UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended Sept. 30, 20162017
or
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¨ | 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)
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Minnesota | | 41-0448030 |
(State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
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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 or an emerging growth company. See the definitions of “large accelerated filer”,filer,” “accelerated filer”filer,” “smaller reporting company,” and “smaller reporting“emerging growth company” in Rule 12b-2 of the Exchange Act.
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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.
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Class | | Outstanding at October 24, 201623, 2017 |
Common Stock, $2.50 par value | | 507,952,795507,762,881 shares |
TABLE OF CONTENTS
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PART I | FINANCIAL INFORMATION | |
Item 1 — | | |
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Item 2 — | | |
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Item 3 — | | |
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Item 4 — | | |
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PART II | OTHER INFORMATION | |
Item 1 — | | |
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Item 1A — | | |
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Item 2 — | | |
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Item 4 — | | |
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Item 5 — | | |
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Item 6 — | | |
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| Certifications Pursuant to Section 302 | 1 |
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| Certifications Pursuant to Section 906 | 1 |
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| Statement Pursuant to Private Litigation | 1 |
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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)
| XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (amounts in thousands, except per share data)
| XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (amounts in thousands, except per share data)
|
| | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
| 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 | | 2017 | | 2016 |
Operating revenues | | | | | | | | | | | | | | |
Electric | $ | 2,799,964 |
| | $ | 2,667,480 |
| | $ | 7,209,225 |
| | $ | 7,105,803 |
| $ | 2,783,569 |
| | $ | 2,799,964 |
| | $ | 7,420,646 |
| | $ | 7,209,225 |
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Natural gas | 221,956 |
| | 216,019 |
| | 1,046,544 |
| | 1,216,146 |
| 214,253 |
| | 221,956 |
| | 1,129,795 |
| | 1,046,544 |
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Other | 18,227 |
| | 17,813 |
| | 56,500 |
| | 56,716 |
| 19,075 |
| | 18,227 |
| | 57,806 |
| | 56,500 |
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Total operating revenues | 3,040,147 |
| | 2,901,312 |
| | 8,312,269 |
| | 8,378,665 |
| 3,016,897 |
| | 3,040,147 |
| | 8,608,247 |
| | 8,312,269 |
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Operating expenses | | | | | | | | | | | | | | |
Electric fuel and purchased power | 1,037,263 |
| | 1,014,726 |
| | 2,755,083 |
| | 2,869,563 |
| 1,006,160 |
| | 1,037,263 |
| | 2,850,480 |
| | 2,755,083 |
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Cost of natural gas sold and transported | 67,566 |
| | 66,071 |
| | 469,754 |
| | 665,109 |
| 63,998 |
| | 67,566 |
| | 543,452 |
| | 469,754 |
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Cost of sales — other | 8,648 |
| | 8,203 |
| | 25,225 |
| | 26,416 |
| 8,451 |
| | 8,648 |
| | 25,216 |
| | 25,225 |
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Operating and maintenance expenses | 590,009 |
| | 565,984 |
| | 1,764,397 |
| | 1,746,093 |
| 541,539 |
| | 590,009 |
| | 1,706,102 |
| | 1,764,397 |
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Conservation and demand side management program expenses | 63,914 |
| | 57,314 |
| | 177,266 |
| | 165,260 |
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Conservation and demand side management expenses | | 73,728 |
| | 63,914 |
| | 206,121 |
| | 177,266 |
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Depreciation and amortization | 328,503 |
| | 280,121 |
| | 971,057 |
| | 827,821 |
| 371,091 |
| | 328,503 |
| | 1,102,015 |
| | 971,057 |
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Taxes (other than income taxes) | 117,190 |
| | 123,081 |
| | 400,982 |
| | 389,438 |
| 133,571 |
| | 117,190 |
| | 410,591 |
| | 400,982 |
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Loss on Monticello life cycle management/extended power uprate project | — |
| | — |
| | — |
| | 129,463 |
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Total operating expenses | 2,213,093 |
| | 2,115,500 |
| | 6,563,764 |
| | 6,819,163 |
| 2,198,538 |
| | 2,213,093 |
| | 6,843,977 |
| | 6,563,764 |
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Operating income | 827,054 |
| | 785,812 |
| | 1,748,505 |
| | 1,559,502 |
| 818,359 |
| | 827,054 |
| | 1,764,270 |
| | 1,748,505 |
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Other income, net | 578 |
| | 1,626 |
| | 6,388 |
| | 5,748 |
| 5,089 |
| | 578 |
| | 14,143 |
| | 6,388 |
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Equity earnings of unconsolidated subsidiaries | 9,701 |
| | 8,162 |
| | 32,500 |
| | 24,360 |
| 7,080 |
| | 9,701 |
| | 22,496 |
| | 32,500 |
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Allowance for funds used during construction — equity | 17,199 |
| | 15,427 |
| | 45,042 |
| | 40,728 |
| 23,483 |
| | 17,199 |
| | 54,182 |
| | 45,042 |
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Interest charges and financing costs | | | | | | | | | | | | | | |
Interest charges — includes other financing costs of $6,060 $6,260, $19,026 and $17,819, respectively | 165,857 |
| | 152,566 |
| | 485,280 |
| | 441,728 |
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Interest charges — includes other financing costs of $5,923, $6,060, $17,657 and $19,026, respectively | | 167,803 |
| | 165,857 |
| | 497,932 |
| | 485,280 |
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Allowance for funds used during construction — debt | (7,532 | ) | | (7,031 | ) | | (20,206 | ) | | (19,340 | ) | (10,724 | ) | | (7,532 | ) | | (25,359 | ) | | (20,206 | ) |
Total interest charges and financing costs | 158,325 |
| | 145,535 |
| | 465,074 |
| | 422,388 |
| 157,079 |
| | 158,325 |
| | 472,573 |
| | 465,074 |
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Income before income taxes | 696,207 |
| | 665,492 |
| | 1,367,361 |
| | 1,207,950 |
| 696,932 |
| | 696,207 |
| | 1,382,518 |
| | 1,367,361 |
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Income taxes | 238,412 |
| | 239,029 |
| | 471,459 |
| | 432,490 |
| 204,791 |
| | 238,412 |
| | 423,844 |
| | 471,459 |
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Net income | $ | 457,795 |
| | $ | 426,463 |
| | $ | 895,902 |
| | $ | 775,460 |
| $ | 492,141 |
| | $ | 457,795 |
| | $ | 958,674 |
| | $ | 895,902 |
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Weighted average common shares outstanding: | | | | | | | | | | | | | | |
Basic | 508,941 |
| | 508,031 |
| | 508,840 |
| | 507,585 |
| 508,581 |
| | 508,941 |
| | 508,468 |
| | 508,840 |
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Diluted | 509,566 |
| | 508,427 |
| | 509,396 |
| | 507,976 |
| 509,242 |
| | 509,566 |
| | 509,052 |
| | 509,396 |
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Earnings per average common share: | | | | | | | | | | | | | | |
Basic | $ | 0.90 |
| | $ | 0.84 |
| | $ | 1.76 |
| | $ | 1.53 |
| $ | 0.97 |
| | $ | 0.90 |
| | $ | 1.89 |
| | $ | 1.76 |
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Diluted | 0.90 |
| | 0.84 |
| | 1.76 |
| | 1.53 |
| 0.97 |
| | 0.90 |
| | 1.88 |
| | 1.76 |
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Cash dividends declared per common share | $ | 0.34 |
| | $ | 0.32 |
| | $ | 1.02 |
| | $ | 0.96 |
| $ | 0.36 |
| | $ | 0.34 |
| | $ | 1.08 |
| | $ | 1.02 |
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See Notes to Consolidated Financial Statements |
XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (amounts in thousands)
| XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (amounts in thousands)
| XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (amounts in thousands)
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| | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
| 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 | | 2017 | | 2016 |
Net income | $ | 457,795 |
| | $ | 426,463 |
| | $ | 895,902 |
| | $ | 775,460 |
| $ | 492,141 |
| | $ | 457,795 |
| | $ | 958,674 |
| | $ | 895,902 |
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Other comprehensive income | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Pension and retiree medical benefits: | | | | | | | | | | | | | | |
Amortization of losses included in net periodic benefit cost, net of tax of $536, $559, $1,635 and $1,689, respectively | 878 |
| | 884 |
| | 1,954 |
| | 2,643 |
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Amortization of losses included in net periodic benefit cost, net of tax of $582, $536, $1,805 and $1,635, respectively | | 982 |
| | 878 |
| | 2,886 |
| | 1,954 |
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Derivative instruments: | | | | | | | | | | | | | | |
Net fair value (decrease) increase, net of tax of $(2), $(28), $3 and $(24), respectively | (4 | ) | | (42 | ) | | 4 |
| | (35 | ) | |
Reclassification of losses to net income, net of tax of $588, $446, $1,786 and $1,210, respectively | 960 |
| | 706 |
| | 2,834 |
| | 1,891 |
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Net fair value increase (decrease), net of tax of $15, $(2), $32 and $3, respectively | | 23 |
| | (4 | ) | | 49 |
| | 4 |
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Reclassification of losses to net income, net of tax of $587, $588, $1,632 and $1,786, respectively | | 981 |
| | 960 |
| | 2,609 |
| | 2,834 |
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| 956 |
| | 664 |
| | 2,838 |
| | 1,856 |
| 1,004 |
| | 956 |
| | 2,658 |
| | 2,838 |
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Marketable securities: |
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Net fair value (decrease) increase, net of tax of $0, $0, $0 and $1, respectively | — |
| | (1 | ) | | — |
| | 1 |
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Net fair value increase, net of tax of $0, $0, $0 and $0, respectively | | — |
| | — |
| | 1 |
| | — |
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Other comprehensive income | 1,834 |
| | 1,547 |
| | 4,792 |
| | 4,500 |
| 1,986 |
| | 1,834 |
| | 5,545 |
| | 4,792 |
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Comprehensive income | $ | 459,629 |
| | $ | 428,010 |
| | $ | 900,694 |
| | $ | 779,960 |
| $ | 494,127 |
| | $ | 459,629 |
| | $ | 964,219 |
| | $ | 900,694 |
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See Notes to Consolidated Financial Statements |
XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (amounts in thousands) | XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (amounts in thousands) | XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (amounts in thousands) |
| | Nine Months Ended Sept. 30 | Nine Months Ended Sept. 30 |
| 2016 | | 2015 | 2017 | | 2016 |
Operating activities | | | | | | |
Net income | $ | 895,902 |
| | $ | 775,460 |
| $ | 958,674 |
| | $ | 895,902 |
|
Adjustments to reconcile net income to cash provided by operating activities: | | | | | | |
Depreciation and amortization | 982,682 |
| | 841,360 |
| 1,113,418 |
| | 982,682 |
|
Conservation and demand side management program amortization | 3,089 |
| | 4,063 |
| 1,927 |
| | 3,089 |
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Nuclear fuel amortization | 89,475 |
| | 82,627 |
| 87,654 |
| | 89,475 |
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Deferred income taxes | 479,100 |
| | 429,091 |
| 501,013 |
| | 479,100 |
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Amortization of investment tax credits | (3,920 | ) | | (4,151 | ) | (3,835 | ) | | (3,920 | ) |
Allowance for equity funds used during construction | (45,042 | ) | | (40,728 | ) | (54,182 | ) | | (45,042 | ) |
Equity earnings of unconsolidated subsidiaries | (32,500 | ) | | (24,360 | ) | (22,496 | ) | | (32,500 | ) |
Dividends from unconsolidated subsidiaries | 34,502 |
| | 29,434 |
| 32,316 |
| | 34,502 |
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Share-based compensation expense | 29,872 |
| | 29,765 |
| 44,239 |
| | 29,872 |
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Loss on Monticello life cycle management/extended power uprate project | — |
| | 129,463 |
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Net realized and unrealized hedging and derivative transactions | 3,307 |
| | 18,808 |
| (62 | ) | | 3,307 |
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Other | (266 | ) | | — |
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Other, net | | (2,577 | ) | | (266 | ) |
Changes in operating assets and liabilities: | | | | | | |
Accounts receivable | (29,585 | ) | | 85,276 |
| (31,337 | ) | | (29,585 | ) |
Accrued unbilled revenues | 87,015 |
| | 182,425 |
| 104,175 |
| | 87,015 |
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Inventories | (6,203 | ) | | (47,659 | ) | (9,158 | ) | | (6,203 | ) |
Other current assets | 80,566 |
| | 72,445 |
| 64,208 |
| | 80,566 |
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Accounts payable | 50,526 |
| | (116,137 | ) | (67,759 | ) | | 50,526 |
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Net regulatory assets and liabilities | 3,911 |
| | 116,068 |
| (26,556 | ) | | 3,911 |
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Other current liabilities | (76,011 | ) | | 60,293 |
| (111,512 | ) | | (63,524 | ) |
Pension and other employee benefit obligations | (96,350 | ) | | (82,013 | ) | (134,455 | ) | | (96,350 | ) |
Change in other noncurrent assets | (11,815 | ) | | 2,374 |
| (15,002 | ) | | (11,815 | ) |
Change in other noncurrent liabilities | (25,401 | ) | | (53,982 | ) | (61,513 | ) | | (25,401 | ) |
Net cash provided by operating activities | 2,412,854 |
| | 2,489,922 |
| 2,367,180 |
| | 2,425,341 |
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Investing activities | | | | | | |
Utility capital/construction expenditures | (2,186,483 | ) | | (2,186,369 | ) | (2,256,452 | ) | | (2,186,483 | ) |
Proceeds from insurance recoveries | 1,595 |
| | 27,237 |
| — |
| | 1,595 |
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Allowance for equity funds used during construction | 45,042 |
| | 40,728 |
| 54,182 |
| | 45,042 |
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Purchases of investment securities | (390,031 | ) | | (773,260 | ) | (971,469 | ) | | (390,031 | ) |
Proceeds from the sale of investment securities | 327,378 |
| | 753,924 |
| 948,558 |
| | 327,378 |
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Investments in WYCO Development LLC and other | (3,962 | ) | | (832 | ) | (7,616 | ) | | (3,962 | ) |
Other, net | 204 |
| | (676 | ) | (5,803 | ) | | 204 |
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Net cash used in investing activities | (2,206,257 | ) | | (2,139,248 | ) | (2,238,600 | ) | | (2,206,257 | ) |
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Financing activities | | | | | | |
Repayments of short-term borrowings, net | (480,000 | ) | | (955,500 | ) | |
Proceeds from issuance of long-term debt | 1,632,642 |
| | 1,627,190 |
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Repayments of long-term debt | (580,167 | ) | | (250,644 | ) | |
Proceeds from issuance of common stock | — |
| | 5,298 |
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Purchase of common stock for settlement of equity awards | (2,810 | ) | | — |
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Proceeds from (repayments of) short-term borrowings, net | | 122,000 |
| | (480,000 | ) |
Proceeds from issuances of long-term debt | | 1,422,163 |
| | 1,632,642 |
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Repayments of long-term debt, including reacquisition premiums | | (1,030,099 | ) | | (580,167 | ) |
Repurchases of common stock | | (2,943 | ) | | (2,810 | ) |
Dividends paid | (507,817 | ) | | (452,217 | ) | (538,045 | ) | | (507,817 | ) |
Net cash provided by (used in) financing activities | 61,848 |
| | (25,873 | ) | |
Other | | (18,291 | ) | | (12,487 | ) |
Net cash (used in) provided by financing activities | | (45,215 | ) | | 49,361 |
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Net change in cash and cash equivalents | 268,445 |
| | 324,801 |
| 83,365 |
| | 268,445 |
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Cash and cash equivalents at beginning of period | 84,940 |
| | 79,608 |
| 84,476 |
| | 84,940 |
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Cash and cash equivalents at end of period | $ | 353,385 |
| | $ | 404,409 |
| $ | 167,841 |
| | $ | 353,385 |
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Supplemental disclosure of cash flow information: | | | | | | |
Cash paid for interest (net of amounts capitalized) | $ | (461,302 | ) | | $ | (424,878 | ) | $ | (488,574 | ) | | $ | (461,302 | ) |
Cash received for income taxes, net | 61,245 |
| | 57,632 |
| 42,051 |
| | 61,245 |
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Supplemental disclosure of non-cash investing and financing transactions: | | | | | | |
Property, plant and equipment additions in accounts payable | $ | 221,155 |
| | $ | 284,864 |
| $ | 268,932 |
| | $ | 221,155 |
|
Issuance of common stock for reinvested dividends and equity awards | 17,527 |
| | 39,169 |
| |
Issuance of common stock for equity awards | | 23,394 |
| | 17,527 |
|
| | | | | | |
See Notes to Consolidated Financial Statements |
XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) (amounts in thousands, except share and per share data)
| XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) (amounts in thousands, except share and per share data)
| XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) (amounts in thousands, except share and per share data)
|
| | Sept. 30, 2016 | | Dec. 31, 2015 | Sept. 30, 2017 | | Dec. 31, 2016 |
Assets | | | | | | |
Current assets | | | | | | |
Cash and cash equivalents | $ | 353,385 |
| | $ | 84,940 |
| $ | 167,841 |
| | $ | 84,476 |
|
Accounts receivable, net | 754,248 |
| | 724,606 |
| 807,621 |
| | 776,289 |
|
Accrued unbilled revenues | 567,852 |
| | 654,867 |
| 625,657 |
| | 729,832 |
|
Inventories | 614,908 |
| | 608,584 |
| 616,675 |
| | 604,226 |
|
Regulatory assets | 317,611 |
| | 344,630 |
| 407,639 |
| | 363,655 |
|
Derivative instruments | 42,860 |
| | 33,842 |
| 74,533 |
| | 38,224 |
|
Deferred income taxes | 195,303 |
| | 140,219 |
| |
Prepaid taxes | 107,210 |
| | 163,023 |
| 55,788 |
| | 106,697 |
|
Prepayments and other | 122,786 |
| | 155,734 |
| 143,120 |
| | 138,682 |
|
Total current assets | 3,076,163 |
| | 2,910,445 |
| 2,898,874 |
| | 2,842,081 |
|
| | | | | | |
Property, plant and equipment, net | 32,206,696 |
| | 31,205,851 |
| 33,949,952 |
| | 32,841,750 |
|
| | | | | | |
Other assets | | | | | | |
Nuclear decommissioning fund and other investments | 2,048,455 |
| | 1,902,995 |
| 2,300,265 |
| | 2,091,858 |
|
Regulatory assets | 2,874,351 |
| | 2,858,741 |
| 3,011,462 |
| | 3,080,867 |
|
Derivative instruments | 51,369 |
| | 51,083 |
| 49,124 |
| | 50,189 |
|
Other | 67,716 |
| | 32,581 |
| 259,117 |
| | 248,532 |
|
Total other assets | 5,041,891 |
| | 4,845,400 |
| 5,619,968 |
| | 5,471,446 |
|
Total assets | $ | 40,324,750 |
| | $ | 38,961,696 |
| $ | 42,468,794 |
| | $ | 41,155,277 |
|
| | | | | | |
Liabilities and Equity | | | | | | |
Current liabilities | | | | | | |
Current portion of long-term debt | $ | 709,567 |
| | $ | 657,021 |
| $ | 305,415 |
| | $ | 255,529 |
|
Short-term debt | 366,000 |
| | 846,000 |
| 514,000 |
| | 392,000 |
|
Accounts payable | 916,534 |
| | 960,982 |
| 992,498 |
| | 1,044,959 |
|
Regulatory liabilities | 228,721 |
| | 306,830 |
| 256,191 |
| | 220,894 |
|
Taxes accrued | 422,437 |
| | 438,189 |
| 427,275 |
| | 457,392 |
|
Accrued interest | 155,005 |
| | 166,829 |
| 147,860 |
| | 172,901 |
|
Dividends payable | 172,704 |
| | 162,410 |
| 182,795 |
| | 172,456 |
|
Derivative instruments | 25,201 |
| | 29,839 |
| 27,659 |
| | 26,959 |
|
Other | 457,803 |
| | 490,197 |
| 486,713 |
| | 503,953 |
|
Total current liabilities | 3,453,972 |
| | 4,058,297 |
| 3,340,406 |
| | 3,247,043 |
|
| | | | | | |
Deferred credits and other liabilities | | | | | | |
Deferred income taxes | 6,851,873 |
| | 6,293,661 |
| 7,362,931 |
| | 6,784,319 |
|
Deferred investment tax credits | 64,499 |
| | 68,419 |
| 59,381 |
| | 63,216 |
|
Regulatory liabilities | 1,367,557 |
| | 1,332,889 |
| 1,358,558 |
| | 1,383,212 |
|
Asset retirement obligations | 2,703,396 |
| | 2,608,562 |
| 2,883,799 |
| | 2,782,229 |
|
Derivative instruments | 154,650 |
| | 168,311 |
| 131,058 |
| | 148,146 |
|
Customer advances | 216,978 |
| | 228,999 |
| 190,995 |
| | 195,214 |
|
Pension and employee benefit obligations | 843,739 |
| | 941,002 |
| 984,794 |
| | 1,112,366 |
|
Other | 277,561 |
| | 261,756 |
| 144,528 |
| | 223,965 |
|
Total deferred credits and other liabilities | 12,480,253 |
| | 11,903,599 |
| 13,116,044 |
| | 12,692,667 |
|
| | | | | | |
Commitments and contingencies |
|
| |
|
|
|
| |
|
|
Capitalization | | | | | | |
Long-term debt | 13,402,583 |
| | 12,398,880 |
| 14,572,967 |
| | 14,194,718 |
|
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 507,952,795 and 507,535,523 shares outstanding at Sept. 30, 2016 and Dec. 31, 2015, respectively | 1,269,882 |
| | 1,268,839 |
| |
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 507,762,881 and 507,222,795 shares outstanding at Sept. 30, 2017 and Dec. 31, 2016, respectively | | 1,269,407 |
| | 1,268,057 |
|
Additional paid in capital | 5,898,896 |
| | 5,889,106 |
| 5,888,729 |
| | 5,881,494 |
|
Retained earnings | 3,924,125 |
| | 3,552,728 |
| 4,386,050 |
| | 3,981,652 |
|
Accumulated other comprehensive loss | (104,961 | ) | | (109,753 | ) | (104,809 | ) | | (110,354 | ) |
Total common stockholders’ equity | 10,987,942 |
| | 10,600,920 |
| 11,439,377 |
| | 11,020,849 |
|
Total liabilities and equity | $ | 40,324,750 |
| | $ | 38,961,696 |
| $ | 42,468,794 |
| | $ | 41,155,277 |
|
| | | | | | |
See Notes to Consolidated Financial Statements |
XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED) (amounts in thousands)
| XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED) (amounts in thousands)
| 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 | Common Stock Issued | | Retained Earnings | | Accumulated Other Comprehensive Loss | | Total Common Stockholders’ Equity |
| Shares | | Par Value | | Additional Paid In Capital | | Shares | | Par Value | | Additional Paid In Capital | |
Three Months Ended Sept. 30, 2016 and 2015 | | | | | | | | | | | |
Balance at June 30, 2015 | 506,959 |
| | $ | 1,267,398 |
| | $ | 5,863,209 |
| | $ | 3,243,645 |
| | $ | (105,186 | ) | | $ | 10,269,066 |
| |
Net income |
|
| |
|
| |
|
| | 426,463 |
| |
|
| | 426,463 |
| |
Other comprehensive income |
|
| |
|
| |
|
| |
|
| | 1,547 |
| | 1,547 |
| |
Dividends declared on common stock |
|
| |
|
| |
|
| | (163,247 | ) | |
|
| | (163,247 | ) | |
Issuances of common stock | 308 |
| | 770 |
| | 8,665 |
| |
|
| |
|
| | 9,435 |
| |
Share-based compensation |
|
| |
|
| | 1,566 |
| |
|
| |
|
| | 1,566 |
| |
Balance at Sept. 30, 2015 | 507,267 |
| | $ | 1,268,168 |
| | $ | 5,873,440 |
| | $ | 3,506,861 |
| | $ | (103,639 | ) | | $ | 10,544,830 |
| |
| | | | | | | | | | | | |
Three Months Ended Sept. 30, 2017 and 2016 | | Three Months Ended Sept. 30, 2017 and 2016 | | | | | | | | | | |
Balance at June 30, 2016 | 507,953 |
| | $ | 1,269,882 |
| | $ | 5,896,394 |
| | $ | 3,643,653 |
| | $ | (106,795 | ) | | $ | 10,703,134 |
| 507,953 |
| | $ | 1,269,882 |
| | $ | 5,896,394 |
| | $ | 3,643,653 |
| | $ | (106,795 | ) | | $ | 10,703,134 |
|
Net income |
|
| |
|
| |
|
| | 457,795 |
| |
|
| | 457,795 |
|
|
| |
|
| |
|
| | 457,795 |
| |
|
| | 457,795 |
|
Other comprehensive income |
|
| |
|
| |
|
| |
|
| | 1,834 |
| | 1,834 |
|
|
| |
|
| |
|
| |
|
| | 1,834 |
| | 1,834 |
|
Dividends declared on common stock |
|
| |
|
| |
|
| | (173,786 | ) | |
|
| | (173,786 | ) |
|
| |
|
| |
|
| | (173,786 | ) | |
|
| | (173,786 | ) |
Issuances of common stock | 48 |
| | 120 |
| | — |
| |
|
| |
|
| | 120 |
| 48 |
| | 120 |
| | — |
| |
|
| |
|
| | 120 |
|
Purchase of common stock for settlement of equity awards | (48 | ) | | (120 | ) | | (2,021 | ) | |
|
| |
|
| | (2,141 | ) | |
Repurchases of common stock | | (48 | ) | | (120 | ) | | (2,021 | ) | |
|
| |
|
| | (2,141 | ) |
Share-based compensation |
|
| |
|
| | 4,523 |
| | (3,537 | ) | |
|
| | 986 |
|
|
| |
|
| | 4,523 |
| | (3,537 | ) | |
|
| | 986 |
|
Balance at Sept. 30, 2016 | 507,953 |
| | $ | 1,269,882 |
| | $ | 5,898,896 |
| | $ | 3,924,125 |
| | $ | (104,961 | ) | | $ | 10,987,942 |
| 507,953 |
| | $ | 1,269,882 |
| | $ | 5,898,896 |
| | $ | 3,924,125 |
| | $ | (104,961 | ) | | $ | 10,987,942 |
|
| | | | | | | | | | | | | | | | | | | | | | |
Balance at June 30, 2017 | | 507,763 |
| | $ | 1,269,407 |
| | $ | 5,881,475 |
| | $ | 4,079,068 |
| | $ | (106,795 | ) | | $ | 11,123,155 |
|
Net income | |
|
| |
|
| |
|
| | 492,141 |
| |
|
| | 492,141 |
|
Other comprehensive income | |
|
| |
|
| |
|
| |
|
| | 1,986 |
| | 1,986 |
|
Dividends declared on common stock | |
|
| |
|
| |
|
| | (184,061 | ) | |
|
| | (184,061 | ) |
Share-based compensation | |
|
| |
|
| | 7,254 |
| | (1,098 | ) | |
|
| | 6,156 |
|
Balance at Sept. 30, 2017 | | 507,763 |
| | $ | 1,269,407 |
| | $ | 5,888,729 |
| | $ | 4,386,050 |
| | $ | (104,809 | ) | | $ | 11,439,377 |
|
| | | | | | | | | | | | |
See Notes to Consolidated Financial Statements |
XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED) (Continued) (amounts in thousands)
| XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED) (Continued) (amounts in thousands)
| XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED) (Continued) (amounts in thousands) |
| | Common Stock Issued | | Retained Earnings | | Accumulated Other Comprehensive Loss | | Total Common Stockholders’ Equity | | | | | | | | | | | |
�� | Shares | | Par Value | | Additional Paid In Capital | | |
Nine Months Ended Sept. 30, 2016 and 2015 | | | | | | | | | | | |
Balance at Dec. 31, 2014 | 505,733 |
| | $ | 1,264,333 |
| | $ | 5,837,330 |
| | $ | 3,220,958 |
| | $ | (108,139 | ) | | $ | 10,214,482 |
| |
Net income | | | | | | | 775,460 |
| | | | 775,460 |
| |
Other comprehensive income | | | | | | | | | 4,500 |
| | 4,500 |
| |
Dividends declared on common stock | | | | | | | (489,557 | ) | | | | (489,557 | ) | |
Issuances of common stock | 1,534 |
| | 3,835 |
| | 18,874 |
| | | | | | 22,709 |
| |
Share-based compensation | | | | | 17,236 |
| | | | | | 17,236 |
| |
Balance at Sept. 30, 2015 | 507,267 |
| | $ | 1,268,168 |
| | $ | 5,873,440 |
| | $ | 3,506,861 |
| | $ | (103,639 | ) | | $ | 10,544,830 |
| |
| | | | | | | | | | | | Common Stock Issued | | Retained Earnings | | Accumulated Other Comprehensive Loss | | Total Common Stockholders’ Equity |
| | Shares | | Par Value | | Additional Paid In Capital | |
Nine Months Ended Sept. 30, 2017 and 2016 | | Nine Months Ended Sept. 30, 2017 and 2016 | | | | | | | | | | |
Balance at Dec. 31, 2015 | 507,536 |
| | $ | 1,268,839 |
| | $ | 5,889,106 |
| | $ | 3,552,728 |
| | $ | (109,753 | ) | | $ | 10,600,920 |
| 507,536 |
| | $ | 1,268,839 |
| | $ | 5,889,106 |
| | $ | 3,552,728 |
| | $ | (109,753 | ) | | $ | 10,600,920 |
|
Net income | | | | | | | 895,902 |
| | | | 895,902 |
| | | | | | | 895,902 |
| | | | 895,902 |
|
Other comprehensive income | | | | | | | | | 4,792 |
| | 4,792 |
| | | | | | | | | 4,792 |
| | 4,792 |
|
Dividends declared on common stock | | | | | | | (520,968 | ) | | | | (520,968 | ) | | | | | | | (520,968 | ) | | | | (520,968 | ) |
Issuances of common stock | 486 |
| | 1,216 |
| | 15,110 |
| | | | | | 16,326 |
| 486 |
| | 1,216 |
| | 15,110 |
| | | | | | 16,326 |
|
Purchase of common stock for settlement of equity awards | (69 | ) | | (173 | ) | | (2,810 | ) | | | | | | (2,983 | ) | |
Repurchases of common stock | | (69 | ) | | (173 | ) | | (2,810 | ) | | | | | | (2,983 | ) |
Share-based compensation | | | | | (2,510 | ) | | (3,537 | ) | | | | (6,047 | ) | | | | | (2,510 | ) | | (3,537 | ) | | | | (6,047 | ) |
Balance at Sept. 30, 2016 | 507,953 |
| | $ | 1,269,882 |
| | $ | 5,898,896 |
| | $ | 3,924,125 |
| | $ | (104,961 | ) | | $ | 10,987,942 |
| 507,953 |
| | $ | 1,269,882 |
| | $ | 5,898,896 |
| | $ | 3,924,125 |
| | $ | (104,961 | ) | | $ | 10,987,942 |
|
| | | | | | | | | | | | | | | | | | | | | | |
Balance at Dec. 31, 2016 | | 507,223 |
| | $ | 1,268,057 |
| | $ | 5,881,494 |
| | $ | 3,981,652 |
| | $ | (110,354 | ) | | $ | 11,020,849 |
|
Net income | | | | | | | | 958,674 |
| | | | 958,674 |
|
Other comprehensive income | | | | | | | | | | 5,545 |
| | 5,545 |
|
Dividends declared on common stock | | | | | | | | (551,614 | ) | | | | (551,614 | ) |
Issuances of common stock | | 611 |
| | 1,527 |
| | 3,510 |
| | | | | | 5,037 |
|
Repurchases of common stock | | (71 | ) | | (177 | ) | | (2,943 | ) | | | | | | (3,120 | ) |
Share-based compensation | | | | | | 6,668 |
| | (2,662 | ) | | | | 4,006 |
|
Balance at Sept. 30, 2017 | | 507,763 |
| | $ | 1,269,407 |
| | $ | 5,888,729 |
| | $ | 4,386,050 |
| | $ | (104,809 | ) | | $ | 11,439,377 |
|
| | | | | | | | | | | | |
See Notes to Consolidated Financial Statements |
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 Sept. 30, 20162017 and Dec. 31, 2015;2016; the results of its operations, including the components of net income and comprehensive income, and changes in stockholders’ equity for the three and nine months ended Sept. 30, 20162017 and 2015;2016; and its cash flows for the nine months ended Sept. 30, 20162017 and 2015.2016. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 20162017 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, 20152016 balance sheet information has been derived from the audited 20152016 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2015.2016. 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, 2015,2016, filed with the SEC on Feb. 19, 2016.24, 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, 2015,2016, 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, with the objective that recognized revenues properly reflect amounts an entity is entitled to receiverevenue. Xcel Energy expects its adoption will primarily result in exchange for goods and services. The new guidance also includes additional disclosure requirementsincreased disclosures regarding revenue cash flows and obligations related to arrangements with customers, as well as separate presentation of alternative revenue programs. Xcel Energy currently expects to implement the standard on a modified retrospective basis, which requires application to contracts with customers. The guidance iscustomers effective for interim and annual reporting periods beginning after Dec. 15, 2017. Xcel Energy is currently evaluatingJan. 1, 2018, with the impact of adopting ASU 2014-09 on its consolidated financial statements.
