during the pendency of the ongoing litigation in order to give the agency the opportunity to reconsider and review the rule.

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. Parties in the litigation, who support the CPP, have filed briefs opposing the EPA’s motion. A court ruling on the EPA’s motion is expected in the second quarter of 2017.

Xcel Energy has undertaken a number of initiatives that reduce GHG emissions and respond to state renewable and energy efficiency goals.  The CPP could require additional emission reductions in states in which Xcel Energy operates.  If state plans do not provide credit for the investments Xcel Energy has already made to reduce GHG emissions, or if they require additional initiatives or emission reductions, then their requirements would potentially impose additional substantial costs.  Xcel Energy cannot predict the costs of compliance with the final rule once it takes effect due to the uncertainty about what, if anything, the final rules may require.  Xcel Energy believes compliance costs will be recoverable through regulatory mechanisms.  If Xcel Energy’s regulators do not allow recovery of all or a part of the cost of capital investment or the operating and maintenance (O&M) costs incurred to comply with the CPP or cost recovery is not provided in a timely manner, it could have a material impact on results of operations, financial position or cash flows.

Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. The Best Available Retrofit Technology (BART) requirements of the EPA’s regional haze rules require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. Under BART, regional haze plans identify facilities that will have to reduce Sulfur Dioxide (SO2), Nitrogen Oxide (NOx) and Particulate Matter (PM) emissions and set emission limits for those facilities. BART requirements can also be met through participation in interstate emission trading programs such as the Clean Air Interstate Rule (CAIR) and its successor, Cross-State Air Pollution Rule (CSAPR). The regional haze plans developed by Minnesota and Colorado have been fully approved and are being implemented in those states. States are required to revise their plans every ten years. The next plans for Minnesota and Colorado will be due in 2021. Texas’ first regional haze plan is still undergoing federal review as described below. President Trump’s Administration has not yet taken any public position regarding its views of the proposed and final regional haze regulations affecting SPS facilities in Texas. 


17


Actions affecting Harrington Units: Texas developed a State Implementation Plan (SIP) that finds the CAIR equal to BART for electric generating units (EGUs). As a result, no additional controls beyond CAIR compliance would be required. In 2014, the EPA proposed to approve the BART portion of the SIP, with substitution of CSAPR compliance for Texas’ reliance on CAIR. In January 2016, the EPA adopted a final rule that defers its approval of CSAPR compliance as BART until the EPA considers further adjustments to CSAPR emission budgets under the D.C. Circuit Court’s remand of the Texas SO2 emission budgets. In June 2016, the EPA issued a memorandum which allows Texas to voluntarily adopt the CSAPR emission budgets limiting annual SO2 and NOx emissions and rely on those emission budgets to satisfy Texas’ BART obligations under the regional haze rules. The Texas Commission on Environmental Quality (TCEQ) has not utilized this option. The EPA then published a proposed rule in January 2017 that could have the effect of requiring installation of dry scrubbers to reduce SO2 emissions from Harrington Units 1 and 2. Investment costs associated with dry scrubbers for Harrington Units 1 and 2 could be approximately $400 million. The EPA’s deadline to issue a final rule for Texas is September 2017.

Actions affecting Tolk units: In January 2016, the EPA adopted a final rule establishing a federal implementation plan for the state of Texas, which imposed SO2 emission limitations that reflect the installation of dry scrubbers on Tolk Units 1 and 2, with compliance required by February 2021. Investment costs associated with dry scrubbers could be approximately $600 million. SPS appealed the EPA’s decision and requested a stay of the final rule. The United States Court of Appeals for the Fifth Circuit (Fifth Circuit) granted the stay and decided that they are the appropriate venue for this case. In March 2017, the Fifth Circuit remanded the rule to the EPA for reconsideration, while leaving the stay in effect. The Fifth Circuit is now holding the case in abeyance until the EPA completes its reconsideration of the rule. It is likely that Texas and other affected entities including SPS would continue to challenge the determinations to date.  The risk of these controls being imposed along with the risk of investments to provide cooling water to Tolk have caused SPS to seek to decrease the remaining depreciable life of the Tolk units.