Presentation of Deferred Taxes — In November 2015, the FASB issued Balance Sheet Classification of Deferred Taxes, Topic 740 (ASU No 2015-17), which eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent on the balance sheet based on the classification of the related asset or liability, and instead requires classification of all deferred tax assets and liabilities as noncurrent. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. Other than the prescribed classification of all deferred tax assets and liabilities as noncurrent, Xcel Energy does not expect the implementation of ASU 2015-17 to have a materialcumulative impact on its consolidated financial statements.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 among other changes in accountingeliminates the available-for-sale classification for marketable equity securities and disclosure requirements,also replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes, and also eliminates the available-for-sale classification for marketable equity securities.changes. Under the new guidance,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 isexpects 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 evaluatingclassified as available-for-sale, will continue to be deferred to a regulatory asset, and that the impactoverall impacts of adopting ASU 2016-01 on its consolidated financial statements.the Jan. 1, 2018 adoption will not be material.
Leases — InIn 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 allmost leases. Additionally, for leases that qualify as finance leases, the guidance requires expense recognition consisting of amortization of the right-of-use asset as well as interest on the related lease liability using the effective interest method. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018, and early2018. Xcel Energy has not yet fully determined the impacts of implementation. However, adoption is permitted.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 is currently evaluatingexpects that similar agreements entered after Dec. 31, 2016 will generally qualify as leases under the impactnew standard, but has not yet completed its evaluation of adopting ASU 2016-02 on its consolidated financial statements.certain other contracts, including arrangements for the secondary use of assets, such as land easements.
Stock CompensationPresentation of Net Periodic Benefit Cost — InIn March 2016,2017, the FASB issued Improvements to Employee Share-Based Payment Accounting,Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 718715 (ASU 2016-09),No. 2017-07), which amends existingestablishes 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, to simplify several aspectsonly the service cost component of pension cost is eligible for capitalization. Xcel Energy 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 presentation for share-based payment transactions, includingthat the accounting for income taxes and forfeitures, as well as presentationimpacts of adoption will be limited to changes in classification of non-service costs in the consolidated statement of cash flows.income. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. Xcel Energy does not expect the implementation of ASU 2016-09 to have a material impact on its consolidated financial statements.2017.
Recently Adopted
ConsolidationStock Compensation — —I In February 2015,n March 2016, the FASB issued AmendmentsImprovements to the Consolidation Analysis,Employee Share-Based Payment Accounting, Topic 810718 (ASU No. 2015-02), which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. Xcel Energy implemented the guidance on Jan. 1, 2016, and other than the classification of certain real estate investments held within the Nuclear Decommissioning Trust as non-consolidated variable interest entities, the implementation did not have a significant impact on its consolidated financial statements.
Presentation of Debt Issuance Costs— In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which requires the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of presentation as an asset. Xcel Energy implemented the new guidance as required on Jan. 1, 2016, and as a result, $94.5 million of deferred debt issuance costs were presented as a deduction from the carrying amount of long-term debt on the consolidated balance sheet as of March 31, 2016, and $91.8 million of such deferred costs were retrospectively reclassified from other non-current assets to long-term debt on the consolidated balance sheet as of Dec. 31, 2015.
Fair Value Measurement— In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07)2016-09), which eliminatessimplifies accounting and financial statement presentation for share-based payment transactions. The guidance requires that the requirementdifference 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 categorize fair value measurements using a net asset value (NAV) methodologyincome 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 fair value hierarchy. Xcel Energy implementedconsolidated statements of cash flows for the guidance on Jan. 1,years ended Dec. 31, 2016, 2015 and the implementation did not have a material impact on its consolidated financial statements. For related disclosures, see Note 8 to the consolidated financial statements.2014.
| |
3. | Selected Balance Sheet Data |
| | (Thousands of Dollars) | | Sept. 30, 2016 | | Dec. 31, 2015 | | Sept. 30, 2017 | | Dec. 31, 2016 |
Accounts receivable, net | | | | | | | | |
Accounts receivable | | $ | 802,827 |
| | $ | 776,494 |
| | $ | 859,242 |
| | $ | 827,112 |
|
Less allowance for bad debts | | (48,579 | ) | | (51,888 | ) | | (51,621 | ) | | (50,823 | ) |
| | $ | 754,248 |
| | $ | 724,606 |
| | $ | 807,621 |
| | $ | 776,289 |
|
|
| | | | | | | | |
(Thousands of Dollars) | | Sept. 30, 2016 | | Dec. 31, 2015 |
Inventories | | | | |
Materials and supplies | | $ | 306,544 |
| | $ | 290,690 |
|
Fuel | | 181,265 |
| | 202,271 |
|
Natural gas | | 127,099 |
| | 115,623 |
|
| | $ | 614,908 |
| | $ | 608,584 |
|
|
| | | | | | | | |
(Thousands of Dollars) | | Sept. 30, 2017 | | Dec. 31, 2016 |
Inventories | | | | |
Materials and supplies | | $ | 320,195 |
| | $ | 312,430 |
|
Fuel | | 166,173 |
| | 181,752 |
|
Natural gas | | 130,307 |
| | 110,044 |
|
| | $ | 616,675 |
| | $ | 604,226 |
|
| | (Thousands of Dollars) | | Sept. 30, 2016 | | Dec. 31, 2015 | | Sept. 30, 2017 | | Dec. 31, 2016 |
Property, plant and equipment, net | | | | | | | | |
Electric plant | | $ | 37,335,785 |
| | $ | 36,464,050 |
| | $ | 39,067,098 |
| | $ | 38,220,765 |
|
Natural gas plant | | 5,149,959 |
| | 4,944,757 |
| | 5,563,536 |
| | 5,317,717 |
|
Common and other property | | 1,741,615 |
| | 1,709,508 |
| | 2,028,743 |
| | 1,888,518 |
|
Plant to be retired (a) | | 36,852 |
| | 38,249 |
| | 11,412 |
| | 31,839 |
|
Construction work in progress | | 1,844,525 |
| | 1,256,949 |
| | 1,861,576 |
| | 1,373,380 |
|
Total property, plant and equipment | | 46,108,736 |
| | 44,413,513 |
| | 48,532,365 |
| | 46,832,219 |
|
Less accumulated depreciation | | (14,218,683 | ) | | (13,591,259 | ) | | (14,982,709 | ) | | (14,381,603 | ) |
Nuclear fuel | | 2,469,772 |
| | 2,447,251 |
| | 2,668,586 |
| | 2,571,770 |
|
Less accumulated amortization | | (2,153,129 | ) | | (2,063,654 | ) | | (2,268,290 | ) | | (2,180,636 | ) |
| | $ | 32,206,696 |
| | $ | 31,205,851 |
| | $ | 33,949,952 |
| | $ | 32,841,750 |
|
| |
(a) | In the third 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. |
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, 20152016 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 AuditAudits — Xcel Energy files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2009 through 2011 and 2012 through 2013 federal income tax returns, following extensions, expires in June 2018 and October 2018, respectively.
In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of Sept. 30, 2016, theThe IRS had proposed an adjustment to the federal tax loss carryback claims that would resulthave resulted in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 and 2014 claims and the anticipated claim for 2015.through 2015 claims. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). In 2016the third quarter of 2017, Xcel Energy and Appeals reached an agreement and the benefit related to the agreed upon portions was recognized.
In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the third quarter of 2017, the IRS concluded the audit teamof tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s net operating loss (NOL) and effective tax rate (ETR). After evaluating the proposed adjustment, Xcel Energy presented their casesfiled a protest with the IRS. Xcel Energy anticipates the issue will be forwarded to Appeals; however, the outcome and timingAppeals. As 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 June 2017.Sept. 30, 2017, Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the IRS’s proposed adjustmentoutcome and timing of the carryback claims. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of Sept. 30, 2016, the IRS had not proposed any material adjustments to tax years 2012 and 2013.a resolution is unknown.
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 Sept. 30, 2016,2017, 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 February 2016, Texas began an audit of years 2009 and 2010. As of Sept. 30, 2016, Texas had not proposed any adjustments.
In June 2016, Minnesota began an audit of years 2010 through 2014. As of Sept. 30, 2016,2017, Minnesota had not proposed any adjustments.
material adjustments;
In August2016, Texas began an audit of years 2009 and 2010, and, in September 2017, began an audit of 2011. As of Sept. 30, 2017, Texas had not proposed any material adjustments;
In 2016, Wisconsin began an audit of years 2012 and 2013. As of Sept. 30, 2016,2017, Wisconsin had not proposed any adjustments. material adjustments; and
As of Sept. 30, 2016,2017, 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 effective tax rate (ETR).ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.
A reconciliation of the amount of unrecognized tax benefit is as follows:
| | (Millions of Dollars) | | Sept. 30, 2016 | | Dec. 31, 2015 | | Sept. 30, 2017 | | Dec. 31, 2016 |
Unrecognized tax benefit — Permanent tax positions | | $ | 27.7 |
| | $ | 25.8 |
| | $ | 20.6 |
| | $ | 29.6 |
|
Unrecognized tax benefit — Temporary tax positions | | 103.1 |
| | 94.9 |
| | 22.2 |
| | 104.1 |
|
Total unrecognized tax benefit | | $ | 130.8 |
| | $ | 120.7 |
| | $ | 42.8 |
| | $ | 133.7 |
|
The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL)NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:
| | (Millions of Dollars) | | Sept. 30, 2016 | | Dec. 31, 2015 | | Sept. 30, 2017 | | Dec. 31, 2016 |
NOL and tax credit carryforwards | | $ | (42.1 | ) | | $ | (36.7 | ) | | $ | (29.2 | ) | | $ | (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 progresses and audit progress,audits resume, 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 $58$19 million.
The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payablesA reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits at Sept. 30, 2016 and Dec. 31, 2015 were not material. are as follows:
|
| | | | | | | | |
(Millions of Dollars) | | Sept. 30, 2017 | | Dec. 31, 2016 |
Payable for interest related to unrecognized tax benefits at beginning of period | | $ | (3.4 | ) | | $ | (0.1 | ) |
Interest income (expense) related to unrecognized tax benefits recorded during the period | | 1.9 |
| | (3.3 | ) |
Payable for interest related to unrecognized tax benefits at end of period | | $ | (1.5 | ) | | $ | (3.4 | ) |
No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 20162017 or Dec. 31, 2015.2016.
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, 20152016 and in Note 5 to Xcel Energy Inc.’s Quarterly ReportsReport on
Form 10-Q for the quarterly periods ended March 31, 20162017 and June 30, 2016,2017, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.
NSP-Minnesota
Pending and Recently Concluded Regulatory Proceedings — 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. 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 |
|
In December 2015,June 2017, the MPUC approved interim rates for 2016.
Settlement Agreement
In August 2016,issued a written order. NSP-Minnesota reached a settlement withestimated the Minnesota Department of Commerce (DOC), Xcel Large Industrials,total rate increase to be approximately $245 million over the Minnesota Chamber of Commerce, the Commercial Group, the Suburban Rate Authority, the City of Minneapolis, the Industrial, Commercial, and Institutional Group, and the Energy CENTS Coalition, which resolves all revenue requirement issues in dispute. The settlement agreement requires the approval of the MPUC.
four-year period covering 2016-2019.
Key terms of the settlement are listed below:terms:
The agreement reflects a four-yearFour-year period covering 2016-2019;
The stated revenue increases in the table below are based on the DOC’s sales forecast;
Annual sales true-up with decoupling subject to weather-normalized actuals all years, all classes:
2016 weather-normalized actuals used to set final 2016 rates, no cap;
2016-2019 full decoupling for decoupled classes (residential, non-demand metered commercial) witha 3 percent cap; and
2017-2019 annual true-up for non-decoupled classes with 3 percent cap.
An ROEReturn on equity (ROE) of 9.2 percent and an equity ratio of 52.5 percent;
The nuclearNuclear related costs in this rate case will not be considered provisional;
Continued use of all existing riders, during the four-year term, however no new riders or legislative additions wouldmay be utilized during the four-year term;
Deferral of incremental 2016 property tax expense above a fixed threshold to 2018 and 2019; and
A four-year stay outFour-year stay-out provision for rate cases.cases;
Compliance steps recommended by the settling parties to implement the settlement:
A propertyProperty tax true-up mechanism for 2017-2019; and
A capitalCapital expenditure true-up mechanism for 2016-2019.
|
| | | | | | | | | | | | | | | | | | | | |
(Millions of Dollars, incremental) | | 2016 | | 2017 | | 2018 | | 2019 | | Total |
Settlement revenues (a) | | $ | 74.99 |
| | $ | 59.86 |
| | $ | — |
| | $ | 50.12 |
| | $ | 184.97 |
|
NSP-Minnesota’s sales forecast (b) | | 37.40 |
| | — |
| | — |
| | — |
| | 37.40 |
|
Total rate impact | | $ | 112.39 |
| | $ | 59.86 |
| | $ | — |
| | $ | 50.12 |
| | $ | 222.37 |
|
| |
(a)
| The settlement revenue increase reflects an increase of 2.47 percent in 2016; 1.97 percent in 2017; 0 percent in 2018 and 1.65 percent in 2019. |
| |
(b)
| The table reflects the estimated rate impact of this agreement, using NSP-Minnesota’s original sales forecast as filed in the Minnesota rate case. The settlement agreement includes a provision to true-up estimated sales to the actual sales for 2016. |
The revised schedule for the Minnesota rate case is listed below: |
| | | | | | | | | | | | | | | | | | | | |
(Millions of Dollars, Incremental) | | 2016 | | 2017 | | 2018 | | 2019 | | Total |
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 |
|
Administrative law judge (ALJ) report — March 3, 2017; and
MPUC decision — June 2017.12
A current liability that is consistent with the settlement and represents NSP-Minnesota’s best estimate of a refund obligation for 2016 associated with interim rates was recorded as of Sept. 30, 2016.
NSP-Minnesota – Gas Utility Infrastructure Costs (GUIC) Rider —In August 2016,September 2017, the MPUC approved NSP-Minnesota’s requestordered NSP-Minnesota to recovercollect final rates beginning March 1, 2017 (requested date was Jan. 1, 2017). As a result, NSP-Minnesota estimates the adjusted total rate increase to be approximately $15.5$240 million in natural gas infrastructure costs throughover the GUIC Rider, based on NSP-Minnesota’s proposed capital structure and a ROE of 9.64 percent. Recovery was approved for the 15-monthfour-year period from January 2016 to March 2017.covering 2016-2019.
Annual Automatic Adjustment (AAA) of Fuel Clause Charges — — In June 2016,May 2017, the DOCMPUC voted to disallow approximately $4.4 million of replacement energy costs for the Prairie Island (PI) nuclear facility outages allocated to the Minnesota jurisdiction in 2015. This disallowance was recognized in the second quarter of 2017. In September 2017, the Minnesota Department of Commerce (DOC) recommended the MPUC should hold utilities responsible for incremental costs of replacement power incurred due to unplanned outages at nuclear facilities under certain circumstances. The DOC’s recommendation could impact replacement power cost recovery forIn addition, the Prairie Island (PI)DOC is continuing its review of nuclear facility outages allocated tocosts and operations focusing on PI under the Minnesota jurisdiction duringinitial rate case and resource plan orders as well as the AAA fiscal year ended June 30, 2015. NSP-Minnesota expects a MPUC decision in mid-2017.recently finalized rate case.
NSP-Wisconsin
Pending Regulatory Proceeding — Public Service Commission of Wisconsin (PSCW)
Nuclear Project Prudence InvestigationWisconsin 2018 Electric and Natural Gas Rate Case— In May 2017, NSP-Wisconsin filed a request with the PSCW to increase electric rates by $24.7 million, or 3.6 percent, and natural gas rates by $12.0 million, or 10.1 percent, effective Jan. 1, 2018. The rate filing is based on a 2018 forecast test year, a ROE of 10.0 percent, an equity ratio of 52.53 percent and a forecasted rate base of approximately $1.2 billion for the electric utility and $138.4 million for the natural gas utility.
In September 2017, the PSCW Staff and the intervenors filed testimony. The PSCW Staff recommended an electric rate increase of $10.9 million, or 1.6 percent, and a natural gas rate increase of $9.9 million, or 8.3 percent, based on a ROE of 9.8 percent and an equity ratio of 51.45 percent.
A PSCW decision is anticipated in December 2017 with new rates effective in January 2018.
PSCo
Pending Regulatory Proceedings — Colorado Public Utilities Commission (CPUC)
Colorado 2017 Multi-Year Electric Rate Case — In 2013, NSP-Minnesota completedOctober 2017, PSCo filed a multi-year request with the Monticello life cycle management (LCM)/extended power uprate (EPU) project.CPUC seeking to increase electric rates approximately $245 million over four years. The multi-year project extended the liferequest, summarized below, is based on forecast test years (FTY) ending Dec. 31, a 10.0 percent ROE and an equity ratio of the facility55.25 percent.
|
| | | | | | | | | | | | | | | | | | | | |
Revenue Request (Millions of Dollars) | | 2018 | | 2019 | | 2020 | | 2021 | | Total |
Revenue request | | $ | 74.6 |
| | $ | 74.9 |
| | $ | 59.7 |
| | $ | 35.7 |
| | $ | 244.9 |
|
Clean Air Clean Jobs Act (CACJA) revenue conversion to base rates (a) | | 90.4 |
| | — |
| | — |
| | — |
| | 90.4 |
|
Transmission Cost Adjustment (TCA) revenue conversion to base rates (a) | | 42.7 |
| | — |
| | — |
| | — |
| | 42.7 |
|
Total (b) | | $ | 207.7 |
| | $ | 74.9 |
| | $ | 59.7 |
| | $ | 35.7 |
| | $ | 378.0 |
|
| | | | | | | | | | |
Expected year-end rate base (billions of dollars) (b) | | $ | 6.8 |
| | $ | 7.1 |
| | $ | 7.3 |
| | $ | 7.4 |
| | |
| |
(a) | The roll-in of each of the TCA and CACJA rider revenues into base rates will not have an impact on total customer bills or total revenue as these costs are already being recovered through a rider. Transmission investments for 2019 through 2021 will be recovered through the TCA rider. |
| |
(b) | This base rate request does not include the impacts associated with the renewable energy standard adjustment and retail electric commodity adjustment for the Rush Creek wind investments or any impacts of the proposed Colorado Energy Plan. |
Final rates are expected to be effective in June 2018. PSCo also proposed a stay-out provision and increased the capacity from 600 to 671 megawatts (MW) in 2015. The Monticello LCM/EPU project expenditures were approximately $665 million. Total capitalized costs were approximately $748 million, which includes allowance for funds used during construction (AFUDC). In 2008, project expenditures were initially estimated at approximately $320 million, excluding AFUDC.
earnings test through 2021.
In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent. In March 2015, the MPUC voted to allow for full recovery, including a return, on $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment over the remaining life of the plant. As a result of these determinations, Xcel Energy recorded an estimated pre-tax loss of $129 million in the first quarter of 2015, after which the remaining book value of the Monticello project represented the present value of the estimated future cash flows.
NSP-Wisconsin
Pending Regulatory Proceedings — Public Service Commission of Wisconsin (PSCW)
WisconsinColorado 2017 Electric andMulti-Year Natural Gas Rate Case — In April 2016, NSP-WisconsinJune 2017, PSCo filed a multi-year request with the PSCW for anCPUC seeking to increase in annual electric rates of $17.4 million, or 2.4 percent, and an increase inretail natural gas rates by $4.8approximately $139 million or 3.9 percent, effective January 2017.
over three years. The electric rate request, detailed below, is for the limited purpose of recovering increases in (1) generation and transmission fixed charges and fuel and purchased power expenses related to the interchange agreement with NSP-Minnesota, and (2) costs associated with forecasted average rate base of $1.188 billion in 2017.
The natural gas rate request is for the limited purpose of recovering expenses related to the ongoing environmental remediation ofbased on FTYs, a former manufactured gas plant (MGP) site and adjacent area in Ashland, Wis.
No changes are being requested to the capital structure or the 10.0 percent ROE authorized by the PSCW in the 2016 rate case. As partand an equity ratio of an agreement with stakeholders to limit the size and scope of the case, NSP-Wisconsin also agreed to an earnings cap, solely for 2017, in which 100 percent of the earnings in excess of the authorized ROE would be refunded to customers.
In August 2016, the PSCW Staff (Staff) and the intervenors filed their direct testimony in the case. The Staff recommended an electric rate increase of $19.5 million, or 2.7 percent and a natural gas rate increase of $4.8 million, or 3.955.25 percent. The Staff adjustments reflect revisions to previously forecasted rate base as well as fuel and purchased power expense. The Staff’s recommended rate increase also encompasses the PSCW’s July 2016 decision to remove the $9.5 million fuel refund credit from the rate case and refund that amount directly to customers in 2016. Adjusting for the treatment of the fuel refund, the Staff’s recommendation is $7.4 million less than NSP-Wisconsin’s request.
On Oct. 26, 2016, the PSCW verbally approved an electric rate increase of approximately $22.5 million, or 3.2 percent, and a natural gas rate increase of $4.8 million, or 3.9 percent. The difference between the Staff’s recommendation and the PSCW’s approved electric increase is attributable to an increase in forecasted fuel and purchased power expense. Consistent with long-standing PSCW policy, these costs were updated prior to the PSCW’s decision to reflect current market forecasts. The PSCW approved NSP-Wisconsin’s requested natural gas rate increase consistent with the Staff’s recommendation.
The major components of the retail electric rate increase, the Staff’s recommendation, and the PSCW’s approval are summarized below:
|
| | | | | | | | | | | | |
Electric Rate Request (Millions of Dollars) | | NSP-Wisconsin Request | | Staff Recommendation | | Final Decision |
Rate base investments | | $ | 11.0 |
| | $ | 7.6 |
| | 7.6 |
|
Generation and transmission expenses (excluding fuel and purchased power) (a) | | 6.8 |
| | 6.1 |
| | 6.1 |
|
Fuel and purchased power expenses | | 11.0 |
| | 7.7 |
| | 10.7 |
|
Subtotal | | 28.8 |
| | 21.4 |
| | 24.4 |
|
2015 fuel refund (b) | | (9.5 | ) | | — |
| | — |
|
Department of Energy settlement refund | | (1.9 | ) | | (1.9 | ) | | (1.9 | ) |
Total electric rate increase | | $ | 17.4 |
| | $ | 19.5 |
| | $ | 22.5 |
|
|
| | | | | | | | | | | | | | | | |
Revenue Request (Millions of Dollars) | | 2018 | | 2019 | | 2020 | | Total |
Revenue request | | $ | 63.2 |
| | $ | 32.9 |
| | $ | 42.9 |
| | $ | 139.0 |
|
Pipeline System Integrity Adjustment (PSIA) revenue conversion to base rates (a) | | — |
| | 93.9 |
| | — |
| | 93.9 |
|
Total | | $ | 63.2 |
| | $ | 126.8 |
| | $ | 42.9 |
| | $ | 232.9 |
|
| | | | | | | | |
Expected year-end rate base (billions of dollars) (b) | | $ | 1.5 |
| | $ | 2.3 |
| | $ | 2.4 |
| |
|
|
| |
(a) | The roll-in of PSIA rider revenue into base rates will not have an impact on customer bills or total revenue as these costs are already being recovered through the rider. PSCo plans to request new PSIA rates for 2018 in November 2017. The recovery of incremental PSIA related investments in 2019 and 2020 are included in the base rate request. |
| |
(a)(b)
| Includes Interchange Agreement billings. The Interchange Agreement is a Federal Energy Regulatory Commission (FERC) tariff under which NSP-Wisconsin and its affiliate, NSP-Minnesota, own and operate a single integrated electric generation and transmission system and both companies pay a pro-rata shareadditional rate base in 2019 predominantly reflects the roll-in of system capital and operating costs. For financial reporting purposes, these expenses are included in operating and maintenance (O&M). |
| |
(b)
| In July 2016, the PSCW required NSP-Wisconsin to return the 2015 fuel refund directly to customers, rather than using it to offset the proposed 2017 rate increase, as originally proposed by NSP-Wisconsin. This decision, when combinedassociated with the increase in forecasted fuel and purchased power expense, effectively increases NSP-Wisconsin’s requested electric rate increase to $29.9 million, or 4.2 percent.PSIA rider. |
In October 2017, several parties filed answer testimony. The CPUC Staff (Staff) and the Office of Consumer Counsel (OCC), recommended a single 2016 historic test year (HTY), based on an average 13-month rate base, and opposed a multi-year plan (MYP). The Staff and OCC recommended an equity capital structure of 48.73 percent and 51.2 percent, respectively. Both the Staff and the OCC recommended the existing PSIA rider expire with the 2018 rates rolled into base rates beginning Jan. 1, 2019. Planned investments in 2019 and 2020 would be recoverable through base rates, subject to a future rate case.
The following represents adjustments to PSCo’s filed request made by Staff and OCC for 2018:
|
| | | | | | | | |
(Millions of Dollars) | | Staff | | OCC |
Filed 2018 new revenue request | | $ | 63.2 |
| | $ | 63.2 |
|
Impact of the change in test year | | 4.4 |
| | 4.4 |
|
PSCo’s filed 2016 HTY | | $ | 67.6 |
| | $ | 67.6 |
|
| | | | |
Recommended adjustments: | | | | |
ROE (9.0 percent) | | (13.5 | ) | | (13.5 | ) |
Capital structure and cost of debt | | (10.2 | ) | | (7.5 | ) |
Change in amortization period | | (5.4 | ) | | — |
|
Prepaid pension and retiree medical assets | | (5.2 | ) | | — |
|
Change from 2016 year end to average rate base | | (4.8 | ) | | (4.8 | ) |
Other, net | | (5.0 | ) | | (5.5 | ) |
Total adjustments | | $ | (44.1 | ) | | $ | (31.3 | ) |
| | | | |
Total recommended rate increase | | $ | 23.5 |
| | $ | 36.3 |
|
The next steps in the procedural schedule are as follows:
Rebuttal testimony — Nov. 3, 2017;
Intervenor sur-rebuttal testimony — Nov. 15, 2017;
Hearings — Dec. 11 - 15 and 18 - 19, 2017; and
Statements of position — Jan. 19, 2018.
Interim rates, subject to refund, are expected to be effective Jan. 1, 2018. A final decision by the CPUC is anticipated in March 2018.
Annual Electric Earnings Test — PSCo must share with customers earnings that exceed the authorized ROE of 9.83 percent for 2015 through 2017, as part of an annual earnings test. The current estimate of the 2017 earnings test, based on annual forecasted information, did not result in the recognition of a liability as of Sept. 30, 2017.
NSP-Wisconsin anticipates a final written order later this year, with new rates effective on Jan. 1, 2017.
SPS
Pending Regulatory Proceedings — Public Utility Commission of Texas (PUCT)
Appeal of the Texas 2015 Electric Rate Case Decision — In 2014, SPS had requested an overall retail electric revenue rate increase of $64.8 million, which it subsequently revised to $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. The hearing inIn March 2017, the appeal is scheduled for February 2017.Travis County District Court denied SPS’ appeal. In April 2017, SPS appealed the District Court’s decision to the Court of Appeals.
Texas 20162017 Electric Rate Case — In February 2016,August 2017, SPS filed a $66.4 million, or 7.1 percent, retail electric, non-fuel base rate increase case in Texas with each of its Texas municipalities and the PUCT requesting an overall increase in annual base rate revenue of approximately $71.9 million, or 14.4 percent.PUCT. The filing isrequest was based on a historic test year (HTY)the 12-month period ended Sept.June 30, 2015,2017, with the final three months based on estimates, a requested ROE of 10.25 percent, ana Texas retail electric rate base of approximately $1.7$1.9 billion and an equity ratio of 53.97 percent.
In SPS’ required update filing in April 2016,October 2017, SPS revised its requestedrequest to $54.6 million, or 5.8 percent, which reflects updated actual results. In addition, approximately $4.4 million of rate case expenses was bifurcated into a separate docket.
The following table summarizes SPS’ revised rate increase to $68.6 million.request:
|
| | | | |
Revenue Request (Millions of Dollars) | | |
Incremental revenue request | | $ | 69.2 |
|
Transmission Cost Recovery Factor (TCRF) revenue conversion to base rates (a) | | (14.6 | ) |
Net revenue increase request | | $ | 54.6 |
|
| |
(a) | The roll-in of the TCRF rider revenue into base rates will not have an impact on customer bills or total revenue as these costs are already being recovered through the rider. SPS can request another TCRF rider after the conclusion of this rate case to recover transmission investments subsequent to June 30, 2017. |
Key dates in the procedural schedule are as follows:
Pursuant to legislation passed in Texas in 2015, theIntervenors’ direct testimony — Feb. 22, 2018;
PUCT Staff direct testimony — March 1, 2018;
PUCT Staff and intervenors’ cross-rebuttal testimony — March 22, 2018;
SPS’ rebuttal testimony — March 23, 2018;
Hearings — April 10 - 20, 2018; and
Statutory deadline — Aug. 31, 2018.
The final rates established in the case willare expected to be effective retroactive to July 20, 2016.
In August 2016, several intervenors filed direct testimony in response to SPS’ rate request, including:Jan. 23, 2018 through a customer surcharge. A PUCT Staff (Staff), the Alliance of Xcel Municipalities (AXM), the Office of Public Utility Counsel (OPUC), Texas Industrial Energy Consumers (TIEC), and the State of Texas’ agencies.
The Staff recommended a rate increase of approximately $32.9 million, based on a ROE of 9.30 percent and an equity ratio of 51 percent. The Staff’s proposed rate increase reflects imputed revenues for power factor adjustment charges and weather normalization;
AXM recommended a rate increase of approximately $25.2 million, based on a ROE of 9.40 percent and an equity ratio of 51 percent; and
The other intervenors did not present a complete revenue requirement analysis. The majority of the direct testimony focused on specific cost allocation and rate design issues. However, OPUC and TIEC recommended ROEs of 9.20 percent and 9.15 percent, respectively.
In October 2016, SPS and various parties reached an agreement in principledecision is expected in the Texas rate case. SPS and the parties are documenting the settlement, and expect to file with the PUCT in the fourththird quarter of 2016. Any settlement would require approval of the PUCT, with a decision expected by the end of 2016 or early 2017.2018.
Pending Regulatory ProceedingsProceeding — New Mexico Public Regulation Commission (NMPRC)
New Mexico 20152016 Electric Rate Case —In October 2015,November 2016, SPS filed an electric rate case with the NMPRC seeking an increase in non-fuel base rates of $45.4 million. The proposedapproximately $41.4 million, representing a total revenue increase would be offset by a decrease in base fuel revenue of approximately $21.1 million.10.9 percent. The rate filing was based on a June 30, 2015 HTY adjusted for known and measurable changes, a requested ROE of 10.2510.1 percent, an equity ratio of 53.97 percent, an electric rate base of approximately $734$832 million and an equity ratio of 53.97 percent.a future test year ending June 30, 2018.
In August 2016,April 2017, the NMPRC approveddismissed SPS’ rate case. In May 2017, SPS filed a black-box stipulation that resulted in a non-fuel base rate increasenotice of $23.5 million and a decrease in base fuel revenue of approximately $21.1 million. The decrease in base fuel revenue will be reflected in adjustmentsappeal to the fuel and purchased power cost adjustment clause.New Mexico Supreme Court. A decision from the New Mexico Supreme Court is not expected until the second or third quarter of 2018.
SPS plans to file another base rate case inby November 20162017 utilizing a future test yearHTY ending June 2018.2017.
Pending Regulatory ProceedingsProceeding — FERCFederal Energy Regulatory Commission (FERC)
Midcontinent Independent System Operator, Inc. (MISO) ROE Complaints/ROE AdderComplaints — 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 organizationRegional Transmission Organization (RTO) membership and for being an independent transmission company)membership), effective Nov. 12, 2013.
In December 2015, an ALJ initial decisionadministrative law judge (ALJ) recommended the FERC approve a base ROE of 10.32 percent whichfor the MISO TOs. The ALJ found the existing 12.38 percent ROE to be unjust and unreasonable. The recommended 10.32 percent ROE applied a FERC upheldROE policy adopted in a June 2014 order (Opinion 531). The FERC approved the ALJ recommended 10.32 percent base ROE in an order issued on Sept. 28,in September 2016. This ROE iswould be 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 iswould be 10.82 percent, which includesincluding a previously approved 50 basis point adder for RTO membership. Various parties requested rehearing of the September 2016 order. The requests are pending FERC action.
In February 2015, a second complaint seeking to reduce the MISO region ROE from 12.38 percent to 8.67 percent prior to any adder was filed whichwith the FERC, set for hearings, 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 DOC 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. OnIn June 30, 2016, the ALJ recommended a ROE of 9.7 percent, applying the midpointmethodology adopted by the FERC in Opinion 531. A final FERC decision on the second ROE complaint was expected later in 2017, but in April 2017, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) by opinion, vacated and remanded Opinion 531. It is unclear how the D.C. Circuit’s opinion to vacate and remand Opinion 531 will affect the September 2016 FERC order or the timing and outcome of the upper halfsecond ROE complaint. The MISO TOs are evaluating the impact of the discounted cash flow range. AD.C. Circuit ruling on the November 2013 and February 2015 ROE complaints. In September 2017, certain MISO TOs (not including NSP-Minnesota and NSP-Wisconsin) filed a motion to dismiss the second ROE complaint. The motion to dismiss is pending FERC decision is expected in 2017.action.
As of Sept. 30, 2016,2017, NSP-Minnesota has recognized a current liabilityprocessed the refunds for the Nov. 12, 2013 to Feb. 11, 2015 complaint period based on the 10.32 percent ROE provided in the September 2016 FERC order, as well asorder. NSP-Minnesota has also recognized a current refund liability representingconsistent with the best estimate of the final ROE for the secondFeb. 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 in part, from other SPP customers whose transmission service depends on capacity enabled by the upgrade. The SPP OATT has allowed SPP to collect chargescharge for these upgrades since 2008, but to date SPP hashad not chargedbeen charging its customers any amounts attributable tofor these upgrades.
In AprilJuly 2016, SPP filed a request with the FERC granted SPP’s request for a waiver that wouldto allow SPP to recover the charges not billed since 2008. The FERC approved the waiver request in July 2016. SPS and certain other parties requested rehearing of the FERC order. In SeptemberNovember 2016, SPP provided further information regarding additional costs, primarily due tobilled SPS a net amount, for the system-wide claw backperiod from 2008 through August 2016, of point to point revenues previously distributed to SPS and other entities. Amounts due to SPP are expected$12.8 million for these charges, to be paid over a five-year period commencing November 2016 under an optional payment plan that was approved by2016. SPP is also billing SPS ongoing charges of approximately $0.5 million per month. On the FERC in September 2016 and elected by SPS in October 2016. Based on SPP’s most recent calculationretail level, in October 2016, estimatedSPS filed applications for deferred accounting and future recovery of related costs would be approximately $12 millionin New Mexico and Texas. In December 2016, SPS’ New Mexico application was consolidated with its base rate case, but the NMPRC dismissed that rate case in April 2017. SPS will seek recovery of these SPP charges in its next New Mexico base rate case by November 2017. In March 2017, SPS withdrew its Texas application and is now seeking to $14 million,recover these SPP charges in its pending rate case filed in August 2017.
In October 2017, SPS filed a complaint against SPP regarding the amounts billed on and after November 2016 asserting that SPP has assessed upgrade charges to SPS anticipates these costs would be recoverable through regulatory mechanisms.even where SPS’ transmission service was not dependent upon the upgrade as required by the SPP OATT. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the differential in future rate proceedings. Also in October 2017, SPP made adjustments to its previous calculations of upgrade charges to SPP customers, and the impact was immaterial to SPS.
| |
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, 2015,2016, and in Notes 5 and 6 to the
consolidated financial statements included in Xcel Energy Inc.’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 20162017 and June 30, 2016,2017 appropriately represent, in all material respects, the current status of commitments and contingent liabilities and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to Xcel Energy’s financial position.
Purchased Power Agreements (PPAs)
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 approximatelyapproximately 3,537 MW and 3,698 MWmegawatts (MW) of capacity under long-term PPAs as of Sept. 30, 20162017 and Dec. 31, 2015,2016, 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.
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 Sept. 30, 20162017 and Dec. 31, 2015,2016, 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) | | Sept. 30, 2016 | | Dec. 31, 2015 | | Sept. 30, 2017 | | Dec. 31, 2016 |
Guarantees issued and outstanding | | $ | 19.0 |
| | $ | 12.5 |
| | $ | 19.1 |
| | $ | 18.8 |
|
Current exposure under these guarantees | | 0.1 |
| | 0.1 |
| | — |
| | 0.1 |
|
Bonds with indemnity protection | | 43.0 |
| | 41.3 |
| | 51.9 |
| | 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 MGPManufactured Gas Plant (MGP) Site — NSP-Wisconsin has beenwas 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 (the Sediments).park.
In 2012, under a settlement agreement with the United States Environmental Protection Agency (EPA), 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). In January 2017, NSP-Wisconsin agreed to remediate the Phase II Project Area (the Sediments), under a settlement agreement with the EPA. The current cost estimatesettlement was approved by the U.S. District Court for the cleanupWestern District of the Phase I Project Area is approximately $71.4 million, of which approximately $52.6 million has been spent.
Wisconsin. NSP-Wisconsin performed a wet dredge pilot study in the summer of 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-Wisconsininitiated field activities to extend the wet dredge pilot to additional areas of the Site. Settlement negotiations are ongoing between the EPA and NSP-Wisconsin regarding the performance of the full scale cleanup of the Sediments. If a court-approved settlement can be reached with the EPA, NSP-Wisconsin anticipatesperform a full scale wet dredge remedy of the Sediments could be performed beginning as early asin 2017 and potentially conclude byanticipates completion of restoration activities in 2018.
AtThe current remediation cost estimate for the entire site (both the Phase I Project Area and the Sediments) is approximately $162.9 million, of which approximately $131.8 million has been spent. As of Sept. 30, 20162017 and Dec. 31, 2015,2016, NSP-Wisconsin had recorded a total liability of $84.6$31.1 million and $94.4$64.3 million, respectively, for the entire site. NSP-Wisconsin’s potential liability, the actual cost
NSP-Wisconsin has deferred the unrecovered portion of the estimated Site remediation costs as a regulatory asset. The 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,May 2017, NSP-Wisconsin filed a limited natural gas rate case forwhich included recovery of additional expenses associated with remediating the Site. If approved, the annual recovery of MGP clean-up costs would increase from $7.6 million in 2016 to $12.4 million in 2017.
2017 to $18.1 million in 2018.
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 at that time and commenced an investigation of the historic MGP and adjacent properties (the Fargo MGP Site). Based on the investigation that concluded in the third quarter of 2016, NSP-Minnesota has recommended that targeted source removal of impacted soils and historic MGP infrastructure should be performed, subject to further input from theperformed. The North Dakota Department of Health approved NSP-Minnesota’s proposed cleanup plan in January 2017. It is anticipated that remediation activities will be performed in 2018, although the Citytiming and final scope of Fargo, N.D., currentremediation is dependent on whether reasonable access is provided to NSP-Minnesota to perform and implement the approved cleanup plan. Access agreements have been reached with a majority of the property owners and other stakeholders.
in the area to perform the work. NSP-Minnesota has also 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 November 2016 to allow NSP-Minnesota time to investigate site conditions. NSP-Minnesota intends to seek an additional stay of the litigation.January 2018.
As of Sept. 30, 20162017 and Dec. 31, 2015,2016, NSP-Minnesota had recorded a liability of $12.2$16.2 million and $2.7$11.3 million, respectively, for the Fargo MGP Site, with the increase due toSite. The current cost estimate for the remediation activities proposed by NSP-Minnesota.of the site is approximately $23.0 million, of which approximately $6.8 million has been spent. In December 2015, the NDPSCNorth Dakota Public Service Commission (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 and approvals from stakeholders to perform the proposedapproved remediation (including the prospective purchase of the historic MGP property), 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 eleven 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 $4.5 million and $2.0 million for these sites as of Sept. 30, 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
Coal Ash RegulationFederal Clean Water Act (CWA) Waters of the United States Rule — Xcel Energy’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. In April 2015, the EPA and the U.S. Army Corps of Engineers (Corps) published a final rule regulatingthat significantly expanded the managementtypes of water bodies regulated under the CWA and disposalbroadened the scope of coal combustion byproducts (coal ash) as a nonhazardous waste. Underwaters subject to federal jurisdiction. In October 2015, the final rule, Xcel Energy’s costs to manage and dispose of coal ash has not significantly increased.
In 2015, industry and environmental non-governmental organizations sought judicial review of the final rule. In June 2016, the United StatesU.S. Court of Appeals for the District of ColumbiaSixth Circuit (D.C. Circuit) issued an order remanding and vacating certain elementsa 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 a result of partial settlements with these parties. Oral arguments areto which court should hear challenges to the rule. A ruling is expected to be heard in early 2017 and a final decision is anticipated in the first halfquarter of 2017. Until2018.
In February 2017, President Trump issued an executive order requiring the EPA and the Corps to review and revise the final rule. On June 27, 2017, the agencies issued a proposed rule that rescinds the 2015 final rule and reinstates the prior 1986 definition of “Water of the U.S.” The agencies are also undertaking a rulemaking to develop a new definition of “Waters of the U.S.”
Federal CWA Effluent Limitations Guidelines (ELG) —In 2015, the EPA issued a final decision is reached inELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. In September 2017, the case, it is uncertain whetherEPA delayed the litigation or partial settlements will have any significant impact on resultscompliance date for flue gas desulfurization wastewater and bottom ash transport water until November 2020 while the agency conducts a rulemaking process to potentially revise the effluent limitations and pretreatment standards for these waste streams.
Air
Cross-State Air Pollution Rule (CSAPR)Greenhouse Gas (GHG) Emission Standard for Existing Sources (Clean Power Plan or CPP) — CSAPR addresses long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO2) and nitrogen oxide (NOx) from utilities inIn 2015, the eastern half of the United States using an emissions trading program. For Xcel Energy,EPA issued its final rule for existing power plants. Among other things, the rule applies in Minnesota, Wisconsinrequires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim (2022-2029) and Texas.final (2030 and thereafter) emission performance targets.
CSAPRThe CPP was adopted to address interstate emissions impacting downwind states’ attainment of the 1997 ozone National Ambient Air Quality Standard (NAAQS) and the 1997 and 2006 particulate NAAQS. As the EPA revises the NAAQS, it will consider whether to make any further reductions to CSAPR emission budgets and whether to change which states are includedchallenged by multiple parties in the emissions trading program.D.C. Circuit Court. In December 2015,February 2016, the EPA proposed adjustments to CSAPR emission budgets which address attainment ofU.S. Supreme Court issued an order staying the more stringent 2008 ozone NAAQS.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 adoptedAdministrator to review the CPP rule and if appropriate, publish proposed rules suspending, revising or rescinding it. Accordingly, the EPA has requested that the D.C. Circuit Court hold the litigation in abeyance until the EPA completes its work under the executive order. The D.C. Circuit granted the EPA’s request and is holding the litigation in abeyance, while considering briefs by the parties on whether the court should remand the challenges to the EPA rather than holding them in abeyance, determining whether and how the court continues or ends the stay that currently applies to the CPP.
In October 2017, the EPA published a finalproposed rule to repeal the CPP, based on an analysis that reduced the ozone season emission budget for NOx in Texas by approximately 22 percent, which is expected to lead to increased costs to purchase emission allowances. Xcel Energy does not anticipate these increased costs to purchase emission allowancesCPP exceeds the EPA’s statutory authority under the Clean Air Act (CAA). The EPA will have a material impacttake public comment on the results of operations, financial position or cash flows.proposal for 60 days. The EPA stated it has not yet determined whether it will promulgate a new rule to regulate GHG emissions from existing electric generating units.
Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. In 2005, the EPA amended the best available retrofit technologyThe Best Available Retrofit Technology (BART) requirements of itsthe EPA’s regional haze rules which 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 SOSulfur Dioxide (SO2), NOxNitrogen Oxide (NOx) and PMparticulate matter 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, CSAPR.Cross-State Air Pollution Rule (CSAPR). The requirements of the regional haze plans developed by Minnesota and Colorado that apply to NSP-Minnesota and PSCo have been fully approved and 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 has undergone federal review as described below.
BART Determinations for Texas:Texas developed a state implementation planState Implementation Plan (SIP) that findsfound the CAIR equal to BART for electric generating units (EGUs).units. As a result, no additional controls beyond CAIR compliance would behave been required. In December 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 defersdeferred its approval of CSAPR compliance as BART until the EPA considersconsidered further adjustments to CSAPR emission budgets under the D.C. Circuit’sCircuit Court’s remand of the Texas SO2 emission budgets. In March 2016,The EPA then published a proposed rule in January 2017 that could have had the EPA requested information under the Clean Air Act relatedeffect of requiring installation of dry scrubbers to EGUs at SPS’ plants. SPS identifiedreduce SO2 emissions from Harrington Units 1 and 2. Investment costs associated with dry scrubbers for Harrington Units 1 and 2 Jones Units 1 and 2, Nichols Unit 3 and Plant X Unit 4 as BART-eligible units. These units will be evaluated based on their impact on visibility. Additional emission control equipment undercould have been approximately $400 million. In September 2017, the EPA’s BART guidelines for PM,EPA issued a final rule adopting a Texas only SO2 and NOx could be required iftrading program as a unit is determined to “cause or contribute” to visibility impairment. SPS cannot evaluate the impact of additional emission controls until the EPA concludes its evaluation of BART. In June 2016, the EPA issued a memorandum which allows Texas to voluntarily adopt the CSAPR emission budgets limiting annualBART Alternative. The program allocated SO2 allowances to electric generating units in Texas, including all three Harrington units and NOxboth Tolk units, consistent with their allocation under CSAPR, resulting in an emissions budget for Texas that is consistent with the EPA’s 2012 rule. SPS expects the allowance allocations to be sufficient for SO2 emissions from Harrington and rely on those emission budgets to satisfy Texas’ BART obligations under the regional haze rules. It isTolk units in 2019 and future years. The anticipated costs of compliance are not yet known whether the Texas Commission on Environmental Quality (TCEQ) intends to utilize this option. If Texas does not opt into the CSAPR rule, the EPA is expected to issuehave a proposed rule in December 2016material impact on the results of operations, financial position or cash flows; and SPS believes that could impact Harrington Units 1 and 2.compliance costs would be recoverable through regulatory mechanisms.
In December 2014, the EPA proposed to disapprove portions of the SIP and instead adopt a federal implementation plan (FIP).Reasonable Progress Rule: In January 2016, the EPA adopted a final rule establishing a FIPfederal 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. In March 2016, SPS appealed the EPA’s decision and asked forrequested a stay of the final rule while it is being reviewed. In July 2016, therule. The United States Court of Appeals for the Fifth Circuit (Fifth Circuit) granted the stay motion and decided thatstay. In March 2017, the Fifth Circuit notremanded the D.C.rule to the EPA for reconsideration, while leaving the stay in effect. The Fifth Circuit is now holding the appropriate venue for this case. In addition, SPS filed a petition withcase in abeyance until the EPA requestingcompletes its reconsideration of the rule. In the final rule. SPS believes these costs orBART rule that affects Tolk and Harrington described above, the costs of alternative cost-effective generation would be recoverable through regulatory mechanisms if required, and therefore does not expectEPA noted that it will address the remanded rule in a material impact on results of operations, financial position or cash flows.
Implementation of the NAAQS forfuture action. Such a rule will address whether further SO2 —emission reductions are needed at Tolk to address the “reasonable progress” requirements of the regional haze program. The EPA adopted a more stringent NAAQS for SO2 in 2010. The EPA is requiring states to evaluate areas in three phases. The first phase includes areas near PSCo’s Pawnee plant and SPS’ Tolk and Harrington plants. The Pawnee plant recently installed an SO2 scrubber and the Tolk and Harrington Plants utilize low sulfur coal to reduce SO2 emissions. In June 2016, the EPA issued final designations which found the area near the Tolk plant to be meeting the NAAQS and the areas near the Harrington and Pawnee plants as “unclassifiable.” The area near the Harrington plant is to be monitored for three years and a final designation is expected to be made by December 2020. It is anticipated that the area near the Pawnee plant will be able to show compliancerisk of these controls being imposed along with the NAAQS through air dispersion modeling performed by the Colorado Departmentrisk of Public Health and Environment.
If an area is designated nonattainment in 2020, the states will need to evaluate all SO2 sources in the area. The state would then submit an implementation plan, which would be due by 2022, designed to achieve the NAAQS by 2025. The TCEQ could require additional SO2 controls at Harrington as part of such a plan. The areas near the remaining Xcel Energy power plants will be evaluated in the next designation phase, ending December 2017. The remaining plants, PSCo’s Comanche and Hayden plants along with NSP-Minnesota’s King and Sherco plants, utilize scrubbers to control SO2 emissions. Xcel Energy cannot evaluate the impacts until the designation of nonattainment areas is made, and any required state plans are developed. Xcel Energy believes that should SO2 control systems be required for a plant, compliance costs or the costs of alternative cost-effective generation will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows.
In light of the continuing development of environmental regulatory requirements, as well as the more favorable long term outlook for alternative resources, SPS is undertaking analysis to determine the most cost-effective means to meet the needs of its customers, given a low natural gas price environment, the need to make additional investments to provide additional cooling water to Tolk have caused SPS to seek to decrease the remaining depreciable life of the Tolk facility and the potential need to make major investments in air pollution control equipment.units.
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. In areas where Xcel Energy operates, current monitored air quality concentrations comply with the new standard in the Twin Cities Metropolitan Area in Minnesota and meet the 70 ppb level in the Texas panhandle. In documents issued with the new standard, the EPA projects that both areas will meet the new standard. The Denver Metropolitan Area is currently not meeting the prior ozone standard and will therefore not meet the new, more stringent standard, however PSCo’s scheduled retirement of coal fired plants in Denver that began in 2011 and was completed in August 2017, should help in any plan to mitigate non-attainment. In August 2017, the EPA withdrew its prior decision delaying designations of nonattainment areas under the 2015 ozone NAAQS to October 2018. The CAA requires areas to be designated within two years after a revision to the NAAQS but allows a one year extension if the EPA has insufficient information on which to base a decision. The EPA is now re-assessing to what extent it has sufficient information to make designations in October 2017 and whether in some cases an extension is still necessary.
Legal Contingencies
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
Pacific Northwest FERC Refund Proceeding — A complaint with the FERC posed that sales made in the Pacific Northwest in 2000 and 2001 through bilateral contracts were unjust and unreasonable under the Federal Power Act. The City of Seattle (the City) alleges between $34 million to $50 million in sales with PSCo is subject to refund. In 2003, the FERC terminated the proceeding, although it was later remanded back to the FERC in 2007 by the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).
In May 2015, the FERC issued an order rejecting the City’s claim that any of the sales made resulted in an excessive burden and concluded that the City failed to establish a causal link between any contracts and any claimed unlawful market activity. In February 2016, the City appealed this decision to the Ninth Circuit. This appeal is pending review by the Ninth Circuit.
In December 2015, the Ninth Circuit held that the standard of review applied by the FERC to the contracts which the City was challenging is appropriate. The Ninth Circuit dismissed questions concerning whether the FERC properly established the scope of the hearing, and determined that the challenged orders are preliminary and that the Ninth Circuit lacks jurisdiction to review evidentiary decisions until after the FERC’s proceedings are final. The City joined the State of California in its request seeking rehearing of this order, which the Ninth Circuit denied. The FERC proceedings are now final with respect to the City’s claims and are subject to review in the pending Ninth Circuit appeal.
In October 2016, a settlement was reached that resolves all outstanding claims between and among the City and the respondents, including PSCo. Settlement terms required PSCo to pay the City $15,000 and the City to withdraw its pending appeal with the Ninth Circuit. This brings this matter to a close.
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.
Thee prime, Xcel Energy and its other affiliates were sued along with several other gas marketing companies. These cases were all consolidated in the U.S. District Court in Nevada. FiveSix of the cases have since been settled and seven have been dismissed. Oneremain active, which includes one multi-district litigation (MDL) matter remains and it consistsconsisting of a Colorado class (Breckenridge), a Wisconsin class (NSP-Wisconsin)(Arandell Corp.), a Missouri class, a Kansas class, and two other cases identified as “Sinclair Oil” and “Farmland.” In May 2016,A motion for class certification was denied and plaintiffs have appealed the ruling to the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit). Motions for summary judgment were granted by the MDL judge granted summary judgment dismissing defendants from the Farmland lawsuit.in favor of e prime and Xcel Energy havein Sinclair Oil and Farmland. Plaintiffs in both cases appealed this decision to the Ninth Circuit. Motions for summary judgment were also filed a motion seeking clarification that this order includes them. This motion is currently pending and is expected to be heard in December 2016. Theby defendants, including e prime, defendants filed a summary judgment motion in the Colorado class lawsuit (Breckenridge) and oppositions to class certifications in all of the class actions, which is also expected to be heardremaining lawsuits. These motions were denied and e prime subsequently filed an appeal in December 2016. Trial dates areSeptember 2017. Dates for all matters pending before the Ninth Circuit have not expected to occur prior to early 2017.been scheduled. Xcel Energy, NSP-Wisconsin and e prime have concluded that a loss is remote.
Line Extension Disputes — In December 2015, Development Recovery Company (DRC) filed a lawsuit in Denver State Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric and gas service agreements entered into by PSCo and various developers. The dispute involves 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 Colorado Public Utilities Commission (CPUC).CPUC. In June 2016, DRC appealed the district court’s dismissal of the lawsuit, and the Colorado Court of Appeals affirmed the lower court decision in favor of PSCo. In July 2017, DRC filed a notice of appeal. DRC filed its opening brief on Oct. 20, 2016 and PSCo’s answer briefpetition to appeal the decision with the Colorado Supreme Court. It is due Nov. 24, 2016.uncertain whether the Colorado Supreme Court will grant the petition. DRC also brought a proceeding before the CPUC as assignee on behalf of two developers, Ryland Homes and Richmond Homes of Colorado. In March 2016, the ALJ issued an order rejecting DRC’s claims for additional allowances and refunds. In June 2016, the ALJ’s determination was approved by the CPUC. DRC did not file a request for reconsideration before the CPUC contesting the decision, but filed an appeal in the Denver District Court in August 2016. In July 2017, a stipulation to dismiss this lawsuit with prejudice was filed on behalf of all parties and granted by the Denver District Court.
PSCo has concluded that a loss is remote with respect to this matter as the service agreements were developed to implement CPUC approved tariffs and PSCo has complied with the tariff provisions. Also, if a loss were sustained, PSCo believes it would be allowed to recover these costs through traditional regulatory mechanisms. The amount or range in dispute is presently unknown and no accrual has been recorded for this matter.
| |
7. | Borrowings and Other Financing Instruments |
Short-Term Borrowings
Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. 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 Sept. 30, 2016 | | Year Ended Dec. 31, 2015 | | Three Months Ended Sept. 30, 2017 | | Year Ended Dec. 31, 2016 |
Borrowing limit | | $ | 2,750 |
| | $ | 2,750 |
| | $ | 2,750 |
| | $ | 2,750 |
|
Amount outstanding at period end | | 366 |
| | 846 |
| | 514 |
| | 392 |
|
Average amount outstanding | | 477 |
| | 601 |
| | 679 |
| | 485 |
|
Maximum amount outstanding | | 609 |
| | 1,360 |
| | 867 |
| | 1,183 |
|
Weighted average interest rate, computed on a daily basis | | 0.77 | % | | 0.48 | % | | 1.50 | % | | 0.74 | % |
Weighted average interest rate at period end | | 0.77 |
| | 0.82 |
| | 1.53 |
| | 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 Sept. 30, 20162017 and Dec. 31, 2015,2016, there were $19$28 million and $29$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 facility capacity.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.
At Sept. 30, 2016,2017, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available:
| | (Millions of Dollars) | | Credit Facility (a) | | Drawn (b) | | Available | | Credit Facility (a) | | Drawn (b) | | Available |
Xcel Energy Inc. | | $ | 1,000 |
| | $ | 362 |
| | $ | 638 |
| | $ | 1,000 |
| | $ | 422 |
| | $ | 578 |
|
PSCo | | 700 |
| | 3 |
| | 697 |
| | 700 |
| | 4 |
| | 696 |
|
NSP-Minnesota | | 500 |
| | 11 |
| | 489 |
| | 500 |
| | 21 |
| | 479 |
|
SPS | | 400 |
| | 5 |
| | 395 |
| | 400 |
| | 3 |
| | 397 |
|
NSP-Wisconsin | | 150 |
| | 4 |
| | 146 |
| | 150 |
| | 92 |
| | 58 |
|
Total | | $ | 2,750 |
| | $ | 385 |
| | $ | 2,365 |
| | $ | 2,750 |
| | $ | 542 |
| | $ | 2,208 |
|
| |
(a) | These credit facilities expire 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 atas of Sept. 30, 20162017 and Dec. 31, 2015.2016.
Amended Credit Agreements - In June 2016, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS entered into amended five-year credit agreements with a syndicate of banks. The total borrowing limit under the amended credit agreements remained at $2.75 billion. The amended credit agreements have substantially the same terms and conditions as the prior credit agreements with the following exceptions:
The maturity extended from October 2019 to June 2021.
The Eurodollar borrowing margins on these lines of credit were reduced to a range of 75 to 150 basis points per year, from a range of 87.5 to 175 basis points per year, based upon applicable long-term credit ratings.
The commitment fees, calculated on the unused portion of the lines of credit, were reduced to a range of 6 to 22.5 basis points per year, from a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.
Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility termination date for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility termination date for an additional one-year period. All extension requests are subject to majority bank group approval.
Long-Term Borrowings
During the nine months ended Sept. 30, 2016,2017, Xcel Energy Inc. and its utility subsidiaries completedissued the following bond issuances:following:
In March, Xcel Energy Inc.PSCo issued $400 million of 2.4 percent senior notes due March 15, 2021 and $350 million of 3.3 percent senior notes due June 1, 2025;
In May, NSP-Minnesota issued $350 million of 3.6 percent first mortgage bonds due May 15, 2046;
In June, PSCo issued $250 million of 3.553.80 percent first mortgage bonds due June 15, 2046; and2047;
In August, SPS issued $300$450 million of 3.43.70 percent first mortgage bonds due Aug. 15, 2046.2047; and
NSP-Minnesota issued $600 million of 3.60 percent first mortgage bonds due Sept. 15, 2047.