Legal Contingencies

Xcel Energy 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 Xcel Energy’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Employment, Tort and Commercial Litigation

Gas Trading Litigation — e prime, inc. (e prime) is a wholly owned subsidiary of Xcel Energy. e prime was in the business of natural gas trading and marketing, but has not engaged in natural gas trading or marketing activities since 2003.  Thirteen lawsuits were commenced against e prime and Xcel Energy (and NSP-Wisconsin, in two instances) between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices.

The cases were consolidated in U.S. District Court in Nevada. Five of the cases have since been settled and seven remain active, which include one multi-district litigation (MDL) matter consisting of a Colorado class (Breckenridge), a Wisconsin class (NSP-Wisconsin), a Kansas class, and two other cases identified as “Sinclair Oil” and “Farmland.” In November 2016, the MDL judge dismissed e prime and Xcel Energy from the Farmland lawsuit, and Farmland has appealed the dismissal. Motions for summary judgment were filed by defendants, including e prime, in all of the remaining lawsuits. In March 2017 the U.S. District Court issued an order dismissing the claims against e prime in the Sinclair lawsuit and denied plaintiffs motions for class certification in the other lawsuits. The U.S. District Court did not grant e prime’s summary judgment motions in the Wisconsin or Colorado cases. Xcel Energy, NSP-Wisconsin and e prime have concluded that a loss is remote.


18


Line Extension Disputes — In December 2015, Development Recovery Company (DRC) filed a lawsuit in Denver State Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric service agreements entered into by PSCo and various developers. The dispute involves assigned interests in those claims by over fifty developers. In May 2016, the district court granted PSCo’s motion to dismiss the lawsuit, concluding that jurisdiction over this dispute resides with the CPUC. In June 2016, DRC filed a notice of appeal. The matter has been fully briefed and plaintiff has requested oral arguments. 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 filed its brief in February 2017 and PSCo’s answer brief was filed in March 2017.

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. NSP-Wisconsin does not participate in the money pool. 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. The money pool balances are eliminated in consolidation.

Commercial Paper — Xcel Energy Inc. and its utility subsidiaries meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities. Commercial paper outstanding for Xcel Energy was as follows:
(Amounts in Millions, Except Interest Rates)
 
Three Months Ended  
 March 31, 2017
 
Year Ended  
 Dec. 31, 2016
Borrowing limit
 
$
2,750

 
$
2,750

Amount outstanding at period end
 
605

 
392

Average amount outstanding
 
557

 
485

Maximum amount outstanding
 
719

 
1,183

Weighted average interest rate, computed on a daily basis
 
0.97
%
 
0.74
%
Weighted average interest rate at period end
 
1.18

 
0.95


Letters of Credit — Xcel Energy Inc. and its subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At March 31, 2017 and Dec. 31, 2016, there were $16 million and $19 million, respectively, of letters of credit outstanding under the credit facilities. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

Credit Facilities — In order to use their commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper in an aggregate amount exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

19



At March 31, 2017, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available:
(Millions of Dollars)
 
Credit Facility (a)
 
Drawn (b)
 
Available
Xcel Energy Inc.
 
$
1,000

 
$
391

 
$
609

PSCo
 
700

 
34

 
666

NSP-Minnesota
 
500

 
47

 
453

SPS
 
400

 
116

 
284

NSP-Wisconsin
 
150

 
33

 
117

Total
 
$
2,750

 
$
621

 
$
2,129

(a) 
These credit facilities mature 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 respective credit facilities. Xcel Energy Inc. and its subsidiaries had no direct advances on the credit facilities outstanding at March 31, 2017 and Dec. 31, 2016.

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).