Debt Redemption
On Aug. 30, 2017, SPS reacquired $250 million of debt with a coupon rate of 8.75 percent and an original maturity date of Dec. 1, 2018. The redemption resulted in payment of an early redemption premium of $21.6 million which was deferred as a regulatory asset.
On Sept. 29, 2017, NSP-Minnesota reacquired $500 million of debt with a coupon rate of 5.25 percent and an original maturity date of March 1, 2018. The redemption resulted in payment of an early redemption premium of $7.9 million which was deferred as a regulatory asset.
| |
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 measurementreporting 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 prices.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 international equity funds, private equity investments and real estate investments are measured using a NAV methodology,NAVs, which takestake 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 and international equity 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.
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 2.2 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.
Electric commodity derivatives held by NSP-Minnesota and SPS include transmission congestion instruments, generally referred to as financial transmission rights (FTRs). 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 energy congestion, which is caused bytransmission congestion. In addition to overall transmission load, and transmission constraints. Congestioncongestion is also influenced by the operating schedules of power plants and the consumption of electricity.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 oncleared prices for each FTR for the historical pricing of FTR purchases.most recent auction.
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. Given the limited observability of management’s forecasts for several oftransparency in the inputs to this complex valuation modelauction process, fair value measurements for FTRs have been assigned a Level 3. MonthlyNon-trading monthly FTR settlements for non-trading FTRs 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, relative to the electric utility operations of NSP-Minnesota and SPS,limited transparency associated with 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 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. RealizedGiven 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, given the purpose and legal restrictions on the use of nuclear decommissioning fund assets.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 $355.3$511.7 million and $328.8$378.6 million atas of Sept. 30, 20162017 and Dec. 31, 2015,2016, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $65.8$10.3 million and $100.2$46.9 million atas of Sept. 30, 20162017 and Dec. 31, 2015,2016, respectively.
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 atas of Sept. 30, 20162017 and Dec. 31, 2015:2016:
| | | | Sept. 30, 2016 | | Sept. 30, 2017 |
| | | | Fair Value | | | | Fair Value |
(Thousands of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | Investments Measured at NAV (b) | | Total | | Cost | | Level 1 | | Level 2 | | Level 3 | | Investments Measured at NAV (b) | | Total |
Nuclear decommissioning fund (a) | | | | | | | | | | | | | | | | | | | | | | | | |
Cash equivalents | | $ | 15,055 |
| | $ | 15,055 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 15,055 |
| | $ | 32,727 |
| | $ | 32,727 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 32,727 |
|
Commingled funds: | | | | | | | | | | | | | | | | | | | | | | | | |
Non U.S. equities | | 254,362 |
| | — |
| | — |
| | — |
| | 245,481 |
| | 245,481 |
| | 257,487 |
| | 204,502 |
| | — |
| | — |
| | 86,654 |
| | 291,156 |
|
Emerging market debt funds | | 92,472 |
| | — |
| | — |
| | — |
| | 101,387 |
| | 101,387 |
| | 97,285 |
| | — |
| | — |
| | — |
| | 106,842 |
| | 106,842 |
|
Commodity funds | | 99,771 |
| | — |
| | — |
| | — |
| | 82,139 |
| | 82,139 |
| |
Private equity investments | | 130,848 |
| | — |
| | — |
| | — |
| | 178,768 |
| | 178,768 |
| | 139,185 |
| | — |
| | — |
| | — |
| | 192,098 |
| | 192,098 |
|
Real estate | | 121,271 |
| | — |
| | — |
| | — |
| | 174,552 |
| | 174,552 |
| | 129,219 |
| | — |
| | — |
| | — |
| | 195,506 |
| | 195,506 |
|
Other commingled funds | | 151,048 |
| | — |
| | — |
| | — |
| | 159,230 |
| | 159,230 |
| | 146,179 |
| | 14,964 |
| | — |
| | — |
| | 145,313 |
| | 160,277 |
|
Debt securities: | | | | | | | | | | | | | | | | | | | | | | | | |
Government securities | | 34,853 |
| | — |
| | 35,723 |
| | — |
| | — |
| | 35,723 |
| | 45,310 |
| | — |
| | 44,944 |
| | — |
| | — |
| | 44,944 |
|
U.S. corporate bonds | | 95,828 |
| | — |
| | 93,981 |
| | — |
| | — |
| | 93,981 |
| | 251,138 |
| | — |
| | 252,868 |
| | — |
| | — |
| | 252,868 |
|
International corporate bonds | | 19,877 |
| | — |
| | 19,860 |
| | — |
| | — |
| | 19,860 |
| |
Municipal bonds | | 13,906 |
| | — |
| | 14,638 |
| | — |
| | — |
| | 14,638 |
| |
Asset-backed securities | | 2,847 |
| | — |
| | 2,948 |
| | — |
| | — |
| | 2,948 |
| |
Mortgage-backed securities | | 10,118 |
| | — |
| | 10,582 |
| | — |
| | — |
| | 10,582 |
| |
Non U.S. corporate bonds | | | 46,245 |
| | — |
| | 46,611 |
| | — |
| | — |
| | 46,611 |
|
Equity securities: | | | | | | | | | | | | | | | | | | | | | | | | |
U.S. equities | | 270,137 |
| | 455,035 |
| | — |
| | — |
| | — |
| | 455,035 |
| | 258,075 |
| | 509,564 |
| | — |
| | — |
| | — |
| | 509,564 |
|
Non U.S. equities | | 213,291 |
| | 225,782 |
| | — |
| | — |
| | — |
| | 225,782 |
| | 152,575 |
| | 224,139 |
| | — |
| | — |
| | — |
| | 224,139 |
|
Total | | $ | 1,525,684 |
| | $ | 695,872 |
| | $ | 177,732 |
| | $ | — |
| | $ | 941,557 |
| | $ | 1,815,161 |
| | $ | 1,555,425 |
| | $ | 985,896 |
| | $ | 344,423 |
| | $ | — |
| | $ | 726,413 |
| | $ | 2,056,732 |
|
| |
(a) | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $134.5$131.8 million of equity investments in unconsolidated subsidiaries and $98.8$111.7 million of rabbi trust assets and miscellaneous investments. |
| |
(b) | Based on the requirementsDue to limited availability of ASU 2015-07,published pricing and a lack of immediate redeemability, certain fund investments measured at fair value using a NAV methodology haveare not been classified inrequired to be categorized within the fair value hierarchy. See Note 2 for further information on the adoption of ASU 2015-07. |
| | | | Dec. 31, 2015 | | Dec. 31, 2016 |
| | | | Fair Value | | | | Fair Value |
(Thousands of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | Investments Measured at NAV (b) | | Total | | Cost | | Level 1 | | Level 2 | | Level 3 | | Investments Measured at NAV (b) | | Total |
Nuclear decommissioning fund (a) | | | | | | | | | | | | | | | | | | | | | | | | |
Cash equivalents | | $ | 27,484 |
| | $ | 27,484 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 27,484 |
| | $ | 20,379 |
| | $ | 20,379 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 20,379 |
|
Commingled funds: | | | | | | | | | | | | | | | | | | | | | | | | |
Non U.S. equities | | 259,114 |
| | — |
| | — |
| | — |
| | 231,122 |
| | 231,122 |
| | 260,877 |
| | 133,126 |
| | — |
| | — |
| | 112,233 |
| | 245,359 |
|
Emerging market debt funds | | 88,987 |
| | — |
| | — |
| | — |
| | 88,467 |
| | 88,467 |
| | 93,597 |
| | — |
| | — |
| | — |
| | 97,543 |
| | 97,543 |
|
Commodity funds | | 99,771 |
| | — |
| | — |
| | — |
| | 77,338 |
| | 77,338 |
| | 106,571 |
| | — |
| | — |
| | — |
| | 92,091 |
| | 92,091 |
|
Private equity investments | | 105,965 |
| | — |
| | — |
| | — |
| | 157,528 |
| | 157,528 |
| | 132,190 |
| | — |
| | — |
| | — |
| | 190,462 |
| | 190,462 |
|
Real estate | | 115,019 |
| | — |
| | — |
| | — |
| | 165,190 |
| | 165,190 |
| | 128,630 |
| | — |
| | — |
| | — |
| | 187,647 |
| | 187,647 |
|
Other commingled funds | | 150,877 |
| | — |
| | — |
| | — |
| | 164,389 |
| | 164,389 |
| | 151,048 |
| | — |
| | — |
| | — |
| | 159,489 |
| | 159,489 |
|
Debt securities: | | | | | | | | | | | | | | | | | | | | | | | | |
Government securities | | 24,444 |
| | — |
| | 21,356 |
| | — |
| | — |
| | 21,356 |
| | 32,764 |
| | — |
| | 31,965 |
| | — |
| | — |
| | 31,965 |
|
U.S. corporate bonds | | 73,061 |
| | — |
| | 65,276 |
| | — |
| | — |
| | 65,276 |
| | 104,913 |
| | — |
| | 105,772 |
| | — |
| | — |
| | 105,772 |
|
International corporate bonds | | 13,726 |
| | — |
| | 12,801 |
| | — |
| | — |
| | 12,801 |
| |
Non U.S. corporate bonds | | | 21,751 |
| | — |
| | 21,672 |
| | — |
| | — |
| | 21,672 |
|
Municipal bonds | | 49,255 |
| | — |
| | 51,589 |
| | — |
| | — |
| | 51,589 |
| | 13,609 |
| | — |
| | 13,786 |
| | — |
| | — |
| | 13,786 |
|
Asset-backed securities | | 2,837 |
| | — |
| | 2,830 |
| | — |
| | — |
| | 2,830 |
| |
Mortgage-backed securities | | 11,444 |
| | — |
| | 11,621 |
| | — |
| | — |
| | 11,621 |
| | 2,785 |
| | — |
| | 2,816 |
| | — |
| | — |
| | 2,816 |
|
Equity securities: | | | | | | | | | | | | | | | | | | | | | | | | |
U.S. equities | | 273,106 |
| | 432,495 |
| | — |
| | — |
| | — |
| | 432,495 |
| | 270,779 |
| | 473,400 |
| | — |
| | — |
| | — |
| | 473,400 |
|
Non U.S. equities | | 200,509 |
| | 214,664 |
| | — |
| | — |
| | — |
| | 214,664 |
| | 189,100 |
| | 218,381 |
| | — |
| | — |
| | — |
| | 218,381 |
|
Total | | $ | 1,495,599 |
| | $ | 674,643 |
| | $ | 165,473 |
| | $ | — |
| | $ | 884,034 |
| | $ | 1,724,150 |
| | $ | 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 $130.0$132.8 million of equity investments in unconsolidated subsidiaries and $48.9$98.3 million of rabbi trust assets and miscellaneous investments. |
| |
(b) | Based on the requirementsDue to limited availability of ASU 2015-07,published pricing and a lack of immediate redeemability, certain fund investments measured at fair value using a NAV methodology haveare not been classified inrequired to be categorized within the fair value hierarchy. See Note 2 for further information on the adoption of ASU 2015-07. |
For the three and nine months ended Sept. 30, 20162017 and 20152016 there were no Level 3 nuclear decommissioning fund investments and no transfers of amounts between levels.
The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, atas of Sept. 30, 2016:2017:
| | | | Final Contractual Maturity | | 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 | | 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 | | $ | — |
| | $ | 10,583 |
| | $ | 971 |
| | $ | 24,169 |
| | $ | 35,723 |
| | $ | — |
| | $ | 1,275 |
| | $ | 2,303 |
| | $ | 41,366 |
| | $ | 44,944 |
|
U.S. corporate bonds | | 257 |
| | 28,245 |
| | 59,451 |
| | 6,028 |
| | 93,981 |
| | 3,834 |
| | 64,119 |
| | 150,741 |
| | 34,174 |
| | 252,868 |
|
International corporate bonds | | — |
| | 5,043 |
| | 11,606 |
| | 3,211 |
| | 19,860 |
| |
Municipal bonds | | — |
| | 210 |
| | 5,773 |
| | 8,655 |
| | 14,638 |
| |
Asset-backed securities | | — |
| | — |
| | 2,948 |
| | — |
| | 2,948 |
| |
Mortgage-backed securities | | — |
| | — |
| | — |
| | 10,582 |
| | 10,582 |
| |
Non U.S. corporate bonds | | | — |
| | 13,793 |
| | 26,651 |
| | 6,167 |
| | 46,611 |
|
Debt securities | | $ | 257 |
| | $ | 44,081 |
| | $ | 80,749 |
| | $ | 52,645 |
| | $ | 177,732 |
| | $ | 3,834 |
| | $ | 79,187 |
| | $ | 179,695 |
| | $ | 81,707 |
| | $ | 344,423 |
|
Rabbi Trusts
In June 2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of its supplemental executive retirement plan and nonqualified pension plans.deferred compensation plan. The following table presentstables present the cost and fair value of the assets held in rabbi trusts atas of Sept. 30, 2017 and Dec. 31, 2016:
| | | | Sept. 30, 2016 | | Sept. 30, 2017 |
| | | | Fair Value | | | | Fair Value |
(Thousands of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | Total | | Cost | | Level 1 | | Level 2 | | Level 3 | | Total |
Rabbi Trusts (a) | | | | | | | | | | | | | | | | | | | | |
Cash equivalents | | $ | 47,762 |
| | $ | 47,762 |
| | $ | — |
| | $ | — |
| | $ | 47,762 |
| | $ | 11,227 |
| | $ | 11,227 |
| | $ | — |
| | $ | — |
| | $ | 11,227 |
|
Mutual funds | | 1,594 |
| | 1,867 |
| | — |
| | — |
| | 1,867 |
| | 46,368 |
| | 48,944 |
| | — |
| | — |
| | 48,944 |
|
Total | | $ | 49,356 |
| | $ | 49,629 |
| | $ | — |
| | $ | — |
| | $ | 49,629 |
| | $ | 57,595 |
| | $ | 60,171 |
| | $ | — |
| | $ | — |
| | $ | 60,171 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| | 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. |
An immaterial amount of mutual funds were held in rabbi trusts at Dec. 31, 2015.
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.
AtAs of Sept. 30, 2016,2017, accumulated other comprehensive losses related to interest rate derivatives included $3.4$2.6 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 energy-related instruments.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.committee, which is made up of management personnel not directly involved in the activities governed by this policy.
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.
AtAs of Sept. 30, 2016,2017, Xcel Energy had various vehicle fuel contracts designated as cash flow hedges extending through December 2016.2018. Xcel Energy also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, but aremay 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 and nine months ended Sept. 30, 20162017 and 2015.2016.
AtAs of Sept. 30, 2016,2017, net lossesgains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included immaterial$0.1 million of net lossesgains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.
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 atas of Sept. 30, 20162017 and Dec. 31, 2015:2016:
| | (Amounts in Thousands) (a)(b) | | Sept. 30, 2016 | | Dec. 31, 2015 | | Sept. 30, 2017 | | Dec. 31, 2016 |
Megawatt hours of electricity | | 64,040 |
| | 50,487 |
| | 78,733 |
| | 46,773 |
|
Million British thermal units of natural gas | | 116,144 |
| | 20,874 |
| | 62,279 |
| | 121,978 |
|
Gallons of vehicle fuel | | 35 |
| | 141 |
| | 300 |
| | — |
|
| |
(a) | Amounts are not reflective of net positions in the underlying commodities. |
| |
(b) | Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. |
The following tables detail the impact of derivative activity during the three and nine months ended Sept. 30, 20162017 and 2015,2016, on accumulated other comprehensive loss, regulatory assets and liabilities, and income:
| | | | Three Months Ended Sept. 30, 2016 | | | Three Months Ended Sept. 30, 2017 | |
| | Pre-Tax Fair Value Gains (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 | | | 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 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) | | | Accumulated Other Comprehensive Loss | | Regulatory (Assets) and Liabilities | | Accumulated Other Comprehensive Loss | | Regulatory Assets and (Liabilities) | |
Derivatives designated as cash flow hedges | | | | | | | | | | | | | | | | | | | | | | |
Interest rate | | $ | — |
| | $ | — |
| | $ | 1,502 |
| (a) | $ | — |
| | $ | — |
| | | $ | — |
| | $ | — |
| | $ | 1,579 |
| (a) | $ | — |
| | $ | — |
| |
Vehicle fuel and other commodity | | (6 | ) | | — |
| | 46 |
| (b) | — |
| | — |
| | | 38 |
| | — |
| | (11 | ) | (b) | — |
| | — |
| |
Total | | $ | (6 | ) | | $ | — |
| | $ | 1,548 |
| | $ | — |
| | $ | — |
| | | $ | 38 |
| | $ | — |
| | $ | 1,568 |
| | $ | — |
| | $ | — |
| |
Other derivative instruments | | | | | | | | | | | | | | | | | | | | | | |
Commodity trading | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,779 |
| (c) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,282 |
| (c) |
Electric commodity | | — |
| | 15,497 |
| | — |
| | 2,491 |
| (d) | — |
| | | — |
| | 17,750 |
| | — |
| | (3,122 | ) | (d) | — |
| |
Natural gas commodity | | — |
| | (5,737 | ) | | — |
| | — |
|
| (6 | ) | (e) | | — |
| | (2,076 | ) | | — |
| | — |
|
| — |
|
|
Total | | $ | — |
| | $ | 9,760 |
| | $ | — |
| | $ | 2,491 |
| | $ | 1,773 |
| | | $ | — |
| | $ | 15,674 |
| | $ | — |
| | $ | (3,122 | ) | | $ | 1,282 |
| |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended Sept. 30, 2016 | | | Nine Months Ended Sept. 30, 2017 | |
| | Pre-Tax Fair Value Gains (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 | | | 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) | | | Accumulated Other Comprehensive Loss | | Regulatory (Assets) and Liabilities | | Accumulated Other Comprehensive Loss | | Regulatory Assets and (Liabilities) | |
Derivatives designated as cash flow hedges | | | | | | | | | | | | | | | | | | | | | | |
Interest rate | | $ | — |
| | $ | — |
| | $ | 4,470 |
| (a) | $ | — |
| | $ | — |
| | | $ | — |
| | $ | — |
| | $ | 4,257 |
| (a) | $ | — |
| | $ | — |
| |
Vehicle fuel and other commodity | | 7 |
| | — |
| | 150 |
| (b) | — |
| | — |
| | | 81 |
| | — |
| | (16 | ) | (b) | — |
| | — |
| |
Total | | $ | 7 |
| | $ | — |
| | $ | 4,620 |
| | $ | — |
| | $ | — |
| | | $ | 81 |
| | $ | — |
| | $ | 4,241 |
| | $ | — |
| | $ | — |
| |
Other derivative instruments | | | | | | | | | | | | | | | | | | | | | | |
Commodity trading | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 3,269 |
| (c) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 8,069 |
| (c) |
Electric commodity | | — |
| | 14,528 |
| | — |
| | 30,024 |
| (d) | — |
| | | — |
| | 17,245 |
| | — |
| | (9,435 | ) | (d) | — |
| |
Natural gas commodity | | — |
| | (2,376 | ) | | — |
| | 11,666 |
| (e) | (5,005 | ) | (e) | | — |
| | (9,921 | ) | | — |
| | 1,075 |
| (e) | (4,070 | ) | (e) |
Total | | $ | — |
| | $ | 12,152 |
| | $ | — |
| | $ | 41,690 |
| | $ | (1,736 | ) | | | $ | — |
| | $ | 7,324 |
| | $ | — |
| | $ | (8,360 | ) | | $ | 3,999 |
| |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended Sept. 30, 2015 | | | Three Months Ended Sept. 30, 2016 | |
| | Pre-Tax Fair Value Losses Recognized During the Period in: | | Pre-Tax Losses Reclassified into Income During the Period from: | | Pre-Tax Losses Recognized During the Period in Income | | | Pre-Tax Fair Value Gains (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) | | | Accumulated Other Comprehensive Loss | | Regulatory (Assets) and Liabilities | | Accumulated Other Comprehensive Loss | | Regulatory Assets and (Liabilities) | |
Derivatives designated as cash flow hedges | | | | | | | | | | | | | | | | | | | | | | |
Interest rate | | $ | — |
| | $ | — |
| | $ | 1,118 |
| (a) | $ | — |
| | $ | — |
| | | $ | — |
| | $ | — |
| | $ | 1,502 |
| (a) | $ | — |
| | $ | — |
| |
Vehicle fuel and other commodity | | (70 | ) | | — |
| | 34 |
| (b) | — |
| | — |
| | | (6 | ) | | — |
| | 46 |
| (b) | — |
| | — |
| |
Total | | $ | (70 | ) | | $ | — |
| | $ | 1,152 |
| | $ | — |
| | $ | — |
| | | $ | (6 | ) | | $ | — |
| | $ | 1,548 |
| | $ | — |
| | $ | — |
| |
Other derivative instruments | | | | | | | | | | | | | |
| | |
| | |
| | |
| | |
| |
Commodity trading | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (3,460 | ) | (c) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,779 |
| (c) |
Electric commodity | | — |
| | (2,403 | ) | | — |
| | 2,860 |
| (d) | — |
| | | — |
| | 15,497 |
| | — |
| | 2,491 |
| (d) | — |
| |
Natural gas commodity | | — |
| | (2,978 | ) | | — |
| | — |
| | (405 | ) | (e) | | — |
| | (5,737 | ) | | — |
| | — |
|
| (6 | ) | (e) |
Total | | $ | — |
| | $ | (5,381 | ) | | $ | — |
| | $ | 2,860 |
| | $ | (3,865 | ) | | | $ | — |
| | $ | 9,760 |
| | $ | — |
| | $ | 2,491 |
| | $ | 1,773 |
| |
| | | | Nine Months Ended Sept. 30, 2015 | | | Nine Months Ended Sept. 30, 2016 | |
| | Pre-Tax Fair Value Losses Recognized During the Period in: | | Pre-Tax Losses Reclassified into Income During the Period from: | | Pre-Tax Losses Recognized During the Period in Income | | | Pre-Tax Fair Value Gains (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) | | | Accumulated Other Comprehensive Loss | | Regulatory (Assets) and Liabilities | | Accumulated Other Comprehensive Loss | | Regulatory Assets and (Liabilities) | |
Derivatives designated as cash flow hedges | | | | | | | | | | | | | | | | | | | | | | |
Interest rate | | $ | — |
| | $ | — |
| | $ | 3,013 |
| (a) | $ | — |
| | $ | — |
| | | $ | — |
| | $ | — |
| | $ | 4,470 |
| (a) | $ | — |
| | $ | — |
| |
Vehicle fuel and other commodity | | (59 | ) | | — |
| | 88 |
| (b) | — |
| | — |
| | | 7 |
| | — |
| | 150 |
| (b) | — |
| | — |
| |
Total | | $ | (59 | ) | | $ | — |
| | $ | 3,101 |
| | $ | — |
| | $ | — |
| | | $ | 7 |
| | $ | — |
| | $ | 4,620 |
| | $ | — |
| | $ | — |
| |
Other derivative instruments | | | | | | | | | | | | | | | | | | | | | | |
Commodity trading | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (5,896 | ) | (c) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 3,269 |
| (c) |
Electric commodity | | — |
| | (16,611 | ) | | — |
| | 16,020 |
| (d) | — |
| | | — |
| | 14,528 |
| | — |
| | 30,024 |
| (d) | — |
| |
Natural gas commodity | | — |
| | (3,366 | ) | | — |
| | 8,685 |
| (e) | (9,455 | ) | (e) | | — |
| | (2,376 | ) | | — |
| | 11,666 |
| (e) | (5,005 | ) | (e) |
Total | | $ | — |
| | $ | (19,977 | ) | | $ | — |
| | $ | 24,705 |
| | $ | (15,351 | ) | | | $ | — |
| | $ | 12,152 |
| | $ | — |
| | $ | 41,690 |
| | $ | (1,736 | ) | |
| |
(a) | Amounts are recorded to interest charges. |
| |
(b) | Amounts are recorded to O&Moperating and maintenance (O&M) expenses. |
| |
(c) | Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. |
| |
(d) | Amounts are recorded to electric fuel and purchased power. These derivative settlement gaingains and loss amountslosses 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 and nine months ended Sept. 30, 2016 included no settlement gains or losses onCertain derivatives enteredare utilized to mitigate natural gas price risk for electric generation and are recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Amounts for the three and nine months ended Sept. 30, 20152017 included $0.4no settlement gains or losses and $0.9 million and $0.5 million, respectively, of settlement losses on derivatives entered to mitigate natural gas price riskgains, respectively. Amounts for electric generation, recorded to electric fuelthe three and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate.nine months ended Sept. 30, 2016 included no settlement gains or losses. The remaining derivative settlement gains and losses for the three and nine months ended Sept. 30, 20162017 and 20152016 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 and nine months ended Sept. 30, 20162017 and 2015.2016. 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.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. AtAs of Sept. 30, 2016, one2017, three of Xcel Energy’s 10 most significant counterparties for these activities, comprising $14.1$36.1 million or 622 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Ratings Services, Moody’s Investor Services or Fitch Ratings. NineSix of the 10 most significant counterparties, comprising $73.4$44.2 million or 3327 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 tenThe one remaining significant counterparty, comprising of $8.1 million or 5 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external analysis. Nine of these significant counterparties are RTOs, municipal or cooperative electric entities or other utilities.
Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those recorded to the consolidated balance sheet at fair value, as well as those accounted for as normal purchase-normal sale contracts and therefore not reflected on the balance sheet, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary is unablesubsidiary’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. Atpayment terms or other covenants. As of Sept. 30, 20162017 and Dec. 31, 2015,2016, there were no derivative instruments in a material liability position that would have required the posting of collateral or settlement of applicable outstanding contracts if the credit ratings of Xcel Energy Inc.’s utility subsidiaries were downgraded below investment grade.with such underlying contract provisions.
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired. Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of Sept. 30, 20162017 and Dec. 31, 2015.2016.
Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis atas of Sept. 30, 2016:2017:
| | | | Sept. 30, 2016 | | Sept. 30, 2017 |
| | Fair Value | | Fair Value Total | | Counterparty Netting (b) | | Total | | Fair Value | | Fair Value Total | | Counterparty Netting (b) | | Total |
(Thousands of Dollars) | | Level 1 | | Level 2 | | Level 3 | | | Level 1 | | Level 2 | | Level 3 | |
Current derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
Derivatives designated as cash flow hedges: | | | | | | | | | | | | | |
Vehicle fuel and other commodity | | | $ | — |
| | $ | 56 |
| | $ | — |
| | $ | 56 |
| | $ | — |
| | $ | 56 |
|
Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
Commodity trading | | $ | 3,846 |
| | $ | 11,239 |
| | $ | — |
| | $ | 15,085 |
| | $ | (9,440 | ) | | $ | 5,645 |
| | 1,412 |
| | 12,172 |
| | 86 |
| | 13,670 |
| | (6,692 | ) | | 6,978 |
|
Electric commodity | | — |
| | — |
| | 27,775 |
| | 27,775 |
| | (3,180 | ) | | 24,595 |
| | — |
| | — |
| | 62,951 |
| | 62,951 |
| | (2,841 | ) | | 60,110 |
|
Natural gas commodity | | — |
| | 6,034 |
| | — |
| | 6,034 |
| | (15 | ) | | 6,019 |
| | — |
| | 1,898 |
| | — |
| | 1,898 |
| | (135 | ) | | 1,763 |
|
Total current derivative assets | | $ | 3,846 |
| | $ | 17,273 |
| | $ | 27,775 |
| | $ | 48,894 |
| | $ | (12,635 | ) | | 36,259 |
| | $ | 1,412 |
| | $ | 14,126 |
| | $ | 63,037 |
| | $ | 78,575 |
| | $ | (9,668 | ) | | 68,907 |
|
PPAs (a) | | | | | | | | | | | | 6,601 |
| | | | | | | | | | | | 5,626 |
|
Current derivative instruments | | | | | | | | | | | | $ | 42,860 |
| | | | | | | | | | | | $ | 74,533 |
|
Noncurrent derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
Derivatives designated as cash flow hedges: | | | | | | | | | | | | | |
Vehicle fuel and other commodity | | | $ | — |
| | $ | 11 |
| | $ | — |
| | $ | 11 |
| | $ | — |
| | $ | 11 |
|
Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
Commodity trading | | $ | 501 |
| | $ | 32,538 |
| | $ | — |
| | $ | 33,039 |
| | $ | (8,306 | ) | | $ | 24,733 |
| | 84 |
| | 30,613 |
| | 5,661 |
| | 36,358 |
| | (7,574 | ) | | 28,784 |
|
Natural gas commodity | | — |
| | 681 |
| | — |
| | 681 |
| | — |
| | 681 |
| |
Total noncurrent derivative assets | | $ | 501 |
| | $ | 33,219 |
| | $ | — |
| | $ | 33,720 |
| | $ | (8,306 | ) | | 25,414 |
| | $ | 84 |
| | $ | 30,624 |
| | $ | 5,661 |
| | $ | 36,369 |
| | $ | (7,574 | ) | | 28,795 |
|
PPAs (a) | | | | | | | | | | | | 25,955 |
| | | | | | | | | | | | 20,329 |
|
Noncurrent derivative instruments | | | | | | | | | | | | $ | 51,369 |
| | | | | | | | | | | | $ | 49,124 |
|
| | | | Sept. 30, 2016 | | Sept. 30, 2017 |
| | Fair Value | | Fair Value Total | | Counterparty Netting (b) | | Total | | Fair Value | | Fair Value Total | | Counterparty Netting (b) | | Total |
(Thousands of Dollars) | | Level 1 | | Level 2 | | Level 3 | | | Level 1 | | Level 2 | | Level 3 | |
Current derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
Derivatives designated as cash flow hedges: | | | | | | | | | | | | | |
Vehicle fuel and other commodity | | $ | — |
| | $ | 41 |
| | $ | — |
| | $ | 41 |
| | $ | — |
| | $ | 41 |
| |
Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
Commodity trading | | 3,921 |
| | 8,000 |
| | — |
| | 11,921 |
| | (9,527 | ) | | 2,394 |
| | $ | 1,289 |
| | $ | 10,204 |
| | $ | 3 |
| | $ | 11,496 |
| | $ | (7,495 | ) | | $ | 4,001 |
|
Electric commodity | | — |
| | — |
| | 3,180 |
| | 3,180 |
| | (3,180 | ) | | — |
| | — |
| | — |
| | 2,842 |
| | 2,842 |
| | (2,841 | ) | | 1 |
|
Natural gas commodity | | — |
| | 15 |
| | — |
| | 15 |
| | (15 | ) | | — |
| | — |
| | 962 |
| | — |
| | 962 |
| | (135 | ) | | 827 |
|
Total current derivative liabilities | | $ | 3,921 |
| | $ | 8,056 |
| | $ | 3,180 |
| | $ | 15,157 |
| | $ | (12,722 | ) | | 2,435 |
| | $ | 1,289 |
| | $ | 11,166 |
| | $ | 2,845 |
| | $ | 15,300 |
| | $ | (10,471 | ) | | 4,829 |
|
PPAs (a) | | | | | | | | | | | | 22,766 |
| | | | | | | | | | | | 22,830 |
|
Current derivative instruments | | | | | | | | | | | | $ | 25,201 |
| | | | | | | | | | | | $ | 27,659 |
|
Noncurrent derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
Commodity trading | | $ | 538 |
| | $ | 24,114 |
| | $ | — |
| | $ | 24,652 |
| | $ | (11,005 | ) | | $ | 13,647 |
| | $ | 52 |
| | $ | 23,072 |
| | $ | — |
| | $ | 23,124 |
| | $ | (10,239 | ) | | $ | 12,885 |
|
Total noncurrent derivative liabilities | | $ | 538 |
| | $ | 24,114 |
| | $ | — |
| | $ | 24,652 |
| | $ | (11,005 | ) | | 13,647 |
| | $ | 52 |
| | $ | 23,072 |
| | $ | — |
| | $ | 23,124 |
| | $ | (10,239 | ) | | 12,885 |
|
PPAs (a) | | | | | | | | | | | | 141,003 |
| | | | | | | | | | | | 118,173 |
|
Noncurrent derivative instruments | | | | | | | | | | | | $ | 154,650 |
| | | | | | | | | | | | $ | 131,058 |
|
| |
(a) | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. |
| |
(b) | Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Sept. 30, 2016.2017. At Sept. 30, 2016,2017, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $2.8$3.5 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. |
The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis atas of Dec. 31, 2015:2016:
| | | | Dec. 31, 2015 | | Dec. 31, 2016 |
| | Fair Value | | Fair Value Total | | Counterparty Netting (b) | | Total | | Fair Value | | Fair Value Total | | Counterparty Netting (b) | | Total |
(Thousands of Dollars) | | Level 1 | | Level 2 | | Level 3 | | | Level 1 | | Level 2 | | Level 3 | |
Current derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
Commodity trading | | $ | 225 |
| | $ | 10,620 |
| | $ | 1,250 |
| | $ | 12,095 |
| | $ | (5,865 | ) | | $ | 6,230 |
| | $ | 13,179 |
| | $ | 14,105 |
| | $ | — |
| | $ | 27,284 |
| | $ | (20,637 | ) | | $ | 6,647 |
|
Electric commodity | | — |
| | — |
| | 21,421 |
| | 21,421 |
| | (4,088 | ) | | 17,333 |
| | — |
| | — |
| | 19,251 |
| | 19,251 |
| | (1,976 | ) | | 17,275 |
|
Natural gas commodity | | — |
| | 496 |
| | — |
| | 496 |
| | (303 | ) | | 193 |
| | — |
| | 8,839 |
| | — |
| | 8,839 |
| | — |
| | 8,839 |
|
Total current derivative assets | Total current derivative assets | $ | 225 |
| | $ | 11,116 |
| | $ | 22,671 |
| | $ | 34,012 |
| | $ | (10,256 | ) | | 23,756 |
| Total current derivative assets | $ | 13,179 |
| | $ | 22,944 |
| | $ | 19,251 |
| | $ | 55,374 |
| | $ | (22,613 | ) | | 32,761 |
|
PPAs (a) | | | | | | | | | | | | 10,086 |
| | | | | | | | | | | | 5,463 |
|
Current derivative instruments | | | | | | | | | | | | $ | 33,842 |
| | | | | | | | | | | | $ | 38,224 |
|
Noncurrent derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
Other derivative instruments: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Commodity trading | | $ | — |
| | $ | 27,416 |
| | $ | — |
| | $ | 27,416 |
| | $ | (6,555 | ) | | $ | 20,861 |
| | $ | 100 |
| | $ | 31,029 |
| | $ | — |
| | $ | 31,129 |
| | $ | (7,323 | ) | | $ | 23,806 |
|
Natural gas commodity | | | — |
| | 1,652 |
| | — |
| | 1,652 |
| | — |
| | 1,652 |
|
Total noncurrent derivative assets | Total noncurrent derivative assets | $ | — |
| | $ | 27,416 |
| | $ | — |
| | $ | 27,416 |
| | $ | (6,555 | ) | | 20,861 |
| Total noncurrent derivative assets | $ | 100 |
| | $ | 32,681 |
| | $ | — |
| | $ | 32,781 |
| | $ | (7,323 | ) | | 25,458 |
|
PPAs (a) | | | | | | | | | | | | 30,222 |
| | | | | | | | | | | | 24,731 |
|
Noncurrent derivative instruments | | | | | | | | | | | | $ | 51,083 |
| | | | | | | | | | | | $ | 50,189 |
|
| | | | Dec. 31, 2015 | | Dec. 31, 2016 |
| | Fair Value | | Fair Value Total | | Counterparty Netting (b) | | Total | | Fair Value | | Fair Value Total | | Counterparty Netting (b) | | Total |
(Thousands of Dollars) | | Level 1 | | Level 2 | | Level 3 | | | Level 1 | | Level 2 | | Level 3 | |
Current derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
Derivatives designated as cash flow hedges: | | | | | | | | | | | | | |
Vehicle fuel and other commodity | | $ | — |
| | $ | 205 |
| | $ | — |
| | $ | 205 |
| | $ | — |
| | $ | 205 |
| |
Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
Commodity trading | | 152 |
| | 7,866 |
| | 555 |
| | 8,573 |
| | (6,904 | ) | | 1,669 |
| | $ | 13,787 |
| | $ | 11,320 |
| | $ | 22 |
| | $ | 25,129 |
| | $ | (20,974 | ) | | $ | 4,155 |
|
Electric commodity | | — |
| | — |
| | 4,088 |
| | 4,088 |
| | (4,088 | ) | | — |
| | — |
| | — |
| | 1,976 |
| | 1,976 |
| | (1,976 | ) | | — |
|
Natural gas commodity | | — |
| | 5,407 |
| | — |
| | 5,407 |
| | (303 | ) | | 5,104 |
| |
Total current derivative liabilities | | $ | 152 |
| | $ | 13,478 |
| | $ | 4,643 |
| | $ | 18,273 |
| | $ | (11,295 | ) | | 6,978 |
| | $ | 13,787 |
| | $ | 11,320 |
| | $ | 1,998 |
| | $ | 27,105 |
| | $ | (22,950 | ) | | 4,155 |
|
PPAs (a) | | | | | | | | | | | | 22,861 |
| | | | | | | | | | | | 22,804 |
|
Current derivative instruments | | | | | | | | | | | | $ | 29,839 |
| | | | | | | | | | | | $ | 26,959 |
|
Noncurrent derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
Commodity trading | | $ | — |
| | $ | 19,898 |
| | $ | — |
| | $ | 19,898 |
| | $ | (9,780 | ) | | $ | 10,118 |
| | $ | 89 |
| | $ | 23,424 |
| | $ | — |
| | $ | 23,513 |
| | $ | (10,727 | ) | | $ | 12,786 |
|
Total noncurrent derivative liabilities | | $ | — |
| | $ | 19,898 |
| | $ | — |
| | $ | 19,898 |
| | $ | (9,780 | ) | | 10,118 |
| | $ | 89 |
| | $ | 23,424 |
| | $ | — |
| | $ | 23,513 |
| | $ | (10,727 | ) | | 12,786 |
|
PPAs (a) | | | | | | | | | | | | 158,193 |
| | | | | | | | | | | | 135,360 |
|
Noncurrent derivative instruments | | | | | | | | | | | | $ | 168,311 |
| | | | | | | | | | | | $ | 148,146 |
|
| |
(a) | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. |
| |
(b) | Xcel Energy 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, 2015.2016. At Dec. 31, 2015,2016, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $4.3$3.7 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 the changes in Level 3 commodity derivatives for the three and nine months ended Sept. 30, 20162017 and 2015:2016:
| | | | | | | | | | |
| | Three Months Ended Sept. 30 | | Three Months Ended Sept. 30 |
(Thousands of Dollars) | | 2016 | | 2015 | | 2017 | | 2016 |
Balance at July 1 | | $ | 24,517 |
| | $ | 46,826 |
| | $ | 69,237 |
| | $ | 24,517 |
|
Purchases | | 274 |
| | 486 |
| | — |
| | 274 |
|
Settlements | | (33,982 | ) | | (20,216 | ) | | (33,144 | ) | | (33,982 | ) |
Net transactions recorded during the period: | | | | |
| | | | |
|
Gains recognized in earnings (a) | | 9 |
| | 121 |
| | 548 |
| | 9 |
|
Gains recognized as regulatory assets and liabilities | | 33,777 |
| | 3,966 |
| |
Net gains recognized as regulatory assets and liabilities | | | 29,212 |
| | 33,777 |
|
Balance at Sept. 30 | | $ | 24,595 |
| | $ | 31,183 |
| | $ | 65,853 |
| | $ | 24,595 |
|
| | | | | | | | |
| | Nine Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
(Thousands of Dollars) | | 2016 | | 2015 | | 2017 | | 2016 |
Balance at Jan. 1 | | $ | 18,028 |
| | $ | 56,155 |
| | $ | 17,253 |
| | $ | 18,028 |
|
Purchases | | 33,296 |
| | 63,724 |
| | 80,073 |
| | 33,296 |
|
Settlements | | (60,707 | ) | | (57,462 | ) | | (75,121 | ) | | (60,707 | ) |
Net transactions recorded during the period: | | | | | | | | |
(Losses) gains recognized in earnings (a) | | (33 | ) | | 1,401 |
| |
Gains (losses) recognized as regulatory assets and liabilities | | 34,011 |
| | (32,635 | ) | |
Gains (losses) recognized in earnings (a) | | | 5,769 |
| | (33 | ) |
Net gains recognized as regulatory assets and liabilities | | | 37,879 |
| | 34,011 |
|
Balance at Sept. 30 | | $ | 24,595 |
| | $ | 31,183 |
| | $ | 65,853 |
| | $ | 24,595 |
|
| |
(a) | These amounts relate to commodity derivatives held at the end of the period. |
Xcel Energy recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three and nine months ended Sept. 30, 20162017 and 2015.2016.
Fair Value of Long-Term Debt
As of Sept. 30, 20162017 and Dec. 31, 2015,2016, other financial instruments for which the carrying amount did not equal fair value were as follows:
| | | | Sept. 30, 2016 | | Dec. 31, 2015 | | Sept. 30, 2017 | | Dec. 31, 2016 |
(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 (a) | | $ | 14,112,150 |
| | $ | 16,127,060 |
| | $ | 13,055,901 |
| | $ | 14,094,744 |
| | $ | 14,878,382 |
| | $ | 16,192,542 |
| | $ | 14,450,247 |
| | $ | 15,513,209 |
|
| |
(a)
| Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2, Accounting Pronouncements for more information on the adoption of ASU 2015-03.
|
The fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of Sept. 30, 20162017 and Dec. 31, 2015,2016, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.
Other income, net consisted of the following:
| | | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
(Thousands of Dollars) | | 2016 | | 2015 | | 2016 | | 2015 | | 2017 | | 2016 | | 2017 | | 2016 |
Interest income | | $ | 1,385 |
| | $ | 312 |
| | $ | 6,439 |
| | $ | 4,939 |
| | $ | 5,772 |
| | $ | 1,385 |
| | $ | 11,679 |
| | $ | 6,439 |
|
Other nonoperating income | | 341 |
| | 625 |
| | 2,517 |
| | 2,387 |
| | — |
| | 341 |
| | 5,013 |
| | 2,517 |
|
Insurance policy (expense) income | | (1,148 | ) | | 689 |
| | (2,568 | ) | | (1,578 | ) | |
Insurance policy expense | | | (528 | ) | | (1,148 | ) | | (2,549 | ) | | (2,568 | ) |
Other nonoperating expense | | | (155 | ) | | — |
| | — |
| | — |
|
Other income, net | | $ | 578 |
| | $ | 1,626 |
| | $ | 6,388 |
| | $ | 5,748 |
| | $ | 5,089 |
| | $ | 578 |
| | $ | 14,143 |
| | $ | 6,388 |
|
The regulated electric utility operating results of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility operating results of NSP-Minnesota, NSP-Wisconsin and PSCo are each separately and regularly reviewed by Xcel Energy’s chief operating decision maker. Xcel Energy evaluates performance by each utility subsidiary 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.
Xcel Energy has the following reportable segments: regulated electric utility, regulated natural gas utility and all other.
Xcel Energy’s regulated electric utility segment generates, transmits and distributes electricity primarily in portions of Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas and New Mexico. 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 commodity trading operations.
Xcel Energy’s regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and 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, nonutility real estate activities, revenues associated with processing solid waste into refuse-derived fuel and investments in rental housing projects that qualify for low-income housing tax credits.
Xcel Energy had equity investments in unconsolidated subsidiaries of $134.5$131.8 million and $130.0$132.8 million as of Sept. 30, 20162017 and Dec. 31, 2015,2016, respectively, included in the regulated natural gas utility segment.
Asset and capital expenditure information is not provided for Xcel Energy’s reportable segments because as an integrated electric and natural gas utility, Xcel Energy operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.
To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.
| | (Thousands of Dollars) | | Regulated Electric | | Regulated Natural Gas | | All Other | | Reconciling Eliminations | | Consolidated Total | | Regulated Electric | | Regulated Natural Gas | | All Other | | Reconciling Eliminations | | Consolidated Total |
Three Months Ended Sept. 30, 2016 | | | | | | | | | | | |
Three Months Ended Sept. 30, 2017 | | | | | | | | | | | |
Operating revenues from external customers | | $ | 2,799,964 |
| | $ | 221,956 |
| | $ | 18,227 |
| | $ | — |
| | $ | 3,040,147 |
| | $ | 2,783,569 |
| | $ | 214,253 |
| | $ | 19,075 |
| | $ | — |
| | $ | 3,016,897 |
|
Intersegment revenues | | 282 |
| | 292 |
| | — |
| | (574 | ) | | — |
| | 351 |
| | 378 |
| | — |
| | (729 | ) | | — |
|
Total revenues | | $ | 2,800,246 |
| | $ | 222,248 |
| | $ | 18,227 |
| | $ | (574 | ) | | $ | 3,040,147 |
| | $ | 2,783,920 |
| | $ | 214,631 |
| | $ | 19,075 |
| | $ | (729 | ) | | $ | 3,016,897 |
|
Net income (loss) | | $ | 479,399 |
| | $ | (5,297 | ) | | $ | (16,307 | ) | | $ | — |
| | $ | 457,795 |
| | $ | 503,058 |
| | $ | 1,853 |
| | $ | (12,770 | ) | | $ | — |
| | $ | 492,141 |
|
| | | | | | | | | | | |
| | (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 Sept. 30, 2015 | | | | | | | | | | | |
Three Months Ended Sept. 30, 2016 | | | | | | | | | | | |
Operating revenues from external customers | | $ | 2,667,480 |
| | $ | 216,019 |
| | $ | 17,813 |
| | $ | — |
| | $ | 2,901,312 |
| | $ | 2,799,964 |
| | $ | 221,956 |
| | $ | 18,227 |
| | $ | — |
| | $ | 3,040,147 |
|
Intersegment revenues | | 392 |
| | 293 |
| | — |
| | (685 | ) | | — |
| | 282 |
| | 292 |
| | — |
| | (574 | ) | | — |
|
Total revenues | | $ | 2,667,872 |
| | $ | 216,312 |
| | $ | 17,813 |
| | $ | (685 | ) | | $ | 2,901,312 |
| | $ | 2,800,246 |
| | $ | 222,248 |
| | $ | 18,227 |
| | $ | (574 | ) | | $ | 3,040,147 |
|
Net income (loss) | | $ | 437,978 |
| | $ | (4,176 | ) | | $ | (7,339 | ) | | $ | — |
| | $ | 426,463 |
| | $ | 479,399 |
| | $ | (5,297 | ) | | $ | (16,307 | ) | | $ | — |
| | $ | 457,795 |
|
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
(Thousands of Dollars) | | Regulated Electric | | Regulated Natural Gas | | All Other | | Reconciling Eliminations | | Consolidated Total |
Nine Months Ended Sept. 30, 2017 | | | | | | | | | | |
Operating revenues from external customers | | $ | 7,420,646 |
| | $ | 1,129,795 |
| | $ | 57,806 |
| | $ | — |
| | $ | 8,608,247 |
|
Intersegment revenues | | 1,081 |
| | 927 |
| | — |
| | (2,008 | ) | | — |
|
Total revenues | | $ | 7,421,727 |
| | $ | 1,130,722 |
| | $ | 57,806 |
| | $ | (2,008 | ) | | $ | 8,608,247 |
|
Net income (loss) | | $ | 924,773 |
| | $ | 77,946 |
| | $ | (44,045 | ) | | $ | — |
| | $ | 958,674 |
|
|
| | | | | | | | | | | | | | | | | | | | |
(Thousands of Dollars) | | Regulated Electric | | Regulated Natural Gas | | All Other | | Reconciling Eliminations | | Consolidated Total |
Nine Months Ended Sept. 30, 2016 | | | | | | | | | | |
Operating revenues from external customers | | $ | 7,209,225 |
| | $ | 1,046,544 |
| | $ | 56,500 |
| | $ | — |
| | $ | 8,312,269 |
|
Intersegment revenues | | 1,038 |
| | 820 |
| | — |
| | (1,858 | ) | | — |
|
Total revenues | | $ | 7,210,263 |
| | $ | 1,047,364 |
| | $ | 56,500 |
| | $ | (1,858 | ) | | $ | 8,312,269 |
|
Net income (loss) | | $ | 863,076 |
| | $ | 84,974 |
| | $ | (52,148 | ) | | $ | — |
| | $ | 895,902 |
|
|
| | | | | | | | | | | | | | | | | | | | |
(Thousands of Dollars) | | Regulated Electric | | Regulated Natural Gas | | All Other | | Reconciling Eliminations | | Consolidated Total |
Nine Months Ended Sept. 30, 2015 | | | | | | | | | | |
Operating revenues from external customers | | $ | 7,105,803 |
| | $ | 1,216,146 |
| | $ | 56,716 |
| | $ | — |
| | $ | 8,378,665 |
|
Intersegment revenues | | 1,142 |
| | 1,141 |
| | — |
| | (2,283 | ) | | — |
|
Total revenues | | $ | 7,106,945 |
| | $ | 1,217,287 |
| | $ | 56,716 |
| | $ | (2,283 | ) | | $ | 8,378,665 |
|
Net income (loss) | | $ | 733,954 |
| (a) | $ | 72,617 |
| | $ | (31,111 | ) | | $ | — |
| | $ | 775,460 |
|
| |
(a)
| Includes a net of tax charge related to the Monticello LCM/EPU project. See Note 5. |
Basic earnings per share (EPS) was computed by dividing the earnings available to Xcel Energy Inc.’s common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS was computed by dividing the earnings available to Xcel Energy Inc.’s common shareholders by the diluted weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method.
Common Stock Equivalents — Xcel Energy Inc. currently has common stock equivalents related to certain equity awards in share-based compensation arrangements.
Common stock equivalents causing a dilutive impact to EPS include commitments to issue common stock related to time based equity compensation awards and time based employer matching contributions to certain 401(k) plan participants.awards.
Stock equivalent units granted to Xcel Energy Inc.’s Board of Directors are included in common shares outstanding upon grant date as there is no further service, performance or market condition associated with these awards. Restricted stock, granted to settle amounts due to certain employees under the Xcel Energy Inc. Executive Annual Incentive Award Plan, is included in common shares outstanding when granted.
Share-based compensation arrangements for which there is currently no dilutive impact to EPS include the following:
Equity awards subject to a performance condition; included in common shares outstanding when all necessary conditions for settlement have been satisfied by the end of the reporting period.
Liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement.
The dilutive impact of common stock equivalents affecting EPS was as follows: |
| | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended Sept. 30, 2017 | | Three Months Ended Sept. 30, 2016 |
(Amounts in thousands, except per share data) | | Income | | Shares | | Per Share Amount | | Income | | Shares | | Per Share Amount |
Net income | | $ | 492,141 |
| | — |
| | — |
| | $ | 457,795 |
| | — |
| | — |
|
Basic EPS: | | |
| | |
| | |
| | |
| | | | |
Earnings available to common shareholders | | 492,141 |
| | 508,581 |
| | $ | 0.97 |
| | 457,795 |
| | 508,941 |
| | $ | 0.90 |
|
Effect of dilutive securities: | | |
| | | | |
| | |
| | |
| | |
|
Time based equity awards | | — |
| | 661 |
| | — |
| | — |
| | 625 |
| | — |
|
Diluted EPS: | | |
| | |
| | |
| | |
| | |
| | |
|
Earnings available to common shareholders | | $ | 492,141 |
| | 509,242 |
| | $ | 0.97 |
| | $ | 457,795 |
| | 509,566 |
| | $ | 0.90 |
|
| | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended Sept. 30, 2016 | | Three Months Ended Sept. 30, 2015 |
(Amounts in thousands, except per share data) | | Income | | Shares | | Per Share Amount | | Income | | Shares | | Per Share Amount |
Net income | | $ | 457,795 |
| | — |
| | — |
| | $ | 426,463 |
| | — |
| | — |
|
Basic EPS: | | | | | | | | | | | | |
Earnings available to common shareholders | | 457,795 |
| | 508,941 |
| | $ | 0.90 |
| | 426,463 |
| | 508,031 |
| | $ | 0.84 |
|
Effect of dilutive securities: | | | | | | | | | | | | |
Time based equity awards | | — |
| | 625 |
| | — |
| | — |
| | 396 |
| | — |
|
Diluted EPS: | | | | | | | | | | | | |
Earnings available to common shareholders | | $ | 457,795 |
| | 509,566 |
| | $ | 0.90 |
| | $ | 426,463 |
| | 508,427 |
| | $ | 0.84 |
|
| | | | Nine Months Ended Sept. 30, 2016 | | Nine Months Ended Sept. 30, 2015 | | Nine Months Ended Sept. 30, 2017 | | Nine Months Ended Sept. 30, 2016 |
(Amounts in thousands, except per share data) | | Income | | Shares | | Per Share Amount | | Income | | Shares | | Per Share Amount | | Income | | Shares | | Per Share Amount | | Income | | Shares | | Per Share Amount |
Net income | | $ | 895,902 |
| | — |
| | — |
| | $ | 775,460 |
| | — |
| | — |
| | $ | 958,674 |
| | — |
| | — |
| | $ | 895,902 |
| | — |
| | — |
|
Basic EPS: | | | | | | | | | | | | | | |
| | |
| | |
| | |
| | | | |
Earnings available to common shareholders | | 895,902 |
| | 508,840 |
| | $ | 1.76 |
| | 775,460 |
| | 507,585 |
| | $ | 1.53 |
| | 958,674 |
| | 508,468 |
| | $ | 1.89 |
| | 895,902 |
| | 508,840 |
| | $ | 1.76 |
|
Effect of dilutive securities: | | | | | | | | | | | | | | |
| | |
| | |
| | |
| | |
| | |
|
Time based equity awards | | — |
| | 556 |
| | — |
| | — |
| | 391 |
| | — |
| | — |
| | 584 |
| | — |
| | — |
| | 556 |
| | — |
|
Diluted EPS: | | | | | | | | | | | | | | |
| | |
| | |
| | |
| | |
| | |
|
Earnings available to common shareholders | | $ | 895,902 |
| | 509,396 |
| | $ | 1.76 |
| | $ | 775,460 |
| | 507,976 |
| | $ | 1.53 |
| | $ | 958,674 |
| | 509,052 |
| | $ | 1.88 |
| | $ | 895,902 |
| | 509,396 |
| | $ | 1.76 |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| |
12. | Benefit Plans and Other Postretirement Benefits |
Components of Net Periodic Benefit Cost (Credit)
| | | | Three Months Ended Sept. 30 | | Three Months Ended Sept. 30 |
| | 2016 | | 2015 | | 2016 | | 2015 | | 2017 | | 2016 | | 2017 | | 2016 |
(Thousands of Dollars) | | Pension Benefits | | Postretirement Health Care Benefits | | Pension Benefits | | Postretirement Health Care Benefits |
Service cost | | $ | 22,940 |
| | $ | 24,828 |
| | $ | 432 |
| | $ | 529 |
| | $ | 23,547 |
| | $ | 22,940 |
| | $ | 465 |
| | $ | 432 |
|
Interest cost | | 40,027 |
| | 37,131 |
| | 6,527 |
| | 6,324 |
| | 36,702 |
| | 40,027 |
| | 5,984 |
| | 6,527 |
|
Expected return on plan assets | | (52,575 | ) | | (53,473 | ) | | (6,249 | ) | | (6,650 | ) | | (52,318 | ) | | (52,575 | ) | | (6,155 | ) | | (6,249 | ) |
Amortization of prior service credit | | (478 | ) | | (451 | ) | | (2,672 | ) | | (2,672 | ) | | (442 | ) | | (478 | ) | | (2,672 | ) | | (2,672 | ) |
Amortization of net loss | | 24,384 |
| | 31,288 |
| | 1,011 |
| | 1,351 |
| | 26,671 |
| | 24,384 |
| | 1,672 |
| | 1,011 |
|
Net periodic benefit cost (credit) | | 34,298 |
| | 39,323 |
| | (951 | ) | | (1,118 | ) | | 34,160 |
| | 34,298 |
| | (706 | ) | | (951 | ) |
Costs not recognized due to the effects of regulation | | (3,976 | ) | | (7,016 | ) | | — |
| | — |
| | (3,610 | ) | | (3,976 | ) | | — |
| | — |
|
Net benefit cost (credit) recognized for financial reporting | | $ | 30,322 |
| | $ | 32,307 |
| | $ | (951 | ) | | $ | (1,118 | ) | | $ | 30,550 |
| | $ | 30,322 |
| | $ | (706 | ) | | $ | (951 | ) |
| | | | | | | | | | | | | | | | |
| | | | Nine Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
| | 2016 | | 2015 | | 2016 | | 2015 | | 2017 | | 2016 | | 2017 | | 2016 |
(Thousands of Dollars) | | Pension Benefits | | Postretirement Health Care Benefits | | Pension Benefits | | Postretirement Health Care Benefits |
Service cost | | $ | 68,805 |
| | $ | 74,484 |
| | $ | 1,295 |
| | $ | 1,587 |
| | $ | 70,641 |
| | $ | 68,805 |
| | $ | 1,395 |
| | $ | 1,295 |
|
Interest cost | | 120,078 |
| | 111,393 |
| | 19,580 |
| | 18,972 |
| | 110,106 |
| | 120,078 |
| | 17,952 |
| | 19,580 |
|
Expected return on plan assets | | (157,725 | ) | | (160,418 | ) | | (18,746 | ) | | (19,950 | ) | | (156,953 | ) | | (157,725 | ) | | (18,466 | ) | | (18,746 | ) |
Amortization of prior service credit | | (1,439 | ) | | (1,353 | ) | | (8,015 | ) | | (8,015 | ) | | (1,326 | ) | | (1,439 | ) | | (8,015 | ) | | (8,015 | ) |
Amortization of net loss | | 73,154 |
| | 93,864 |
| | 3,031 |
| | 4,053 |
| | 80,012 |
| | 73,154 |
| | 5,016 |
| | 3,031 |
|
Net periodic benefit cost (credit) | | 102,873 |
| | 117,970 |
| | (2,855 | ) | | (3,353 | ) | | 102,480 |
| | 102,873 |
| | (2,118 | ) | | (2,855 | ) |
Costs not recognized due to the effects of regulation | | (12,587 | ) | | (22,035 | ) | | — |
| | — |
| | (11,523 | ) | | (12,587 | ) | | — |
| | — |
|
Net benefit cost (credit) recognized for financial reporting | | $ | 90,286 |
| | $ | 95,935 |
| | $ | (2,855 | ) | | $ | (3,353 | ) | | $ | 90,957 |
| | $ | 90,286 |
| | $ | (2,118 | ) | | $ | (2,855 | ) |
In January 2016,2017, contributions of $125.0$150.0 million were made across four of Xcel Energy’s pension plans. Xcel Energy does not expect additional pension contributions during 2016.2017.