Investments in equity securities and other funds Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per-share market value. The investments in commingled funds may be redeemed for NAV with proper notice. Proper notice varies by fund and can range from daily with one or two days notice to annually with 90 days notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate investments may be redeemed with proper notice, which is typically quarterly with 45-90 days notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity.

Investments in debt securities Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.

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


20


Commodity derivatives The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2. When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.

Electric commodity derivatives held by NSP-Minnesota include transmission congestion instruments, generally referred to as financial transmission rights (FTRs), purchased from MISO. Electric commodity derivatives held by SPS include FTRs purchased from SPP. FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR. The valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Fair value measurements for FTRs have been assigned a Level 3 given the limited observability of management’s forecasts for several of the inputs to this complex valuation model. Non-trading monthly FTR settlements are included in fuel and purchased energy cost recovery mechanisms as applicable in each jurisdiction, and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs, the numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the consolidated financial statements of Xcel Energy.

Non-Derivative Instruments Fair Value Measurements

Nuclear Decommissioning Fund

The Nuclear Regulatory Commission (NRC) requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Together with all accumulated earnings or losses, the assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning the Monticello and Prairie Island (PI) nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other investments – all classified as available-for-sale. NSP-Minnesota plans to reinvest matured securities until decommissioning begins. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust.

NSP-Minnesota recognizes the costs of funding the decommissioning of its nuclear generating plants over the lives of the plants, assuming rate recovery of all costs. Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund, including any other-than-temporary impairments, are deferred as a component of the regulatory asset for nuclear decommissioning.

Unrealized gains for the nuclear decommissioning fund were $428.2 million and $378.6 million at March 31, 2017 and Dec. 31, 2016, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $31.7 million and $46.9 million at March 31, 2017 and Dec. 31, 2016, respectively.


21


The following tables present the cost and fair value of Xcel Energy’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund at March 31, 2017 and Dec. 31, 2016:
 
 
March 31, 2017
 
 
 
 
Fair Value
(Thousands of Dollars)
 
Cost
 
Level 1
 
Level 2
 
Level 3
 
Investments Measured at NAV (b)
 
Total
Nuclear decommissioning fund (a)
 
 
 
 
 
 
 
 
 
 
 
 
Cash equivalents
 
$
24,161

 
$
24,161

 
$

 
$

 
$

 
$
24,161

Commingled funds:
 
 
 
 
 
 
 
 
 
 
 
 
Non U.S. equities
 
272,437

 
178,990

 

 

 
98,876

 
277,866

Emerging market debt funds
 
94,772

 

 

 

 
101,269

 
101,269

Commodity funds
 
106,571

 

 

 

 
88,749

 
88,749

Private equity investments
 
137,176

 

 

 

 
194,912

 
194,912

Real estate
 
125,410

 

 

 

 
187,609

 
187,609

Other commingled funds
 
151,048

 

 

 

 
161,936

 
161,936

Debt securities:
 
 
 
 
 
 
 
 
 
 
 
 
Government securities
 
27,369

 

 
27,199

 

 

 
27,199

U.S. corporate bonds
 
127,841

 

 
128,799

 

 

 
128,799

Non U.S. corporate bonds
 
25,345

 

 
25,556

 

 

 
25,556

Municipal bonds
 
5

 

 
5

 

 

 
5

Equity securities:
 
 
 
 
 
 
 
 
 
 
 
 
U.S. equities
 
275,101

 
501,543

 

 

 

 
501,543

Non U.S. equities
 
188,763

 
232,851

 

 

 

 
232,851

Total
 
$
1,555,999

 
$
937,545

 
$
181,559

 
$

 
$
833,351

 
$
1,952,455

(a) 
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $131.9 million of equity investments in unconsolidated subsidiaries and $103.6 million of rabbi trust assets and miscellaneous investments.
(b) 
Due to limited availability of published pricing and a lack of immediate redeemability, certain fund investments measured at NAV are not required to be categorized within the fair value hierarchy.
 