| |
13. | Other Comprehensive Income (Loss) |
Changes in accumulated other comprehensive (loss) income, net of tax, for the three and nine months ended Sept. 30, 20162017 and 20152016 were as follows:
| | | | Three Months Ended Sept. 30, 2016 | | Three Months Ended Sept. 30, 2017 |
(Thousands of Dollars) | | Gains and Losses on Cash Flow Hedges | | Unrealized Gains and Losses on Marketable Securities | | Defined Benefit Pension and Postretirement Items | | Total | | Gains and Losses on Cash Flow Hedges | | Unrealized Gains and Losses on Marketable Securities | | Defined Benefit Pension and Postretirement Items | | Total |
Accumulated other comprehensive (loss) income at July 1 | | $ | (52,980 | ) | | $ | 110 |
| | $ | (53,925 | ) | | $ | (106,795 | ) | |
Other comprehensive loss before reclassifications | | (4 | ) | | — |
| | — |
| | (4 | ) | |
Accumulated other comprehensive (loss) income at June 30 | | | $ | (49,497 | ) | | $ | 111 |
| | $ | (57,409 | ) | | $ | (106,795 | ) |
Other comprehensive income before reclassifications | | | 23 |
| | — |
| | — |
| | 23 |
|
Losses reclassified from net accumulated other comprehensive loss | | 960 |
| | — |
| | 878 |
| | 1,838 |
| | 981 |
| | — |
| | 982 |
| | 1,963 |
|
Net current period other comprehensive income | | 956 |
| | — |
| | 878 |
| | 1,834 |
| | 1,004 |
| | — |
| | 982 |
| | 1,986 |
|
Accumulated other comprehensive (loss) income at Sept. 30 | | $ | (52,024 | ) | | $ | 110 |
| | $ | (53,047 | ) | | $ | (104,961 | ) | | $ | (48,493 | ) | | $ | 111 |
| | $ | (56,427 | ) | | $ | (104,809 | ) |
| | | | Three Months Ended Sept. 30, 2015 | | Three Months Ended Sept. 30, 2016 |
(Thousands of Dollars) | | Gains and Losses on Cash Flow Hedges | | Unrealized Gains and Losses on Marketable Securities | | Defined Benefit Pension and Postretirement Items | | Total | | Gains and Losses on Cash Flow Hedges | | Unrealized Gains and Losses on Marketable Securities | | Defined Benefit Pension and Postretirement Items | | Total |
Accumulated other comprehensive (loss) income at July 1 | | $ | (56,436 | ) | | $ | 112 |
| | $ | (48,862 | ) | | $ | (105,186 | ) | |
Accumulated other comprehensive (loss) income at June 30 | | | $ | (52,980 | ) | | $ | 110 |
| | $ | (53,925 | ) | | $ | (106,795 | ) |
Other comprehensive loss before reclassifications | | (42 | ) | | (1 | ) | | — |
| | (43 | ) | | (4 | ) | | — |
| | — |
| | (4 | ) |
Losses reclassified from net accumulated other comprehensive loss | | 706 |
| | — |
| | 884 |
| | 1,590 |
| | 960 |
| | — |
| | 878 |
| | 1,838 |
|
Net current period other comprehensive income (loss) | | 664 |
| | (1 | ) | | 884 |
| | 1,547 |
| |
Net current period other comprehensive income | | | 956 |
| | — |
| | 878 |
| | 1,834 |
|
Accumulated other comprehensive (loss) income at Sept. 30 | | $ | (55,772 | ) | | $ | 111 |
| | $ | (47,978 | ) | | $ | (103,639 | ) | | $ | (52,024 | ) | | $ | 110 |
| | $ | (53,047 | ) | | $ | (104,961 | ) |
|
| | | | | | | | | | | | | | | | |
| | Nine Months Ended Sept. 30, 2016 |
(Thousands of Dollars) | | Gains and Losses on Cash Flow Hedges | | Unrealized Gains and Losses on Marketable Securities | | Defined Benefit Pension and Postretirement Items | | Total |
Accumulated other comprehensive (loss) income at Jan. 1 | | $ | (54,862 | ) | | $ | 110 |
| | $ | (55,001 | ) | | $ | (109,753 | ) |
Other comprehensive income (loss) before reclassifications | | 4 |
| | — |
| | (653 | ) | | (649 | ) |
Losses reclassified from net accumulated other comprehensive loss | | 2,834 |
| | — |
| | 2,607 |
| | 5,441 |
|
Net current period other comprehensive income | | 2,838 |
| | — |
| | 1,954 |
| | 4,792 |
|
Accumulated other comprehensive (loss) income at Sept. 30 | | $ | (52,024 | ) | | $ | 110 |
| | $ | (53,047 | ) | | $ | (104,961 | ) |
| | | | Nine Months Ended Sept. 30, 2015 | | Nine Months Ended Sept. 30, 2017 |
(Thousands of Dollars) | | Gains and Losses on Cash Flow Hedges | | Unrealized Gains and Losses on Marketable Securities | | Defined Benefit Pension and Postretirement Items | | Total | | Gains and Losses on Cash Flow Hedges | | Unrealized Gains on Marketable Securities | | Defined Benefit Pension and Postretirement Items | | Total |
Accumulated other comprehensive (loss) income at Jan. 1 | | $ | (57,628 | ) | | $ | 110 |
| | $ | (50,621 | ) | | $ | (108,139 | ) | | $ | (51,151 | ) | | $ | 110 |
| | $ | (59,313 | ) | | $ | (110,354 | ) |
Other comprehensive (loss) income before reclassifications | | (35 | ) | | 1 |
| | — |
| | (34 | ) | |
Other comprehensive income before reclassifications | | | 49 |
| | 1 |
| | — |
| | 50 |
|
Losses reclassified from net accumulated other comprehensive loss | | 1,891 |
| | — |
| | 2,643 |
| | 4,534 |
| | 2,609 |
| | — |
| | 2,886 |
| | 5,495 |
|
Net current period other comprehensive income | | 1,856 |
| | 1 |
| | 2,643 |
| | 4,500 |
| | 2,658 |
| | 1 |
| | 2,886 |
| | 5,545 |
|
Accumulated other comprehensive (loss) income at Sept. 30 | | $ | (55,772 | ) | | $ | 111 |
| | $ | (47,978 | ) | | $ | (103,639 | ) | | $ | (48,493 | ) | | $ | 111 |
| | $ | (56,427 | ) | | $ | (104,809 | ) |
|
| | | | | | | | | | | | | | | | |
| | Nine Months Ended Sept. 30, 2016 |
(Thousands of Dollars) | | Gains and Losses on Cash Flow Hedges | | Unrealized Gains on Marketable Securities | | Defined Benefit Pension and Postretirement Items | | Total |
Accumulated other comprehensive (loss) income at Jan. 1 | | $ | (54,862 | ) | | $ | 110 |
| | $ | (55,001 | ) | | $ | (109,753 | ) |
Other comprehensive income (loss) before reclassifications | | 4 |
| | — |
| | (653 | ) | | (649 | ) |
Losses reclassified from net accumulated other comprehensive loss | | 2,834 |
| | — |
| | 2,607 |
| | 5,441 |
|
Net current period other comprehensive income | | 2,838 |
| | — |
| | 1,954 |
| | 4,792 |
|
Accumulated other comprehensive (loss) income at Sept. 30 | | $ | (52,024 | ) | | $ | 110 |
| | $ | (53,047 | ) | | $ | (104,961 | ) |
Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 20162017 and 20152016 were as follows: |
| | | | | | | | | |
(Thousands of Dollars) | | Amounts Reclassified from Accumulated Other Comprehensive Loss | |
| | Three Months Ended Sept. 30, 2017 | | Three Months Ended Sept. 30, 2016 | |
Losses (gains) on cash flow hedges: | | | | | |
Interest rate derivatives | | $ | 1,579 |
| (a) | $ | 1,502 |
| (a) |
Vehicle fuel derivatives | | (11 | ) | (b) | 46 |
| (b) |
Total, pre-tax | | 1,568 |
| | 1,548 |
| |
Tax benefit | | (587 | ) | | (588 | ) | |
Total, net of tax | | 981 |
| | 960 |
| |
Defined benefit pension and postretirement losses: | | | | | |
Amortization of net loss | | 1,622 |
| (c) | 1,478 |
| (c) |
Prior service credit | | (58 | ) | (c) | (64 | ) | (c) |
Total, pre-tax | | 1,564 |
| | 1,414 |
| |
Tax benefit | | (582 | ) | | (536 | ) | |
Total, net of tax | | 982 |
| | 878 |
| |
Total amounts reclassified, net of tax | | $ | 1,963 |
| | $ | 1,838 |
| |
|
| | | | | | | | | |
| | Amounts Reclassified from Accumulated Other Comprehensive Loss | |
(Thousands of Dollars) | | Three Months Ended Sept. 30, 2016 | | Three Months Ended Sept. 30, 2015 | |
(Gains) losses on cash flow hedges: | | | | | |
Interest rate derivatives | | $ | 1,502 |
| (a) | $ | 1,118 |
| (a) |
Vehicle fuel derivatives | | 46 |
| (b) | 34 |
| (b) |
Total, pre-tax | | 1,548 |
| | 1,152 |
| |
Tax benefit | | (588 | ) | | (446 | ) | |
Total, net of tax | | 960 |
| | 706 |
| |
Defined benefit pension and postretirement (gains) losses: | | | | | |
Amortization of net loss | | 1,478 |
| (c) | 1,532 |
| (c) |
Prior service credit | | (64 | ) | (c) | (89 | ) | (c) |
Total, pre-tax | | 1,414 |
| | 1,443 |
| |
Tax benefit | | (536 | ) | | (559 | ) | |
Total, net of tax | | 878 |
| | 884 |
| |
Total amounts reclassified, net of tax | | $ | 1,838 |
| | $ | 1,590 |
| |
| | | | Amounts Reclassified from Accumulated Other Comprehensive Loss | | | Amounts Reclassified from Accumulated Other Comprehensive Loss | |
(Thousands of Dollars) | | Nine Months Ended Sept. 30, 2016 | | Nine Months Ended Sept. 30, 2015 | | | Nine Months Ended Sept. 30, 2017 | | Nine Months Ended Sept. 30, 2016 | |
(Gains) losses on cash flow hedges: | | | | | | |
Losses (gains) on cash flow hedges: | | | | | | |
Interest rate derivatives | | $ | 4,470 |
| (a) | $ | 3,013 |
| (a) | | $ | 4,257 |
| (a) | $ | 4,470 |
| (a) |
Vehicle fuel derivatives | | 150 |
| (b) | 88 |
| (b) | | (16 | ) | (b) | 150 |
| (b) |
Total, pre-tax | | 4,620 |
| | 3,101 |
| | | 4,241 |
| | 4,620 |
| |
Tax benefit | | (1,786 | ) | | (1,210 | ) | | | (1,632 | ) | | (1,786 | ) | |
Total, net of tax | | 2,834 |
| | 1,891 |
| | | 2,609 |
| | 2,834 |
| |
Defined benefit pension and postretirement (gains) losses: | | | | | | |
Defined benefit pension and postretirement losses: | | | | | | |
Amortization of net loss | | 4,434 |
| (c) | 4,600 |
| (c) | | 4,868 |
| (c) | 4,434 |
| (c) |
Prior service credit | | (192 | ) | (c) | (268 | ) | (c) | | (177 | ) | (c) | (192 | ) | (c) |
Total, pre-tax | | 4,242 |
| | 4,332 |
| | | 4,691 |
| | 4,242 |
| |
Tax benefit | | (1,635 | ) | | (1,689 | ) | | | (1,805 | ) | | (1,635 | ) | |
Total, net of tax | | 2,607 |
| | 2,643 |
| | | 2,886 |
| | 2,607 |
| |
Total amounts reclassified, net of tax | | $ | 5,441 |
| | $ | 4,534 |
| | | $ | 5,495 |
| | $ | 5,441 |
| |
| |
(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 12 for details regarding these benefit plans. |
Item 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy’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 the related notes to consolidated financial statements. Due to the seasonality of Xcel Energy’s operating results, quarterly financial results are not 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, including our 20162017 and 20172018 earnings per share guidance and assumptions, are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Quarterly Report on Form 10-Q and in other securities filings (including Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2015 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2016, and June 30, 2016)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 Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) 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 Xcel Energy 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 Xcel Energy 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 ofor cost of capital; and employee work force factors.
Financial Review
The only common equity securities that are publicly traded are common shares of Xcel Energy Inc. The diluted earnings and EPS of each subsidiary discussed below do not represent a direct legal interest in the assets and liabilities allocated to such subsidiary but rather represent a direct interest in our assets and liabilities as a whole. Ongoing diluted EPS for Xcel Energy and by subsidiary is a financial measure not recognized under GAAP. Ongoing diluted EPS is calculated by dividing the net income or loss attributable to the controlling interest of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. We use this non-GAAP financial measure to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. We believe this measurement is useful to investors in facilitating period over period comparisons and evaluating or projecting financial results. This non-GAAP financial measure should not be considered as an alternative to measures calculated and reported in accordance with GAAP.
Results of Operations
The following table summarizes diluted EPS for Xcel Energy:
| | | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
Diluted Earnings (Loss) Per Share | | 2016 | | 2015 | | 2016 | | 2015 | | 2017 | | 2016 | | 2017 | | 2016 |
NSP-Minnesota | | | $ | 0.45 |
| | $ | 0.41 |
| | $ | 0.81 |
| | $ | 0.74 |
|
PSCo | | $ | 0.34 |
| | $ | 0.34 |
| | $ | 0.74 |
| | $ | 0.75 |
| | 0.37 |
| | 0.34 |
| | 0.78 |
| | 0.74 |
|
NSP-Minnesota | | 0.41 |
| | 0.35 |
| | 0.74 |
| | 0.65 |
| |
SPS | | 0.13 |
| | 0.12 |
| | 0.24 |
| | 0.21 |
| | 0.13 |
| | 0.13 |
| | 0.25 |
| | 0.24 |
|
NSP-Wisconsin | | 0.05 |
| | 0.05 |
| | 0.11 |
| | 0.13 |
| | 0.04 |
| | 0.05 |
| | 0.12 |
| | 0.11 |
|
Equity earnings of unconsolidated subsidiaries | | 0.01 |
| | 0.01 |
| | 0.04 |
| | 0.03 |
| | 0.01 |
| | 0.01 |
| | 0.03 |
| | 0.04 |
|
Regulated utility(a) | | 0.94 |
| | 0.87 |
| | 1.87 |
| | 1.77 |
| | 1.00 |
| | 0.94 |
| | 1.98 |
| | 1.87 |
|
Xcel Energy Inc. and other | | (0.04 | ) | | (0.03 | ) | | (0.11 | ) | | (0.08 | ) | | (0.03 | ) | | (0.04 | ) | | (0.10 | ) | | (0.11 | ) |
Ongoing diluted EPS | | 0.90 |
| | 0.84 |
| | 1.76 |
| | 1.69 |
| |
Loss on Monticello LCM/EPU project | | — |
| | — |
| | — |
| | (0.16 | ) | |
GAAP diluted EPS | | $ | 0.90 |
| | $ | 0.84 |
| | $ | 1.76 |
| | $ | 1.53 |
| | $ | 0.97 |
| | $ | 0.90 |
| | $ | 1.88 |
| | $ | 1.76 |
|
| |
(a) | Amounts may not add due to rounding. |
Earnings Adjusted for Certain Items (Ongoing Earnings)
Ongoing earnings reflect adjustments to GAAP earnings for certain items. Xcel Energy’s management believes that ongoing earnings provide a meaningful comparison of earnings results and is representative of Xcel Energy’s fundamental core earnings power. Xcel Energy’s management uses ongoing earnings internally for financial planning and analysis, for reporting of results to the Board of Directors, in determining whether performance targets are met for performance-based compensation, and when communicating its earnings outlook to analysts and investors.
For the nine months ended Sept. 30, 2015, GAAP earnings included a $0.16 per share charge related to the Monticello nuclear facility LCM/EPU project, which in total cost $748 million. In March 2015, the MPUC approved full recovery, including a return, on $415 million of the project costs, inclusive of AFUDC, but only allowed recovery of the remaining $333 million of costs with no return on this portion of the investment for years 2015 and beyond. As a result of this decision, Xcel Energy recorded a pre-tax charge of approximately $129 million in the first quarter of 2015. See Note 5 to the consolidated financial statements for further discussion.
Summary of Ongoing Earnings
Xcel Energy — Xcel Energy’s ongoing earnings increased $0.06$0.07 per share for the third quarter of 20162017 and $0.12 per share year-to-date. Earnings for the third quarter of 2017 increased due to higher electric margins to recover infrastructure investments, along with a lower ETR and lower O&M expenses, partially offset by higher depreciation expense and property taxes.
NSP-Minnesota — Earnings increased $0.04 per share for the third quarter of 2017 and $0.07 per share year-to-date. The year-to-date which excludesincrease in earnings reflects electric rate increases, lower ETR and reduced O&M expenses. The decrease in the 2015 adjustment for a charge relatedETR is largely driven by resolution of IRS appeals/audits and an increase in research and experimentation credits. The lower O&M expenses primarily relate to the NSP-Minnesota Monticello LCM/EPU project. Electrictiming of maintenance activities and natural gas margins rose inthe overhauls at various generation facilities and reduced expense for nuclear refueling outages. These positive factors were partially offset by depreciation expense (for additional capital investments, including the Courtenay Wind Farm, and prior year amortization of Minnesota’s excess depreciation reserve) and higher property taxes.
PSCo — Earnings increased $0.03 per share for the third quarter primarilyof 2017 and $0.04 per share year-to-date. The year-to-date increase in earnings, driven by higher retailelectric margins, lower O&M expenses and lower ETR, were partially offset by increased depreciation expense associated with electric and natural gas ratesinvestments. The lower O&M expenses are driven by the timing of maintenance and non-fuel riders to recover our capital investments, alongoverhauls at various generation facilities and the impact of costs associated with higher sales growth. These positive factors and a lower effective tax rate were offset by higher depreciation, operating and maintenance expenses and interest charges.storm damage in 2016.
PSCo—SPS PSCo’s ongoing earnings— Earnings were flat for the third quarter of 20162017 and decreasedincreased $0.01 per share year-to-date. Year-to-date, higher natural gas margins, primarily dueThe year-to-date increase in electric margin was attributable to rate increases in Texas and higher AFUDC wereNew Mexico, partially offset by the impact of unfavorable weather. This increase was largely offset by higher depreciation expense for transmission and distribution investments and timing of O&M expenses, and interest charges.
NSP-Minnesota— NSP-Minnesota’s ongoing earnings increased $0.06 forincluding the third quarter ofprior year deferrals associated with the Texas 2016 and $0.09 per share year-to-date. Year-to-date, higher electric revenues driven by an interim electric rate increase in Minnesota (subject to refund) and non-fuel riders were partially offset by higher depreciation, O&M expenses, interest charges and property taxes.
SPS— SPS’ ongoing earnings increased $0.01 for the third quarter of 2016 and $0.03 per share year-to-date. Year-to-date, higher electric margins and lower O&M expenses were partially offset by an increase in depreciation.case.
NSP-Wisconsin — NSP-Wisconsin’s ongoing earnings were flat Earnings decreased $0.01 per share for the third quarter of 20162017 and decreased $0.02increased $0.01 per share year-to-date. Year-to-date, the positive impact of higher electric revenues, primarilyThe year-to-date change was driven by anincreases in electric rate increase, wasand natural gas rates, partially offset by higher O&M expenses and depreciation.
Xcel Energy Inc. and other — Xcel Energy Inc. and other includes financing costs at the holding company and other items. Ongoing earnings decreased by $0.01 for the third quarter of 2016 and $0.03 per share year-to-date,depreciation expense primarily related to higher long-term debt levels.transmission and distribution investments and the impact of unfavorable weather.
Changes in Diluted EPS
The following table summarizes significant components contributing to the changes in 20162017 EPS compared with the same period in 2015:2016:
|
| | | | | | | | |
Diluted Earnings (Loss) Per Share | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
2015 GAAP diluted EPS | | $ | 0.84 |
| | $ | 1.53 |
|
Loss on Monticello LCM/EPU project | | — |
| | 0.16 |
|
2015 ongoing diluted EPS | | 0.84 |
| | 1.69 |
|
| | | | |
Components of change — 2016 vs. 2015 | | | | |
Higher electric margins (a) | | 0.14 |
| | 0.27 |
|
Lower ETR | | 0.02 |
| | 0.04 |
|
Higher natural gas margins (b) | | 0.01 |
| | 0.03 |
|
Higher depreciation and amortization | | (0.06 | ) | | (0.17 | ) |
Higher interest charges | | (0.02 | ) | | (0.05 | ) |
Higher O&M expenses | | (0.03 | ) | | (0.03 | ) |
Other, net | | — |
| | (0.02 | ) |
2016 GAAP and ongoing diluted EPS | | $ | 0.90 |
| | $ | 1.76 |
|
|
| | | | | | | | |
Diluted Earnings (Loss) Per Share | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
2016 GAAP diluted EPS | | $ | 0.90 |
| | $ | 1.76 |
|
| | | | |
Components of change — 2017 vs. 2016 | | | | |
Higher electric margins | | 0.02 |
| | 0.14 |
|
Lower ETR (a) | | 0.07 |
| | 0.10 |
|
Lower O&M expenses | | 0.06 |
| | 0.07 |
|
Higher natural gas margins | | — |
| | 0.01 |
|
Higher depreciation and amortization | | (0.05 | ) | | (0.16 | ) |
Higher conservation and DSM expenses (offset by higher revenues) | | (0.01 | ) | | (0.03 | ) |
Other, net | | (0.02 | ) | | (0.01 | ) |
2017 GAAP diluted EPS | | $ | 0.97 |
| | $ | 1.88 |
|
(a) Reflects $0.006 and $0.015 attributable to weather for the three and nine months ended Sept. 30, 2016, respectively.
(b) Reflects $0.001 and $(0.007) attributable to weather for the three and nine months ended Sept. 30, 2016, respectively. | |
(a) | Lower ETR includes the impact of an additional $9.6 million and $18.4 million of wind production tax credits (PTCs) for the three and nine months ended Sept. 30, 2017, respectively, which are largely flowed back to customers through electric margin. |
Statement of Income Analysis
The following discussion summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.
Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances and the amount of natural gas or electricity the average customer historically usesused per degree of temperature. Accordingly,Weather deviations in weather from normal levels can affect Xcel Energy’s financial performance.
Degree-day or Temperature-Humidity Index (THI) data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. Heating degree-days (HDD) is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. Cooling degree-days (CDD) is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather.
Normal weather conditions are defined as either the 20-year or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales as defined above to derive the amount of demand associated with the weather impact.sales.
The percentage increase (decrease) in normal and actual HDD, CDD and THI is provided in the following table:
| | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
| 2016 vs. Normal | | 2015 vs. Normal | | 2016 vs. 2015 | | 2016 vs. Normal | | 2015 vs. Normal | | 2016 vs. 2015 | 2017 vs. Normal | | 2016 vs. Normal | | 2017 vs. 2016 | | 2017 vs. Normal | | 2016 vs. Normal | | 2017 vs. 2016 |
HDD | (52.6 | )% | | (57.9 | )% | | 11.1 | % | | (12.7 | )% | | (4.2 | )% | | (8.4 | )% | (16.5 | )% | | (52.6 | )% | | 67.5 | % | | (13.6 | )% | | (12.7 | )% | | (2.2 | )% |
CDD | 11.0 |
| | 15.1 |
| | (3.1 | ) | | 8.3 |
| | 5.4 |
| | 3.3 |
| 5.3 |
| | 11.0 |
| | (4.5 | ) | | 5.9 |
| | 8.3 |
| | (1.8 | ) |
THI | 6.5 |
| | 4.3 |
| | 3.2 |
| | 8.6 |
| | (1.6 | ) | | 11.2 |
| (11.6 | ) | | 6.5 |
| | (17.5 | ) | | (10.6 | ) | | 8.6 |
| | (18.5 | ) |
Weather — The following table summarizes the estimated impact of temperature variations on EPS compared with sales under normal weather conditions:
| | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
| 2016 vs. Normal | | 2015 vs. Normal | | 2016 vs. 2015 | | 2016 vs. Normal | | 2015 vs. Normal | | 2016 vs. 2015 | 2017 vs. Normal | | 2016 vs. Normal | | 2017 vs. 2016 | | 2017 vs. Normal | | 2016 vs. Normal | | 2017 vs. 2016 |
Retail electric | $ | 0.016 |
| (a) | $ | 0.010 |
| | $ | 0.006 |
| | $ | 0.011 |
| (a) | $ | (0.004 | ) | | $ | 0.015 |
| $ | (0.011 | ) | | $ | 0.024 |
| | $ | (0.035 | ) | | $ | (0.032 | ) | | $ | 0.020 |
| | $ | (0.052 | ) |
Firm natural gas | (0.001 | ) | | (0.002 | ) | | 0.001 |
| | (0.014 | ) | | (0.007 | ) | | (0.007 | ) | — |
| | (0.001 | ) | | 0.001 |
| | (0.020 | ) | | (0.014 | ) | | (0.006 | ) |
Total | $ | 0.015 |
| | $ | 0.008 |
| | $ | 0.007 |
| | $ | (0.003 | ) | | $ | (0.011 | ) | | $ | 0.008 |
| |
Total (excluding decoupling) | | $ | (0.011 | ) | | $ | 0.023 |
| | $ | (0.034 | ) | | $ | (0.052 | ) | | $ | 0.006 |
| | $ | (0.058 | ) |
Decoupling – Minnesota | | 0.015 |
| | (0.008 | ) | | 0.023 |
| | 0.023 |
| | (0.009 | ) | | 0.032 |
|
Total (adjusted for recovery from decoupling) | | $ | 0.004 |
| | $ | 0.015 |
| | $ | (0.011 | ) | | $ | (0.029 | ) | | $ | (0.003 | ) | | $ | (0.026 | ) |
| |
(a)
| Excludes $0.008 and $0.009 favorable weather impact due to electric sales decoupling at NSP-Minnesota for the three and nine months ended Sept. 30, 2016, respectively. |
Sales Growth (Decline) — The following tables summarize Xcel Energy and its subsidiaries’ sales growth (decline) for actual and weather-normalized sales in 20162017 compared to the same period in 2015:2016:
| | | | Three Months Ended Sept. 30 | | Three Months Ended Sept. 30 |
| | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy | | NSP-Minnesota | | PSCo | | SPS | | NSP-Wisconsin | | Xcel Energy |
Actual | | | | | | | | | | | | | | | | | | | | |
Electric residential (a) | | 5.6 | % | | 4.7 | % | | 1.5 | % | | 2.8 | % | | 4.4 | % | | (6.8 | )% | | (2.5 | )% | | (7.4 | )% | | (6.9 | )% | | (5.3 | )% |
Electric commercial and industrial | | 0.1 |
| | 0.8 |
| | 3.6 |
| | — |
| | 1.2 |
| | (2.7 | ) | | 0.8 |
| | (1.0 | ) | | 1.5 |
| | (0.9 | ) |
Total retail electric sales | | 2.0 |
| | 2.0 |
| | 3.2 |
| | 0.7 |
| | 2.2 |
| | (3.9 | ) | | (0.3 | ) | | (2.5 | ) | | (0.8 | ) | | (2.2 | ) |
Firm natural gas sales | | 3.5 |
| | (5.0 | ) | | N/A |
| | (12.8 | ) | | (0.2 | ) | | 8.5 |
| | 4.7 |
| | N/A |
| | 11.4 |
| | 6.2 |
|
| | | | Three Months Ended Sept. 30 | | Three Months Ended Sept. 30 |
| | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy | | NSP-Minnesota | | PSCo | | SPS | | NSP-Wisconsin | | Xcel Energy |
Weather-normalized | | | | | | | | | | | | | | | | | | | | |
Electric residential (a) | | 4.8 | % | | 2.0 | % | | 1.0 | % | | 1.0 | % | | 2.8 | % | | (1.5 | )% | | (3.0 | )% | | (2.0 | )% | | (0.4 | )% | | (2.1 | )% |
Electric commercial and industrial | | 0.5 |
| | 0.2 |
| | 3.4 |
| | (0.2 | ) | | 1.0 |
| | (1.9 | ) | | 0.7 |
| | 0.3 |
| | 3.0 |
| | (0.2 | ) |
Total retail electric sales | | 2.1 |
| | 0.8 |
| | 3.1 |
| | — |
| | 1.6 |
| | (1.8 | ) | | (0.6 | ) | | (0.3 | ) | | 2.0 |
| | (0.8 | ) |
Firm natural gas sales | | (1.6 | ) | | (4.9 | ) | | N/A |
| | (12.9 | ) | | (3.2 | ) | | 6.9 |
| | (0.6 | ) | | N/A |
| | 9.6 |
| | 2.1 |
|
|
| | | | | | | | | | | | | | | |
| | Nine Months Ended Sept. 30 |
| | NSP-Minnesota | | PSCo | | SPS | | NSP-Wisconsin | | Xcel Energy |
Actual | | | | | | | | | | |
Electric residential (a) | | (3.3 | )% | | (1.9 | )% | | (4.4 | )% | | (2.7 | )% | | (2.9 | )% |
Electric commercial and industrial | | (1.6 | ) | | 0.6 |
| | 0.7 |
| | 1.5 |
| | (0.2 | ) |
Total retail electric sales | | (2.1 | ) | | (0.2 | ) | | (0.4 | ) | | 0.3 |
| | (1.0 | ) |
Firm natural gas sales | | 4.4 |
| | (5.5 | ) | | N/A |
| | 4.5 |
| | (1.9 | ) |
| | | | Nine Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
| | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy | | NSP-Minnesota | | PSCo | | SPS | | NSP-Wisconsin | | Xcel Energy |
Actual | | | | | | | | | | | |
Weather-normalized | | | | | | | | | | | |
Electric residential (a) | | 4.2 | % | | 1.7 | % | | (1.7 | )% | | (0.5 | )% | | 1.9 | % | | (0.5 | )% | | (1.5 | )% | | (1.7 | )% | | 0.4 | % | | (1.0 | )% |
Electric commercial and industrial | | (0.7 | ) | | (0.3 | ) | | 1.6 |
| | (0.3 | ) | | — |
| | (1.0 | ) | | 0.7 |
| | 1.0 |
| | 2.1 |
| | 0.2 |
|
Total retail electric sales | | 0.9 |
| | 0.3 |
| | 1.0 |
| | (0.5 | ) | | 0.6 |
| | (0.9 | ) | | — |
| | 0.3 |
| | 1.6 |
| | (0.2 | ) |
Firm natural gas sales | | 3.2 |
| | (9.0 | ) | | N/A |
| | (12.5 | ) | | (1.8 | ) | | 4.4 |
| | (1.0 | ) | | N/A |
| | 4.0 |
| | 1.0 |
|
|
| | | | | | | | | | | | | | | |
| | Nine Months Ended Sept. 30 |
| | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy |
Weather-normalized | | | | | | | | | | |
Electric residential (a) | | 3.4 | % | | 0.6 | % | | (1.2 | )% | | (0.3 | )% | | 1.3 | % |
Electric commercial and industrial | | (0.7 | ) | | (0.7 | ) | | 1.2 |
| | (0.4 | ) | | (0.3 | ) |
Total retail electric sales | | 0.7 |
| | (0.3 | ) | | 0.8 |
| | (0.5 | ) | | 0.2 |
|
Firm natural gas sales | | 0.9 |
| | (0.6 | ) | | N/A |
| | (4.7 | ) | | — |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended Sept. 30 (Excluding Leap Day) (b) | | Nine Months Ended Sept. 30 (Excluding Leap Day) (b) |
| | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy | | NSP-Minnesota | | PSCo | | SPS | | NSP-Wisconsin | | Xcel Energy |
Weather-normalized - adjusted for leap day | | | | | | | | | | | | | | | | | | | | |
Electric residential (a) | | 3.0 | % | | 0.2 | % | | (1.6 | )% | | (0.7 | )% | | 0.9 | % | | (0.2 | )% | | (1.2 | )% | | (1.3 | )% | | 0.8 | % | | (0.6 | )% |
Electric commercial and industrial | | (1.1 | ) | | (1.1 | ) | | 0.8 |
| | (0.7 | ) | | (0.6 | ) | | (0.7 | ) | | 1.0 |
| | 1.3 |
| | 2.4 |
| | 0.6 |
|
Total retail electric sales | | 0.3 |
| | (0.7 | ) | | 0.4 |
| | (0.8 | ) | | (0.2 | ) | | (0.5 | ) | | 0.3 |
| | 0.7 |
| | 1.9 |
| | 0.2 |
|
Firm natural gas sales | | 0.1 |
| | (1.4 | ) | | N/A |
| | (5.4 | ) | | (0.7 | ) | | 5.3 |
| | (0.3 | ) | | N/A |
| | 4.8 |
| | 1.8 |
|
| |
(a) | Extreme weather variations, and additional factors such as windchill and cloud cover may not be reflected in weather-normalized and actual growth estimates. |
| |
(b) | The estimated impact of the 2016 leap day is excluded to present a more comparable year-over-year presentation. The estimated impact of the additional day of sales in 2016 was approximately 30-40 basis points for retail electric and 70-80 basis points for firm natural gas for the nine months ended Sept. 30, 2016.ended. |
Weather-normalized Electric Sales Growth (Decline) — Year-To-Date (ExcludingExcluding Leap Day)Day
NSP-Minnesota’s residential sales decrease was a result of lower use per customer, partially offset by customer growth. The decline in commercial and industrial (C&I) sales was largely due to reduced usage, which offset an increase in the number of customers. Declines in services offset increased sales to large customers in manufacturing and energy industries.
PSCo’s decline in residential sales reflects lower use per customer, partially offset by customer additions. C&I growth reflectswas mainly due to an increased number ofincrease in customers and higher use per customer. The commercial and industrial (C&I) decline was mainly due to lower sales to certainfor large C&I customers that support the mining, oil and natural gas industries. The decline wasindustries, which were partially offsetreduced by an increase inlower use for the number of small C&I customers.
NSP-Minnesota’s residential sales growth reflects customer additions, partially offset by lower use per customer. C&I sales declined primarily as a result of lower use by small and large customers in the manufacturing industry.class.
SPS’ residential sales decline was primarily the result offell largely due to lower use per customer. The increase in C&I sales wasreflects customer additions and greater use per customer driven by the oil and natural gas productionindustry in the Southeastern New Mexico, Permian Basin area as well as greater use by agricultural customers.Basin.
NSP-Wisconsin’s residential sales decreaseincrease was primarily attributable to lowerhigher use per customer partially offset byand customer additions. The C&I declinegrowth was largely due to reducedhigher use per customer and an increase in sales to small customers in the sand mining industry. The overall decrease was partially offset by an increaseindustry and large customers in the number of largeenergy and small C&I customers as well as greater use per customer in the large C&I class for the oil and gasmanufacturing industries.
Weather-normalized Natural Gas Sales DeclineGrowth (Decline) — Year-To-Date (ExcludingExcluding Leap Day)
Day
Across natural gasmost service territories, lowerhigher natural gas sales reflect a decline in customer use, partially offset by a slightan increase in the number of customers.customers, partially offset by a decline in customer use.
Electric Revenues and Margin
Electric revenues and fuel and purchased power expenses are largely impacted by the fluctuationfluctuations in the price of natural gas, coal and uranium 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:
| | | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
(Millions of Dollars) | | 2016 | | 2015 | | 2016 | | 2015 | | 2017 | | 2016 | | 2017 | | 2016 |
Electric revenues | | $ | 2,800 |
| | $ | 2,667 |
| | $ | 7,209 |
| | $ | 7,106 |
| | $ | 2,784 |
| | $ | 2,800 |
| | $ | 7,421 |
| | $ | 7,209 |
|
Electric fuel and purchased power | | (1,037 | ) | | (1,015 | ) | | (2,755 | ) | | (2,870 | ) | | (1,006 | ) | | (1,037 | ) | | (2,850 | ) | | (2,755 | ) |
Electric margin | | $ | 1,763 |
| | $ | 1,652 |
| | $ | 4,454 |
| | $ | 4,236 |
| | $ | 1,778 |
| | $ | 1,763 |
| | $ | 4,571 |
| | $ | 4,454 |
|
The following tables summarize the components of the changes in electric revenues and electric margin:
Electric Revenues
| | (Millions of Dollars) | | Three Months Ended Sept. 30 2016 vs. 2015 | | Nine Months Ended Sept. 30 2016 vs. 2015 | | Three Months Ended Sept. 30 2017 vs. 2016 | | Nine Months Ended Sept. 30 2017 vs. 2016 |
Retail rate increases (a) | | $ | 59 |
| | $ | 132 |
| |
Transmission revenue | | 16 |
| | 53 |
| |
Retail rate increases (Texas, Minnesota, New Mexico and Wisconsin) | | | $ | 25 |
| | $ | 102 |
|
Trading | | | 8 |
| | 50 |
|
Non-fuel riders | | | 19 |
| | 39 |
|
Higher conservation and DSM revenues (offset by higher expenses) | | | 10 |
| | 24 |
|
Decoupling (weather portion - Minnesota) | | | 17 |
| | 24 |
|
Fuel and purchased power cost recovery | | | (55 | ) | | 1 |
|
Wholesale transmission revenue | | | (12 | ) | | — |
|
Estimated impact of weather | | 11 |
| | 19 |
| | (26 | ) | | (39 | ) |
Non-fuel riders | | 8 |
| | 16 |
| |
Retail sales growth, excluding weather impact | | 18 |
| | 15 |
| |
Conservation incentive | | 7 |
| | 7 |
| | (8 | ) | | (12 | ) |
Fuel and purchased power cost recovery | | 7 |
| | (141 | ) | |
Weather decoupling-Minnesota | | (6 | ) | | (7 | ) | |
PSCo earnings test refund | | 5 |
| | (1 | ) | |
Other, net | | 8 |
| | 10 |
| | 6 |
| | 23 |
|
Total increase in electric revenues | | $ | 133 |
| | $ | 103 |
| |
Total (decrease) increase in electric revenues | | | $ | (16 | ) | | $ | 212 |
|
| |
(a)
| Increase is primarily related to interim rates in Minnesota (subject to and net of estimated provision for refund) and final rates in Wisconsin. |
Electric Margin
| | (Millions of Dollars) | | Three Months Ended Sept. 30 2016 vs. 2015 | | Nine Months Ended Sept. 30 2016 vs. 2015 | | Three Months Ended Sept. 30 2017 vs. 2016 | | Nine Months Ended Sept. 30 2017 vs. 2016 |
Retail rate increases (a) | | $ | 59 |
| | $ | 132 |
| |
Retail rate increases (Texas, Minnesota, New Mexico and Wisconsin) | | | $ | 25 |
| | $ | 102 |
|
Non-fuel riders | | | 19 |
| | 39 |
|
Higher conservation and DSM revenues (offset by higher expenses) | | | 10 |
| | 24 |
|
Decoupling (weather portion - Minnesota) | | | 17 |
| | 24 |
|
Estimated impact of weather | | 11 |
| | 19 |
| | (26 | ) | | (39 | ) |
Non-fuel riders | | 8 |
| | 16 |
| |
Retail sales growth, excluding weather impact | | 18 |
| | 15 |
| |
Transmission revenue, net of costs | | 1 |
| | 13 |
| |
Wholesale transmission revenue, net of costs | | | (24 | ) | | (37 | ) |
Conservation incentive | | 7 |
| | 7 |
| | (8 | ) | | (12 | ) |
Weather decoupling-Minnesota | | (6 | ) | | (7 | ) | |
PSCo earnings test refund | | 5 |
| | (1 | ) | |
Other, net | | 8 |
| | 24 |
| | 2 |
| | 16 |
|
Total increase in electric margin | | $ | 111 |
| | $ | 218 |
| | $ | 15 |
| | $ | 117 |
|
| |
(a)
| Increase is primarily due to interim rates in Minnesota (subject to and net of estimated provision for refund) and final rates in Wisconsin. |
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 for sales to retail customers, fluctuations in the cost of natural gas has minimal impact on natural gas margin.margin due to natural gas cost recovery mechanisms. The following table details natural gas revenues and margin:
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
(Millions of Dollars) | | 2016 | | 2015 | | 2016 | | 2015 |
Natural gas revenues | | $ | 222 |
| | $ | 216 |
| | $ | 1,047 |
| | $ | 1,216 |
|
Cost of natural gas sold and transported | | (68 | ) | | (66 | ) | | (470 | ) | | (665 | ) |
Natural gas margin | | $ | 154 |
| | $ | 150 |
| | $ | 577 |
| | $ | 551 |
|
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
(Millions of Dollars) | | 2017 | | 2016 | | 2017 | | 2016 |
Natural gas revenues | | $ | 214 |
| | $ | 222 |
| | $ | 1,130 |
| | $ | 1,047 |
|
Cost of natural gas sold and transported | | (64 | ) | | (68 | ) | | (543 | ) | | (470 | ) |
Natural gas margin | | $ | 150 |
| | $ | 154 |
| | $ | 587 |
| | $ | 577 |
|
The following tables summarize the components of the changes in natural gas revenues and natural gas margin:
Natural Gas Revenues
| | (Millions of Dollars) | | Three Months Ended Sept. 30 2016 vs. 2015 | | Nine Months Ended Sept. 30 2016 vs. 2015 | | Three Months Ended Sept. 30 2017 vs. 2016 | | Nine Months Ended Sept. 30 2017 vs. 2016 |
Purchased natural gas adjustment clause recovery | | $ | (3 | ) | | $ | (200 | ) | | $ | (4 | ) | | $ | 72 |
|
Retail rate increases (a) | | 8 |
| | 32 |
| |
Infrastructure and integrity riders | | | (1 | ) | | 11 |
|
Estimated impact of weather | | | 1 |
| | (4 | ) |
Other, net | | 1 |
| | (1 | ) | | (4 | ) | | 4 |
|
Total increase (decrease) in natural gas revenues | | $ | 6 |
| | $ | (169 | ) | |
Total (decrease) increase in natural gas revenues | | | $ | (8 | ) | | $ | 83 |
|
| |
| Increase is primarily related to final rates in Colorado. |
Natural Gas Margin
| | (Millions of Dollars) | | Three Months Ended Sept. 30 2016 vs. 2015 | | Nine Months Ended Sept. 30 2016 vs. 2015 | | Three Months Ended Sept. 30 2017 vs. 2016 | | Nine Months Ended Sept. 30 2017 vs. 2016 |
Retail rate increases (a) | | $ | 8 |
| | $ | 32 |
| |
Infrastructure and integrity riders | | | $ | (1 | ) | | $ | 11 |
|
Estimated impact of weather | | — |
| | (5 | ) | | 1 |
| | (4 | ) |
Non-fuel riders | | (3 | ) | | (5 | ) | |
Other, net | | (1 | ) | | 4 |
| | (4 | ) | | 3 |
|
Total increase in natural gas margin | | $ | 4 |
| | $ | 26 |
| |
Total (decrease) increase in natural gas margin | | | $ | (4 | ) | | $ | 10 |
|
| |
(a)
| Increase is primarily related to final rates in Colorado. |
Non-Fuel Operating Expenses and Other Items
O&M Expenses — O&M expenses increased $24.0decreased $48.5 million, or 4.28.2 percent, for the third quarter of 20162017 and $18.3$58.3 million, or 1.03.3 percent, foryear-to-date. The significant changes are summarized in the nine months ended Sept. 30, 2016 compared with the same periods in 2015. The year-to-date increase was mainlytable below:
|
| | | | | | | | |
(Millions of Dollars) | | Three Months Ended Sept. 30 2017 vs. 2016 | | Nine Months Ended Sept. 30 2017 vs. 2016 |
Plant generation costs | | $ | (4.5 | ) | | $ | (33.9 | ) |
Nuclear plant operations and amortization | | (11.0 | ) | | (17.3 | ) |
Electric distribution costs | | (16.0 | ) | | (10.7 | ) |
Transmission costs | | (3.1 | ) | | (9.9 | ) |
Employee benefits expense | | (7.0 | ) | | 9.7 |
|
Texas 2016 electric rate case cost deferral | | — |
| | 7.9 |
|
Other, net | | (6.9 | ) | | (4.1 | ) |
Total decrease in O&M expenses | | $ | (48.5 | ) | | $ | (58.3 | ) |
Plant generation costs decreased primarily due to additional maintenance activities and storm related costs, which were partially offset by a reduction in the timing of planned maintenance and scopeoverhauls at a number of generation facilities;
Nuclear plant outagesoperations and discovery work.amortization expenses are lower mostly due to savings initiatives and reduced refueling outage costs;
Electric distribution costs declined as a result of storm damage expense incurred in 2016; and
Transmission costs decreased mostly due to the timing of transmission line maintenance.
Conservation and Demand Side Management (DSM) ProgramDSM Expenses — Conservation and DSM program expenses increased $6.6$9.8 million, or 11.515.4 percent, for the third quarter of 20162017 and $12.0$28.9 million, or 7.316.3 percent, for the nine months ended Sept. 30, 2016 compared with the same periods in 2015. Increases were primarily attributableyear-to-date. The increase was due to morehigher recovery rates and additional customer participation in DSMelectric conservation programs, which has led to additional customer rebatesmostly in Minnesota. Conservation and increased program implementation costs. Higher conservation and DSM program expenses are generally offset by higher revenues duerecovered in our major jurisdictions concurrently through riders and base rates. Timing of recovery may not correspond to recovery mechanisms.the period in which costs were incurred.
Depreciation and Amortization — Depreciation and amortization increased $48.4$42.6 million, or 17.313.0 percent, for the third quarter of 20162017 and $143.2$131.0 million, or 17.313.5 percent, for the nine months ended Sept. 30, 2016 compared with the same periods in 2015. Increases wereyear-to-date. The increase was primarily attributabledue to capital investments, including Pleasant Valleythe Courtenay Wind Farm, a new enterprise resource planning system and Border Wind Farms, reductionprior year amortization of the excess depreciation reserve in Minnesota and the full amortization of the DOE settlement in 2015.Minnesota.
Taxes (Other Thanthan Income Taxes) — Taxes (other than income taxes) decreased $5.9increased $16.4 million, or 4.814.0 percent for the third quarter of 20162017 and increased $11.5$9.6 million, or 3.02.4 percent for the nine months ended Sept. 30, 2016 compared with the same periods in 2015.year-to-date. The year-to-date increase was primarily due to higher property taxes in Minnesota, excludingMinnesota.
AFUDC, Equity and Debt — Allowance for funds used during construction (AFUDC) increased $9.5 million for the impactthird quarter of 2017 and $14.3 million year-to-date. The increase was primarily due to higher construction work in progress, particularly the proposed settlement agreement in the Minnesota 2016 multi-year electric rate case.Rush Creek wind project.
Interest Charges — Interest charges increased $13.3$1.9 million, or 8.71.2 percent, for the third quarter of 20162017 and $43.6$12.7 million, or 9.92.6 percent, for the nine months ended Sept. 30, 2016 compared with the same periods in 2015. Increases wereyear-to-date. The increase was related to higher long-term debt levels to fund capital investments, partially offset by refinancings at lower interest rates.
Income Taxes —Income tax expense decreased $0.6$33.6 million for the third quarter and $47.6 million for the first nine months of 20162017, compared withto the same periodperiods in 2015.2016. The decrease was primarily due to increasednet tax benefits related to an increase in wind production taxPTCs, the resolution of past appeals/audits, and an increase in research and experimentation credits in 2016, partially offset by higher pretax earnings in 2016.credits. The ETR was 34.229.4 percent for the third quarter of 20162017 compared with 35.934.2 percent for the same period in 2015.2016 and 30.7 percent for the first nine months of 2017, compared to 34.5 percent for the first nine months of 2016. The lower ETR in 2016 is2017 was primarily due to the adjustments referenced above.
Income tax expense increased $39.0 million for the first nine months of 2016 compared with the same period in 2015. The increase in income tax expense was primarily due to higher pretax earnings, partially offset by increased wind production tax and research and experimentation credits. The ETR was 34.5 percent for the first nine months of 2016 compared with 35.8 percent for the same period in 2015. The lower ETR in 2016 is primarily due to the adjustments referenced above.
Public Utility Regulation
Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 1 of Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 20152016 and Public Utility Regulation included in Item 2 of Xcel Energy Inc.’s
Quarterly ReportsReport on Form 10-Q for the quarterly periods ended March 31, 20162017 and June 30, 2016,2017, appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.
NSP-MinnesotaXcel Energy Inc.
NSP Resource PlansWind Development —Xcel Energy plans to significantly expand its wind capacity at NSP-Minnesota, PSCo and SPS. The CPUC approved the Rush Creek wind project in 2016. In January 2015, NSP-Minnesota filed its 2016-2030 Integrated Resource Plan (the Plan) withJuly 2017, the MPUC.
Subsequently, NSP-Minnesota proposed revisionsMPUC approved NSP-Minnesota’s proposal to the Plan, which addressed stakeholder recommendations as well as the Clean Power Plan issued by the EPA. The revised plan was based on four primary elements: (1) accelerate the transition from coal energy to renewables, (2) preserve regional system reliability, (3) pursue energy efficiency gains and grid modernization, and (4) ensure customer benefits. The revised plan includes substantial opportunities for NSP-Minnesotaadd 1,550 MW of new wind generation, including ownership of renewable1,150 MW of wind generation and would result in 63 percent of NSP System energy being carbon-free by 2030 and a 60 percent reduction in carbon emissions from 2005 levels by 2030.
Specific terms of the proposal include:NSP-Minnesota.
The addition of 1,800 MW ofPUCT and NMPRC are expected to rule on SPS’ wind and 1,400 MW of solar between 2016-2030, including approximately 650 MW of solar from NSP-Minnesota’s community solar gardens program by 2020;
The retirement of Sherco Unit 2 in 2023 and Sherco Unit 1 in 2026;
Partial replacement of Sherco coal generation with a 786 MW natural gas combined cycle unit at the Sherco site to coincide with the Unit 1 retirement;
The addition of a 230 MW natural gas combustion turbine in North Dakotaprojects by the end of 2025;
Operationthe first quarter of 2018. Hearings in Texas with the Monticello and PI nuclear plantsPUCT are scheduled for Nov. 6 through their current license periodsNov. 17, 2017. Hearings in New Mexico with the early 2030’s - and a commitment to provide additional information regarding forecasted cost increases at PINMPRC are scheduled for Nov. 28 through end of licensed life if the MPUC wishes to further explore alternatives to operating PI through its current license periods.
Dec. 1, 2017.
In October 2016,September 2017, NSP-Minnesota filed with the MPUC verballyseeking approval to build and own the Dakota Range project, a 300 MW wind project in South Dakota. The project is projected to be placed into service by the end of 2021 to qualify for 80 percent of the PTC. NSP-Minnesota has requested that the MPUC approve the proposed wind project by March 2018.
These wind projects (with the exception of the Dakota Range project) would qualify for 100 percent of the PTC and are expected to provide billions of dollars of savings to Xcel Energy’s customers and substantial environmental benefits. Projected savings/benefits assume fuel costs and generation mix consistent with various commission approved NSP-Minnesota’s plan, with modifications as follows:resource plans.
The acquisition of at least 1,000 MW offollowing table details these wind by 2019, with additional acquisitions dependent on considerations such as price, bidder qualifications, rate impact, transmission availability and location;projects:
The acquisition of 650 MW of solar before 2021 through the community solar gardens program or other acquisitions - and pursuit of additional, cost-effective solar resources if it is in the best interests of its customers;Determination of the proper mix of purchased power and Company-owned renewable resources shall be made during the resource acquisition process; |
| | | | | | | | | | | |
Project Name | | Capacity (MW) | | State | | Estimated Year of Completion | | Ownership/PPA | | Regulatory Status |
Rush Creek | | 600 |
| | CO | | 2018 | | PSCo | | Approved by CPUC |
Freeborn | | 200 |
| | MN/IA | | 2020 | | NSP-Minnesota | | Approved by MPUC |
Blazing Star 1 | | 200 |
| | MN | | 2019 | | NSP-Minnesota | | Approved by MPUC |
Blazing Star 2 | | 200 |
| | MN | | 2020 | | NSP-Minnesota | | Approved by MPUC |
Lake Benton | | 100 |
| | MN | | 2019 | | NSP-Minnesota | | Approved by MPUC |
Foxtail | | 150 |
| | ND | | 2019 | | NSP-Minnesota | | Approved by MPUC |
Crowned Ridge | | 300 |
| | SD | | 2019 | | NSP-Minnesota | | Approved by MPUC |
Dakota Range | | 300 |
| | SD | | 2021 | | NSP-Minnesota | | Pending MPUC Approval |
Hale | | 478 |
| | TX | | 2019 | | SPS | | Pending PUCT & NMPRC Approval |
Sagamore | | 522 |
| | NM | | 2020 | | SPS | | Pending PUCT & NMPRC Approval |
Total Ownership | | 3,050 |
| | | | | | | | |
| | | | | | | | | | |
Crowned Ridge | | 300 |
| | SD | | 2019 | | PPA | | Approved by MPUC |
Clean Energy 1 | | 100 |
| | ND | | 2019 | | PPA | | Approved by MPUC |
Bonita | | 230 |
| | TX | | 2019 | | PPA | | Pending PUCT & NMPRC Approval |
Total PPA | | 630 |
| | | | | | | | |
Total Wind Capacity | | 3,680 |
| | | | | | | | |
Retirement of Sherco Unit 2 in 2023 and Sherco Unit 1 in 2026, and a finding that more likely than not, there will be a need for approximately 750 MW of capacity coinciding with the retirement of Sherco Unit 1 in 2026;
Authorization forNSP-Minnesota
PPA Terminations and Amendments — In June and July 2017, NSP-Minnesota to file a petition for a certificate of need to select the resource that best meets the system resource and local reliability needs associatedfiled requests with the retirement of Sherco Unit 1 in 2026;
Acquisition of no less than 400 MW of additional demand response by 2023; and
Submission of NSP-Minnesota’s next Resource Plan by February 2019.MPUC and/or the NDPSC for several initiatives including changes to four PPAs to reduce future costs for customers. These actions include the following:
The MPUC’s ordertermination of a PPA with Benson Power LLC (Benson) for its 55 MW biomass facility in Benson, Minn., including the purchase and closure of the facility. The purchase of the Benson biomass facility requires FERC approval, which was requested in August 2017. The transaction would result in payments of $95 million to terminate the PPA and acquire the facility, as well as additional expenditures of approximately $26 million to temporarily operate then close the facility.
The termination of a PPA with Laurentian Energy Authority I, LLC (Laurentian) for its 35 MW of biomass facilities in Hibbing and Virginia, Minn. The termination of the Laurentian PPA would result in $108.5 million of contract cancellation payments over six years.
The remaining two requested PPA changes involve a PPA extension for a 34 MW waste-to-energy facility at a price reflective of current market conditions and termination of another 12 MW waste-to-energy PPA.
NSP-Minnesota has requested recovery of all costs associated with these changes through the Fuel Clause Adjustment (FCA), including a return on NSP-Minnesota’s Resource Plan is expectedtotal investment in late 2016.the Benson transaction over the remaining life of the current PPA through 2028. NSP-Minnesota and NSP-Wisconsin will jointly request FERC approval to modify the Interchange Agreement to share a portion of the cost with NSP-Wisconsin. If approved, these actions together are intended to provide approximately $653 million in net cost savings to NSP System customers over the next 10 years.
Request for Proposal (RFP)Jurisdictional Cost Recovery Allocation — In SeptemberDecember 2016, NSP-Minnesota issuedfiled a RFPresource treatment framework with the NDPSC and MPUC. The filing proposed a framework to allow NSP-Minnesota’s operations in North Dakota and Minnesota to gradually become more independent of one another with respect to future generation resource selection while also identifying a path for 1,500 MWcost sharing of wind generationcurrent resources. NSP-Minnesota’s filing identified two options: a legal separation, creating a separate North Dakota operating company; or a pseudo-separation, which maintains the current corporate structure but directly assigns the costs and benefits of each resource to the jurisdiction that supports it. The annual costs for a legal separation and pseudo-separation are estimated to be approximately $3 million and $1 million, respectively. A one-time cost of approximately $10 million would also be incurred to establish a North Dakota operating company under legal separation. Costs are not expected to be incurred until 2020 and are anticipated to be recoverable through rates. The filing proposed a procedural schedule that considers an order in service by 2020. The RFP requests both PPAs and Build-Own-Transfer proposals. NSP-Minnesota intends to compare self-build optionsmid-2018. In October 2017, NDPSC staff filed testimony recommending no change to the RFP bids to ensure that allcurrent system of proxy pricing and policy-based disallowances claiming there is a likelihood of overall increased costs and potential loss of resource additionsdiversity. NSP-Minnesota’s rebuttal testimony is due Nov. 15, 2017 and hearings are cost-competitive.scheduled in January 2018.
In October 2016,CapX2020 — The estimated cost of the five major CapX2020 transmission projects listed below was approximately $2 billion. NSP-Minnesota submitted a petitionand NSP-Wisconsin were responsible for approvalapproximately $1.04 billion of the total investment and the majority of this investment has occurred. The projects are as follows:
Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. 161/345 kilovolt (KV) transmission lines— The final 161 KV and 345 KV segments of the MPUC of a 750 MW self-build wind farm portfolio. RFP bids were receivedproject went into service in OctoberJanuary 2016 and will be evaluatedSeptember 2016, respectively;
Brookings County, S.D. to Hampton, Minn. 345 KV transmission line— The project was placed in conjunction with the self-build proposal.service in March 2015;
Bemidji, Minn. to Grand Rapids, Minn. 230 KV transmission line — The project was placed in service in September 2012;
An overviewMonticello, Minn. to Fargo, N.D. 345 KV transmission line— The final portion of the anticipated RFP schedule is as follows:project was placed in service in April 2015; and
Project proposal selection and negotiation will occur from November 2016Big Stone South to March 2017;
An NSP-Minnesota recommendation for proposed wind additions to the MPUCBrookings County, S.D. 345 KV transmission line — The project was placed in the first quarter of 2017; and
MPUC approval is expected by Julyservice in September 2017.
Minnesota SolarFCA —Minnesota legislation requires 1.5 percent In October 2017, the MPUC voted to change the process in which utilities seek fuel cost recovery under the FCA in Minnesota. Each month, utilities collect amounts equal to the baseline cost of energy set at the start of the plan year, as well as issue refunds or billings for the difference relative to the baseline costs. Under the new process, monthly variations to the baseline costs will be tracked and netted over a public utility’s total electric retail sales to retail customers be generated using solar energy by 2020. Of12-month period. Subsequently, utilities can seek recovery of any overage. The MPUC has requested additional compliance filings from all utilities outlining the 1.5 percent, 10 percent must come from systems sized 20 kilowatts or less. NSP-Minnesota anticipates it will meet its compliance requirements through largedetails and small scale solar additions.timing of the proposed process.
NSP-Minnesota also offers customer solar programs: a solar production incentive program for rooftop solar, called Solar*Rewards®, and a community solar garden program that provides bill credits to participating subscribers, called Solar*Rewards® Community®. Additionally, the DOC offers the “Made in Minnesota” program, providing incentives for the installation
In August 2015, the MPUC issued an order regarding the Solar*Rewards Community program, limiting the size of solar installations eligible to participate in the program. The order was appealed to the Minnesota Court of Appeals, which affirmed the MPUC’s decision. The decision was subsequently appealed to the Minnesota Supreme Court, which denied the appeal in September 2016, terminating the case.
Nuclear Power Operations
NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the PI plant. NSP-Minnesota’s next triennial nuclear decommissioning filing is expected to be submitted in the fourth quarter of 2017. See Note 14 of Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 20152016 for further discussion regarding the nuclear generating plants. The circumstances set forth in Nuclear Power Operations and Waste Disposal included in Item 1 of Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 20152016 and Nuclear Power Operations included in Item 2 of Xcel Energy Inc.’s Quarterly ReportsReport on Form 10-Q for the quarterly periods ended March 31, 20162017 and June 30, 2016,2017, appropriately represent, in all material respects, the current status of nuclear power operations, and are incorporated herein by reference.
NSP-Wisconsin
20162017 Electric Fuel Cost Recovery — NSP-Wisconsin’s electric fuel costs for the nine months ended Sept. 30, 20162017 were lower than authorized in rates and outside the two percent annual tolerance band established in the Wisconsin fuel cost recovery rules.rules, primarily due to lower sales volume and lower purchased power costs coupled with moderate weather and generation sales into the MISO market. Under the fuel cost recovery rules, NSP-Wisconsin may retain the amount of over-recovery up to two percent of authorized annual fuel costs, or approximately $3.5$3.7 million. However, NSP-Wisconsin must defer the amount of over-recovery in excess of the two percent annual tolerance band for future refund to customers. Accordingly, NSP-Wisconsin recorded a deferral of approximately $6.6$10.5 million through Sept. 30, 2016.2017. The amount of the deferral could increase or decrease based on actual fuel costs incurred for the remainder of the year. In the first quarter of 20172018, NSP-Wisconsin will file a reconciliation of 20162017 fuel costs with the PSCW. The amount of any potential refund is subject to review and approval by the PSCW, which is not expected until mid-2017.mid-2018.
PSCo
Rush Creek Wind Ownership Proposal — In 2016, the CPUC granted PSCo a Certificate of Public Convenience and Necessity (CPCN) to build, own and operate a 600 MW wind generation facility in Colorado 2016 Electric Resourceat 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.
Colorado Energy Plan (CEP)— In May 2016, PSCo filed its 2016 Electric Resource Plan which identified approximately 600included the estimated need for additional generation resources through 2024. In April 2017, the CPUC approved the modeling assumptions that will be used in the Request for Proposal (RFP) process. In August 2017, PSCo filed an updated capacity need with the CPUC of 450 MW.
In August 2017, PSCo, along with various other stakeholders, filed a stipulation agreement proposing the CEP. The major components include:
Early retirement of 660 MW of additionalcoal-fired generation at Comanche Units 1 (2022) and 2 (2025);
An RFP which could result in the addition of up to 1,000 MW of wind, 700 MW solar and 700 MW of natural gas and/or storage;
Utility ownership targets of 50 percent renewable generation resources need byand 75 percent of natural gas-fired, storage, or renewable with storage generation resources;
Accelerated depreciation for the summerearly retirement of 2023.the two Comanche units and establishment of a regulatory asset to collect the incremental depreciation expense and related costs;
Reduction of the Renewable Energy Standard Adjustment rider, from two percent to one percent, subject to regulatory proceedings, effective beginning 2021 or 2022; and
Construction of a new transmission switching station to further the development of renewable generating resources.
In August 2017, PSCo issued an All-Source RFP. Bids are due on Nov. 28, 2017. PSCo anticipates filing its’ recommended portfolios in April 2018. The CPUC is expected to considerrule on the resource planstipulation agreement in two phases. InMarch 2018. A CPUC decision on the first phase, the CPUC will examine the resource need to address peak demand periods, establish the resource acquisition period and determine modeling parameters used in resource selection for the second phase. The second phase would include solicitation of new resources. PSCo’s base plan, filed in Phase I, addressed various resources including 410 MW of combined cycle generation, 700 MW of combustion turbine generation and approximately 600 MW of customer sited solar generation. Additional scenarios to the plan include adding 600 MW of the Rush Creek Wind Project or 400 MW of wind or utility solar generation.