 
Dec. 31, 2016
 
 
 
 
Fair Value
(Thousands of Dollars)
 
Cost
 
Level 1
 
Level 2
 
Level 3
 
Investments Measured at NAV (b)
 
Total
Nuclear decommissioning fund (a)
 
 
 
 
 
 
 
 
 
 
 
 
Cash equivalents
 
$
20,379

 
$
20,379

 
$

 
$

 
$

 
$
20,379

Commingled funds:
 
 
 
 
 
 
 
 
 
 
 
 
Non U.S. equities
 
260,877

 
133,126

 

 

 
112,233

 
245,359

Emerging market debt funds
 
93,597

 

 

 

 
97,543

 
97,543

Commodity funds
 
106,571

 

 

 

 
92,091

 
92,091

Private equity investments
 
132,190

 

 

 

 
190,462

 
190,462

Real estate
 
128,630

 

 

 

 
187,647

 
187,647

Other commingled funds
 
151,048

 

 

 

 
159,489

 
159,489

Debt securities:
 
 
 
 
 
 
 
 
 
 
 
 
Government securities
 
32,764

 

 
31,965

 

 

 
31,965

U.S. corporate bonds
 
104,913

 

 
105,772

 

 

 
105,772

Non U.S. corporate bonds
 
21,751

 

 
21,672

 

 

 
21,672

Municipal bonds
 
13,609

 

 
13,786

 

 

 
13,786

Mortgage-backed securities
 
2,785

 

 
2,816

 

 

 
2,816

Equity securities:
 
 
 
 
 
 
 
 
 
 
 
 
U.S. equities
 
270,779

 
473,400

 

 

 

 
473,400

Non U.S. equities
 
189,100

 
218,381

 

 

 

 
218,381

Total
 
$
1,528,993

 
$
845,286

 
$
176,011

 
$

 
$
839,465

 
$
1,860,762

(a) 
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $132.8 million of equity investments in unconsolidated subsidiaries and $98.3 million of rabbi trust assets and miscellaneous investments.
(b) 
Due to limited availability of published pricing and a lack of immediate redeemability, certain fund investments measured at NAV are not required to be categorized within the fair value hierarchy.
For the three months ended March 31, 2017 and 2016 there were no Level 3 nuclear decommissioning fund investments and no transfers of amounts between levels.

22



The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at March 31, 2017:
 
 
Final Contractual Maturity
(Thousands of Dollars)
 
Due in 1 Year
or Less
 
Due in 1 to 5
Years
 
Due in 5 to 10
Years
 
Due after 10
Years
 
Total
Government securities
 
$

 
$
1,100

 
$
3,017

 
$
23,082

 
$
27,199

U.S. corporate bonds
 
354

 
38,741

 
74,617

 
15,087

 
128,799

International corporate bonds
 

 
8,085

 
13,443

 
4,028

 
25,556

Municipal bonds
 

 

 
5

 

 
5

Debt securities
 
$
354

 
$
47,926

 
$
91,082

 
$
42,197

 
$
181,559


Rabbi Trusts

In June 2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of its supplemental executive retirement plan and deferred compensation plan. The following tables present the cost and fair value of the assets held in rabbi trusts at March 31, 2017 and Dec. 31, 2016:
 
 
March 31, 2017
 
 
 
 
Fair Value
(Thousands of Dollars)
 
Cost
 
Level 1
 
Level 2
 
Level 3
 
Total
Rabbi Trusts (a)
 
 
 
 
 
 
 
 
 
 
Cash equivalents
 
$
9,575

 
$
9,575

 
$

 
$

 
$
9,575

Mutual funds
 
39,965

 
40,264

 

 

 
40,264

Total
 
$
49,540

 
$
49,839

 
$

 
$

 
$
49,839


 
 
Dec. 31, 2016
 
 
 
 
Fair Value
(Thousands of Dollars)
 
Cost
 
Level 1
 
Level 2
 
Level 3
 
Total
Rabbi Trusts (a)
 
 
 
 
 
 
 
 
 
 
Cash equivalents
 
$
47,831

 
$
47,831

 
$

 
$

 
$
47,831

Mutual funds
 
1,663

 
1,901

 

 

 
1,901

Total
 
$
49,494

 
$
49,732

 
$

 
$

 
$
49,732

(a) 
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.

Derivative Instruments Fair Value Measurements

Xcel Energy 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 — Xcel Energy 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 March 31, 2017, accumulated other comprehensive losses related to interest rate derivatives included $3.1 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 — Xcel Energy Inc.’s utility subsidiaries conduct 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. Xcel Energy’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.


23


Commodity Derivatives — Xcel Energy 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, FTRs, vehicle fuel and weather derivatives.

Xcel Energy 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. Xcel Energy recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three months ended March 31, 2016.

Additionally, Xcel Energy 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, options and FTRs at March 31, 2017 and Dec. 31, 2016:
(Amounts in Thousands) (a)(b)
 
March 31, 2017
 
Dec. 31, 2016
Megawatt hours of electricity
 
31,838

 
46,773

Million British thermal units of natural gas
 
92,801

 
121,978

(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 March 31, 2017 and 2016, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:
 
 
Three Months Ended March 31, 2017
 
 
 
Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
 
Pre-Tax (Gains) 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
 
$

 
$

 
$
1,359

(a) 
$

 
$

 
Total
 
$

 
$

 
$
1,359

 
$

 
$

 
Other derivative instruments
 
 
 
 
 
 
 
 
 
 
 
Commodity trading
 
$

 
$

 
$

 
$

 
$
1,001

(c) 
Electric commodity
 

 
794

 

 
(3,998
)
(d) 

 
Natural gas commodity
 

 
(6,161
)
 

 
1,075

(e) 
(4,070
)
(e) 
Total
 
$

 
$
(5,367
)
 
$

 
$
(2,923
)
 
$
(3,069
)
 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

24


 
 
Three Months Ended March 31, 2016
 
 
 
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
 
$

 
$

 
$
1,485

(a) 
$

 
$

 
Vehicle fuel and other commodity
 
(6
)
 

 
57

(b) 

 

 
Total
 
$
(6
)
 
$

 
$
1,542

 
$

 
$

 
Other derivative instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity trading
 
$

 
$

 
$

 
$

 
$
1,009

(c) 
Electric commodity
 

 
(265
)
 

 
8,631

(d) 

 
Natural gas commodity
 

 
(2,702
)
 

 
11,666

(e) 
(5,024
)
(e) 
Total
 
$

 
$
(2,967
)
 
$

 
$
20,297

 
$
(4,015
)
 
(a) 
Amounts are recorded to interest charges.
(b) 
Amounts are recorded to O&M expenses.
(c) 
Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.
(d) 
Amounts are recorded to electric fuel and purchased power. These derivative settlement gain and loss amounts are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.
(e) 
Amounts for the three months ended March 31, 2017 included $0.9 million of settlement gains and an immaterial amount of settlement losses for the three months ended March 31, 2016 on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the three months ended March 31, 2017 and 2016 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate.

Xcel Energy had no derivative instruments designated as fair value hedges during the three months ended March 31, 2017 and 2016. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Consideration of Credit Risk and Concentrations — Xcel Energy 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 Xcel Energy’s own credit risk when determining the fair value of derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets.

Xcel Energy Inc. and its subsidiaries employ 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.

Xcel Energy’s utility subsidiaries’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to their wholesale, trading and non-trading commodity activities. At March 31, 2017, two of Xcel Energy’s 10 most significant counterparties for these activities, comprising $24.1 million or ten percent of this credit exposure, had investment grade credit ratings from S&P’s, Moody’s or Fitch Ratings. Eight of the 10 most significant counterparties, comprising $79.1 million or 34 percent of this credit exposure, were not rated by these external agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade. All ten of these significant counterparties are municipal or cooperative electric entities or other utilities.

Credit Related Contingent Features