The key datesrecommended portfolio is anticipated in the procedural schedule for the first phasesummer of the Electric Resource Plan are as follows:
Answer testimony — Dec. 9, 2016;
Rebuttal testimony — Jan. 17, 2017;
Hearings — Feb. 1-8, 2017; and
Statements of position — Feb. 17, 2017.
The second phase of the Electric Resource Plan is anticipated to begin shortly after the conclusion of the first phase.2018.
Rush Creek Wind Ownership Proposal — In May 2016, PSCo filed an application to build, own and operate a 600 MW wind generation facility at Rush Creek for a cost of approximately $1 billion, including transmission investment.
In September 2016, the CPUC approved a settlement between PSCo, the CPUC Staff, the Colorado Office of Consumer Counsel, the Colorado Energy Office and various other parties. This will allow PSCo to commence the project on a timely basis and capture the full production tax credit benefit for customers.
Key termsApproval of the settlement are listed below:
CEP could increase the total capital investment up to $1.5 billion. The Rush Creek project satisfies the reasonable cost standardCEP is not included in PSCo and is in the public interest;
The project should be placed in service by Oct. 31, 2018;
The useful lifeXcel Energy’s base capital expenditures forecast. See Item 2. Management’s Discussion and Analysis of Financial Condition and Result of Operations— Capital Requirements for further discussion of the project should be set at 25 years;
A hard cost-cap on the $1.096 billion investment (which includes the capital investment and allowance for funds used during construction);
A capital cost sharing mechanism for every $10 million below the cost-cap, with 82.5 percent retained by customers and 17.5 percent retained by PSCo on a net present value basis over the life of the project;
Amounts retained by PSCo under the capital cost sharing mechanism as well as overall facility revenue requirements may each be reduced for lower than projected long term generating output (i.e., higher degradation); and
The Pawnee-Daniels transmission line (estimated project cost of $178 million) should be accelerated and operations are expected to begin by October 2019.
PSCo Global Settlement Agreementforecast. — In August 2016, PSCo and various intervenors, including small and large customers, state representatives, environmental advocates and solar and energy groups, entered into a global settlement agreement regarding three pending filings with the CPUC, including the Phase II electric rate case (which is related to the rate design portion of the 2015 Electric Rate Case), the Renewable*Connect proposal (formally known as Solar*Connect) and the 2017 Renewable Energy Plan. Key terms of the agreement include that participating customers in the proposed Renewable*Connect program would pay ordinary tariff electric rates in addition to a voluntary tariff solar charge, and receive bill credits related to avoided cost savings for a new 50 MW solar resource. It was also agreed that PSCo’s 2017 Renewable Energy Plan would include 2017 to 2019 acquisition of a total of 225 MW of renewable energy from sources including rooftop solar, solar gardens and recycled energy.
A CPUC decision is expected by December 2016, which would allow PSCo to issue a RFP for the new Renewable*Connect solar facility and implement the 2017 Renewable Energy Plan and the rate design changes of the Phase II electric rate case beginning January 2017.
Joint Dispatch Agreement (JDA) — In February 2016, the FERC approved a JDA between PSCo, Black Hills Colorado Electric Utility Company, LP and Platte River Power Authority. Through the JDA, energy is dispatched to economically serve the combined electric customer loads of the three systems. In circumstances where PSCo is the lowest cost producer, it will sell its excess generation to other JDA counterparties. PSCo proposed with the CPUC that margins on these sales be shared among PSCo and its customers, of which 10 percent would be retained by PSCo. A decision by the CPUC is anticipated in the fourth quarter of 2016. The JDA parties estimate the combined net benefits of the agreement would be approximately $4.5 million, annually. The agreement results in a reduction in total energy costs for the parties, of which approximately $1.4 million would be allocated to PSCo’s customers. As part of the agreement, PSCo will earn a management fee to administer the JDA. We expect operations under the JDA to begin in the fourth quarter of 2016.
Advanced Grid Intelligence and Security —In August 2016, PSCo filed a request withJuly 2017, the CPUC to approve a certificate of public convenience and necessityapproved PSCo’s CPCN for implementation of its advanced grid initiative. The project incorporates installing advanced meters, implementing a combination of hardware and software applications to allow the distribution system to operate at a lower voltage (integrated volt-var optimization) and installing necessary communications infrastructure to implement this hardware.infrastructure. These major projects are expected to improve customer experience, enhance grid reliability and enable the implementation of new and innovative programs and rate structures.
In June 2017, the CPUC approved a settlement, which delayed the advanced meter deployment from 2017-2021 to 2019-2024. The estimatedtotal capital cost of the project included in the CPCN is approximately $537 million for 2017-2024. As a result of the settlement, approximately $120 million of capital investment for the project is approximately $500 million. PSCo anticipates a CPUC decision by the third quarter of 2017. If approval is received, the project is expectedwas deferred to be completed by 2021.2022-2024.
Decoupling Filing — In July 2016, PSCo filed a request with the CPUC to approve a partial decoupling mechanism, for a five year period, effective on Jan. 1, 2017. The proposed decoupling adjustmentwhich would allow PSCo to adjust annual revenues based on changes in weather normalized average use per customer for the residential and small C&Icommercial classes. The proposed mechanism is intended
In July 2017, the CPUC issued a decision which approved the following key decisions regarding decoupling:
Effective Jan. 1, 2018 through December 2023 (subject to improve PSCo’s ability to collect base rate revenuesestablishing new rates in the event that average use per customer declines asnext electric rate case);
Applicable to the residential class and small commercial class;
Based on total class revenues (subject to establishing the base period in the next electric rate case);
Based on actual sales; and
Subject to a resultsoft cap of DSM, distributed generation and other energy saving programs. The proposed decoupling mechanism is symmetric and may result in potential refunds to customers if there were an increase in average use per customer. PSCo did not request that revenue be adjusted as a result of weather related sales fluctuations.3 percent on any annual adjustment.
In August 2016, a majority2017, the CPUC denied PSCo’s request for reconsideration of the parties to the PSCo Global Settlement Agreement agreed to limit any future opposition to PSCo’s decoupling proposal to the specifics of design and implementation.
The key dates in the procedural schedule are as follows:
Direct testimony — Dec. 14, 2016;
Answer testimony — Jan. 16, 2017;
Rebuttal and cross answer testimony — Feb. 10, 2017; and
Hearings — Feb. 21-24, 2017.
A decision is anticipated in the first quarter of 2017.order.
Boulder, Colo. Municipalization — In November 2011, in the City of Boulder, Colo. (Boulder), voters passed a ballot measure was passed which authorizedauthorizing the formation and operation of a municipal utility, and the issuance of enterprise revenue bonds, subject to certain restrictions, including the level of initial rates and debt service coverage.conditions. In May 2014, the City of Boulder (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, but the case was dismissed. PSCo appealed this decision and in Septemberutility. In 2016, the Colorado Court of Appeals preserved PSCo’s ability to challengedo so. Subsequently, Boulder filed a Petition for Writ of Certiorari with the utility while vacatingColorado Supreme Court. In August 2017, the lower court’sColorado Supreme Court granted the petition to review the Colorado Court of Appeals decision.
In 2013,2015, the Boulder District Court affirmed a prior CPUC ruleddecision that Boulder may not be the retail service provider to any PSCocannot serve customers located outside Boulderits city limits unless Boulder can establish that PSCo is unwilling or unable to serve those customers.limits. The CPUCDistrict Court also ruled that itthe CPUC has jurisdiction over the transfer of any facilities to Boulder that currently serve any customers located outside Boulder city limits and will determine separation matters. The CPUC has declared that Boulder must receive CPUC transfer approval priorin determining how the systems are separated to any eminent domain actions. Boulder appealed this ruling to the Boulder District Court. In January 2015,preserve reliability, safety and effectiveness. Further, the Boulder District Court affirmeddismissed the condemnation action Boulder had filed, finding that the CPUC decision. Themust give approval before Boulder District Court also dismissedfiles any future condemnation proceeding. Boulder does not have authorization to initiate a condemnation action thatproceeding at this time.
Beginning in 2015, Boulder had filed. filed multiple separation applications, the most recent one being in May 2017. In June 2017, PSCo and other intervenors filed alternatives to Boulder’s separation plan and opposed certain sharing; contracting and financing aspects of the plan.
In September 2017, the CPUC issued a written decision, agreeing with several key aspects of PSCo’s position, stating PSCo is not required to:
Finance Boulder’s municipalization efforts;
Design or construct future Boulder electric distribution facilities;
Enter into joint use of pole arrangements with Boulder; and
Use a third party to design and build facilities.
The CPUC mustprovided conditional approval related to the transfer of some of the electrical distribution assets in Boulder, however subject to completion of certain items, including:
Filing an agreement between Boulder and PSCo providing permanent rights for PSCo to place and access facilities in Boulder needed to continue to serve its customers;
Filing a complete the separation plan proceeding beforeand accurate revised list of distribution assets to be transferred; and
Filing an agreement to address numerous aspects of payments from Boulder may refile a condemnation proceeding.to PSCo for costs of Boulder’s municipalization efforts.
The CPUC requested those filings be made by Dec. 13, 2017. The CPUC has established a process whereby once those filings are made, additional hearings may be held.
At the end of 2017, several Boulder measures expire absent voter approvals, including the Utility Occupational Tax (UOT) which funds Boulder’s municipalization efforts. In July 2015,response, Boulder filedhas placed the following measures on the November 2017 ballot:
An extension and increase of the UOT for funding Boulder’s exploration of municipalization;
Requiring final voter approval prior to Boulder issuing debt to acquire assets and fund the start up of a local electric utility; and
Extending Boulder city council’s authority to hold non-public, executive sessions to discuss legal strategy related to municipalization, but not to discuss certain settlement options with PSCo.
Mountain West Transmission Group (MWTG) — PSCo, along with six other transmission owners from the Rocky Mountain region, have been considering creating and operating a joint transmission tariff to increase wholesale market efficiency and improve regional transmission planning. In September 2017, the MWTG determined that membership in the SPP RTO would provide opportunities to reduce customer costs, and maximize resource and electric grid utilization. If participation with SPP proceeds, the MWTG utilities expect an applicationeconomic benefit. In October 2017, the MWTG commenced negotiations with SPP through the SPP public stakeholder process.
SPP’s organizational group will address respective findings, objectives and next steps related to MWTG’s consideration of SPP membership. Should the MWTG decide to move forward, SPP would make filings with the FERC and PSCo would make filings with the CPUC requesting approval of its proposed separation plan. In August 2015, PSCo filed a motionand the FERC, in mid-2018. If approved, MWTG operations within the SPP RTO would not be expected to dismiss Boulder’s separation proposal, arguing Boulder’s request was not permissible under Colorado law. In December 2015,begin until late 2019, at the CPUC granted the motion to dismiss the application in part, holding that Boulder had no right to acquire PSCo facilities used exclusively to serve customers located outside Boulder city limits. Other portions of Boulder’s application were not dismissed, but were stayed until Boulder supplemented its application. Boulder filed its amended application in September 2016, and in the application, Boulder estimates it would incur approximately $53 million of costs to separate from the PSCo system.earliest.
SPS
TUCO Substation to Yoakum County Substation to Hobbs Plant Substation 345 Kilovolt (KV)KV Transmission Line — In June 2015, SPS filed a certificate of convenience and necessity (CCN) withMarch 2016, the PUCT approved SPS’ Certificate of Convenience and Necessity (CCN) for the 33-mile27-mile Yoakum County to Texas/New Mexico State line portion of this 345 KV line project. The PUCT approved this CCN in March 2016. A CCN for the 111-mile106-mile TUCO to Yoakum County substation segment was filedapproved by the PUCT in June 2016. Assuming approval of this CCN, this segmentSeptember 2017 and is scheduled to be in service in 2019.the second quarter of 2020. A 20-mile36-mile CCN for the Texas/New Mexico state line to Hobbs Plant segment was filed in June 2017. Assuming approval of this CCN, the Yoakum County to Hobbs Plant segment is plannedscheduled to be filed in the fourth quarterservice in summer of 2016 or early 2017.2019. The estimated project cost for all three segments is approximately $242$239 million.
The TUCO Substation to Yoakum County Substation to Hobbs Plant Substation transmission line is part of a larger project which includes a 345 KV transmission line from the Hobbs Plant to the China Draw Substation. The Hobbs Plant to China Draw Substation portion of this project was approved by the NMPRC in November 2016 and has an estimated cost of $163 million. The total investment for the two transmission lines is approximately $402 million. The Hobbs Plant to China Draw Substation transmission line is under construction and is anticipated to be in service by June 1, 2018.
Wholesale Customer Participation in Electric Reliability Council of Texas (ERCOT) — In March 2016, the PUCT Staff requested comments on Lubbock Power & Light’s (LP&L’s) proposal to transition a portion of its load (approximately 430 MW on a peak basis) to the ERCOT in June 2019. LP&L’s proposal would result in an approximate seven percent reduction of load in SPS, or a loss of approximately $18 million in wholesale transmission revenue based on 2015 revenue requirements.revenue. The remaining portion of LP&L’s load (approximately 170 MW) would continue to be served by SPS. Should LP&L join ERCOT, costs to SPS’ remaining customers would increase as SPS’ transmission costs would be spread across a smaller base of customers.
The PUCT has indicated there will be a two-step process regarding LP&L’s possible transfer to ERCOT. The first step will be a proceeding to determine whether the proposed transfer is in the public interest and to consider certain protections for non-LP&L customers who would be affected by LP&L’s transfer. If the PUCT determines the transfer is in the public interest, the second step will be for LP&L to file a CCN application for transmission facilities to connect with ERCOT. As part of the first process, theThe PUCT asked SPP and ERCOT to perform reliability and economic studies to better understand the implications of LP&L’s proposal. SPS intendsSPP and ERCOT filed the studies on June 30, 2017. In September 2017, LP&L filed its application with the PUCT for a public interest determination and proposed a transition date no later than June 2021. The PUCT issued a preliminary order setting out issues for the parties to participateaddress. A hearing on the matter is expected to be held in the PUCT’s processes to protect its customers’ interests.first quarter of 2018 and a PUCT decision is expected in the second quarter of 2018.
In May 2016, SPS submitted a filing to the FERC seeking approval to impose an Interconnection Switching Fee (exit fee) associated with LP&L’s proposal. In September 2016, FERC dismissed SPS’ petition without prejudice to refile, finding the petition premature since LP&L has not made aNo final decision to move to ERCOT and the termsregarding LP&L’s departure or its potential timing is expected until completion of the transition, if any, have not been determined.PUCT proceedings.
Summary of Recent Federal Regulatory Developments
The Pipeline and Hazardous Materials Safety Administration
Pipeline Safety Act — The Pipeline Safety, Regulatory Certainty, and Job Creation Act (Pipeline Safety Act) requires additional verification of pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. In April 2016, the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) released proposed rules that address this verification requirement along with a number of other significant changes to gas transmission regulations. These changes include requirements around use of automatic or remote-controlled shut-off valves; testing of certain previously untested transmission lines; and expanding integrity management requirements. The Pipeline Safety Act also includes a maximum penalty for violating pipeline safety rules of $2 million per day for related violations.
Xcel Energy continues to analyze the proposed rule changes as they relate to costs, current operations and financial results. PHMSA has indicated that they intend for the rules to go into effect in late 2017 or early 2018.
Xcel Energy has been taking actions that were intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective. PSCo and NSP-Minnesota can generally recover costs to comply with the transmission and distribution integrity management programs through the pipeline system integrity adjustment and GUIC riders, respectively.
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 Xcel Energy Inc.’s utility subsidiaries and transmission-only subsidiaries, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. State and local agencies have jurisdiction over many of Xcel Energy Inc.’s utility subsidiaries’ 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 Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 20152016 and Quarterly ReportsReport on Form 10-Q for the quarterly periods ended March 31, 20162017 and June 30, 2016.2017. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.
FERC Order, New ROE Policy — TheIn June 2014, the FERC has adopted a new two-step ROE methodology for electric utilities.utilities in an order issued in a complaint proceeding involving New England Transmission Owners (NETOs). The issue of how to apply the new FERC ROE methodology is beinghas been contested in various complaint proceedings. There areproceedings, including two ROE complaints againstinvolving the MISO TOs, which includeincludes NSP-Minnesota and NSP-Wisconsin. In September 2016,April 2017, the D.C. Circuit vacated and remanded the June 2014 ROE order. The D.C. Circuit found that the FERC issued an order inhad not properly determined that the first MISO ROE complaint which upheldauthorized for the initial decision made byNETOs prior to June 2014 was unjust and unreasonable. The D.C. Circuit also found that the ALJ in December 2015.FERC failed to justify the new ROE methodology. The second complaint is pending FERC action after issuance of an initial decision byhas yet to act on the ALJ in June 2016. FERC is not expected to issue an order in the second litigated MISO ROE complaint proceeding until 2017.D.C. Circuit’s decision. See Note 5 to the consolidated financial statements for discussion of the D.C. Circuit’s decision and the impact on the MISO ROE Complaints.
Formula Rate TreatmentDepartment of Accumulated Deferred Income Taxes (ADIT)Energy (DOE) Grid Resiliency Notice of Proposed Rule (NOPR) — In 2015, NSP-Minnesota, NSP-Wisconsin, SPSSeptember 2017, the DOE requested the FERC consider and PSCo filed changesadopt a Grid Resiliency and Pricing Rule to address threats to the U.S. electrical grid. The proposed DOE rule expands upon an August 2017 DOE grid study on the resiliency of the grid. Under the proposed rule, coal and nuclear generation facilities would qualify for full recovery of their transmission formula ratescosts, which includes a fair rate of return, if they meet the following criteria:
Are located within a FERC-approved organized wholesale market operated by an RTO or Independent System Operator;
Have 90 days of on-site fuel storage;
Provide essential energy and PSCo filed changesancillary reliability services to its production formula rate, to comply with IRS guidance regarding how ADIT must be reflected in formula rates using future test years and a true-up. The filings were intended to ensure that NSP-Minnesota, NSP-Wisconsin, PSCo and SPS arethe grid;
Are in compliance with IRS rulesall environmental mandates; and may continue
Are not subject to use accelerated tax depreciation.cost-of-service regulation by any state or local authority.
In December 2015,If implemented as written, the FERC partially accepted the proposedcoal and nuclear generation owned by NSP-Minnesota, and NSP-Wisconsin transmission formula rate changes, but rejected changes regarding the treatment of ADIT in the formula rate true-up. In September 2016, FERC issued an order clarifying that NSP-Minnesota and NSP-Wisconsin may incorporate ADIT true-up provisions in their formula rate. However, submission of a new tariff change filing is required to implement the change. NSP-Minnesota and NSP-Wisconsin expect to file a change to their transmission formula rate in the fourth quarter of 2016 and will request a Jan. 1, 2016 effective date.
Golden Spread protested the proposed changes to the SPS transmission formula rate. In April 2016, FERC accepted the SPS and PSCo transmission formula rate and PSCo production formula rate changes, subject to compliance filings. SPS and PSCo submitted the compliance filings in May 2016. In August 2016, FERC approved the PSCo and SPS compliance filings.
SPP and MISO Complaints Regarding RTO Joint Operating Agreement (JOA) —SPP and MISO were involved in a long-running dispute regarding the interpretation of their JOA, which is intended to coordinate RTO operations along the MISO/SPP system boundary. SPP and MISO disagreed over MISO’s authority to transmit power between the traditional MISO region in the Midwest and the Entergy system. Several cases were filed with the FERC by MISO and SPP between 2011 and 2014.
In January 2016, the FERC approved a settlement between SPP, MISO and other parties that resolves various disputed matters and provides a defined settlement compensation plan by MISO to SPP. MISO will pay SPP $16 million for the two-year retroactive period (February 2014 to January 2016) and $16 million annually prospectively starting Feb. 1, 2016, subject to a true-up. In January 2016, SPP filed a proposal regarding distribution of the MISO revenues to SPP members, including SPS. In March 2016, the FERC issued an order rejecting one component of the SPP filing, accepting the remainder of the SPP tariff proposal subject to refund. In August 2016, MISO and other parties filed a settlement regarding the April 2014 MISO tariff change filing to recover SPP JOA charges in MISO rates. The settlement is pending FERC approval. NSP-Minnesota and NSP-Wisconsin expect to be able to recover any resulting MISO charges in retail rates. The JOA revenue allocated to SPS under the filed SPP proposal wasare not expected to be material.eligible for wholesale cost recovery from MISO or SPP because the generation is subject to state cost-of-service regulation. This rule could impact utilities in MISO or SPP subject to cost-of-service regulation if they have to compensate other generation facilities who qualify for full recovery of their costs under the rule. Xcel Energy is evaluating the DOE proposal and plans to engage in the FERC stakeholder process. The FERC has indicated that they plan to take action within 60 days, as requested by the DOE. It is unclear how the FERC will respond to the DOE’s NOPR.
Minnesota State Right-Of-First Refusal (ROFR) Statute Complaint — In September 2017, LSP Transmission Holdings, LLC filed a complaint in the U.S. District Court in Minnesota against the Minnesota Attorney General, the MPUC and the DOC. The complaint was in response to NSP-Minnesota and ITC Midwest, LLC being assigned by MISO to jointly own a new 345 kilovolt transmission line that is planned to run from NSP-Minnesota’s Wilmarth Substation near Mankato, Minn. to ITC Midwest’s Huntley Substation in Minnesota south of Winnebago, Minn. The line is estimated to cost $108 million. The project was assigned to NSP-Minnesota and ITC Midwest as the incumbent utilities, consistent with a Minnesota state ROFR statute. The complaint challenges the constitutionality of the state ROFR statute and is seeking declaratory judgment that the statute violates the Commerce Clause of the U.S. Constitution and should not be enforced. The Minnesota state agencies are expected to answer the complaint in November 2017. NSP-Minnesota expects to intervene in the case. The timing and outcome of the litigation is uncertain.
North American Electric Reliability Corporation (NERC) Supply Chain Standards — In September 2017, NERC filed supply chain cyber security reliability standards with the FERC. These standards consider the FERC’s directives to address supply chain cyber security risk management for industrial control system hardware, software, computing and network services associated with electric grid operations. The proposed reliability standards focus on security objectives including software integrity and authenticity, vendor remote access protections, information system planning and vendor risk management. It is uncertain when the FERC will take action to approve or remand the proposed reliability standards. If approved by the FERC, the proposed reliability standards will become effective on the first calendar quarter that is 18 months after the effective date of the approval. Xcel Energy is in the process of developing plans in accordance with the requirements of the standards. The additional cost for compliance is anticipated to be recoverable through wholesale and retail rates.
Public Utility Regulatory Policies Act (PURPA) Enforcement Complaint Against CPUC —In December 2016, Sustainable Power Group, LLC (sPower) petitioned the FERC to initiate an enforcement action in federal court against the CPUC under PURPA. The petition asserts that a December 2016 CPUC ruling, which indicated that a qualifying facility must be a successful bidder in a PSCo resource acquisition bidding process, violated PURPA and FERC rules. In January 2017, PSCo filed a motion to intervene and protest, arguing that the FERC should decline the petition. The CPUC filed a similar pleading. sPower has proposed to construct 800 MW of solar generation and 700 MW of wind generation in Colorado and seeks to require PSCo to contract for these resources under PURPA. If sPower were to prevail, PSCo’s ability to select generation resources through competitive bidding would be negatively affected. However, due to a lack of quorum at the FERC, the FERC did not act on that petition within the sixty days contemplated by PURPA. Subsequently sPower filed a complaint for declaratory and injunctive relief in the United States District Court for the District of Colorado (District Court) requesting that the court find the bidding requirement in the CPUC qualifying facility rules to be unlawful. PSCo intervened in that proceeding and the CPUC filed a motion to dismiss. In June 2017, the United States Magistrate Judge (Magistrate) issued a recommendation to the District Court that sPower’s complaint be dismissed because sPower failed to establish that it faced a substantial risk of harm. In October 2017, the District Court denied the CPUC’s motion to dismiss and instead allowed sPower to file an amended complaint. The case effectively starts over and PSCo is expected to intervene in the proceeding again. The timing of a resolution in this case is unclear.
Solar Gardens Investment
In July 2017, a newly formed subsidiary of Xcel Energy signed an agreement with a solar developer to construct and operate approximately 19 MW of new community solar gardens in Minnesota serving existing NSP-Minnesota customers. The projects are expected to achieve commercial operations in 2017 and 2018.
Derivatives, Risk Management and Market Risk
Xcel Energy Inc. and its subsidiaries are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. See Note 8 to the consolidated financial statements for further discussion of market risks associated with derivatives.
Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, when necessary, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While Xcel Energy expects that the counterparties will perform under the contracts underlying its derivatives, the contracts expose Xcel Energy to some credit and non-performance risk.
Though no material non-performance risk currently exists with the counterparties to Xcel Energy’s commodity derivative contracts, distress in the financial markets may in the future impact that risk to the extent it impacts those counterparties. Distress in the financial markets may also impact the fair value of the securities in the nuclear decommissioning fund and master pension trust, as well as Xcel Energy’s ability to earn a return on short-term investments of excess cash.
Commodity Price Risk — Xcel Energy Inc.’s utility subsidiaries are exposed to commodity price risk in their electric and natural gas operations. Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and for various fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. Xcel Energy’s risk management policy allows it to manage commodity price risk within each rate-regulated operation to the extent such exposure exists.
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 energy-related instruments.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.
At Sept. 30, 2016,2017, the fair values by source for net commodity trading contract assets were as follows:
| | | | Futures / Forwards | | Futures / Forwards |
(Thousands of Dollars) | | Source of Fair Value | | Maturity Less Than 1 Year | | Maturity 1 to 3 Years | | Maturity 4 to 5 Years | | Maturity Greater Than 5 Years | | Total Futures/ Forwards Fair Value | | Source of Fair Value | | Maturity Less Than 1 Year | | Maturity 1 to 3 Years | | Maturity 4 to 5 Years | | Maturity Greater Than 5 Years | | Total Futures/ Forwards Fair Value |
NSP-Minnesota | | 1 |
| | $ | 2,719 |
| | $ | 6,582 |
| | $ | 1,500 |
| | $ | 303 |
| | $ | 11,104 |
| | 1 |
| | $ | 2,465 |
| | $ | 3,898 |
| | $ | 3,712 |
| | $ | — |
| | $ | 10,075 |
|
PSCo | | 1 |
| | 461 |
| | 2 |
| | — |
| | — |
| | 463 |
| | 1 |
| | 107 |
| | 105 |
| | — |
| | — |
| | 212 |
|
PSCo | | | 2 |
| | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
| | | | $ | 3,180 |
| | $ | 6,584 |
| | $ | 1,500 |
| | $ | 303 |
| | $ | 11,567 |
| | | | $ | 2,574 |
| | $ | 4,003 |
| | $ | 3,712 |
| | $ | — |
| | $ | 10,289 |
|
| | | | Options | | Options |
(Thousands of Dollars) | | Source of Fair Value | | Maturity Less Than 1 Year | | Maturity 1 to 3 Years | | Maturity 4 to 5 Years | | Maturity Greater Than 5 Years | | Total Futures/ Forwards Fair Value | | Source of Fair Value | | Maturity Less Than 1 Year | | Maturity 1 to 3 Years | | Maturity 4 to 5 Years | | Maturity Greater Than 5 Years | | Total Futures/ Forwards Fair Value |
NSP-Minnesota | | 2 |
| | $ | (16 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (16 | ) | | 1 |
| | $ | (365 | ) | | $ | (15 | ) | | $ | — |
| | $ | — |
| | $ | (380 | ) |
NSP-Minnesota | | | 2 |
| | — |
| | 3,921 |
| | 1,579 |
| | — |
| | 5,500 |
|
| | | | | $ | (365 | ) | | $ | 3,906 |
| | $ | 1,579 |
| | $ | — |
| | $ | 5,120 |
|
1 — Prices actively quoted or based on actively quoted prices.
2 — Prices based on models and other valuation methods.
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing mechanisms were as follows:
| | | | Nine Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
(Thousands of Dollars) | | 2016 | | 2015 | | 2017 | | 2016 |
Fair value of commodity trading net contract assets outstanding at Jan. 1 | | $ | 11,040 |
| | $ | 21,811 |
| | $ | 9,771 |
| | $ | 11,040 |
|
Contracts realized or settled during the period | | (2,628 | ) | | (4,400 | ) | | (9,118 | ) | | (2,628 | ) |
Commodity trading contract additions and changes during period | | 3,139 |
| | (3,169 | ) | |
Commodity trading contract additions and changes during the period | | | 14,756 |
| | 3,139 |
|
Fair value of commodity trading net contract assets outstanding at Sept. 30 | | $ | 11,551 |
| | $ | 14,242 |
| | $ | 15,409 |
| | $ | 11,551 |
|
At Sept. 30, 2017, a 10 percent increase in market prices for commodity trading contracts would increase pretax income from continuing operations by approximately $0.6 million, whereas a 10 percent decrease would decrease pretax income from continuing operations by approximately $1.3 million. At Sept. 30, 2016, a 10 percent increase in market prices for commodity trading contracts would decrease pretax income from continuing operations by approximately $0.3 million, whereas a 10 percent decrease would increase pretax income from continuing operations by approximately $0.3 million. At Sept. 30, 2015, a 10 percent increase in market prices for commodity trading contracts would increase pretax income from continuing operations by approximately $0.5 million, whereas a 10 percent decrease would decrease pretax income from continuing operations by approximately $0.5 million.
Xcel Energy Inc.’s utility subsidiaries’ wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, including transactions that are not recorded at fair value, using an industry standard methodology known as Value at Risk (VaR). VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time under normal market conditions.
The VaRs for the NSP-Minnesota and PSCo commodity trading operations, calculated on a consolidated basis using a Monte Carlo simulation with a 95 percent confidence level and a one-day holding period, were as follows:
| | (Millions of Dollars) | | Three Months Ended Sept. 30 | | VaR Limit | | Average | | High | | Low | | Three Months Ended Sept. 30 | | VaR Limit | | Average | | High | | Low |
2017 | | | $ | 0.07 |
| | $ | 3.00 |
| | $ | 0.13 |
| | $ | 0.63 |
| | $ | 0.03 |
|
2016 | | $ | 0.10 |
| | $ | 3.00 |
| | $ | 0.18 |
| | $ | 0.38 |
| | $ | 0.05 |
| | 0.10 |
| | 3.00 |
| | 0.18 |
| | 0.38 |
| | 0.05 |
|
2015 | | 0.17 |
| | 3.00 |
| | 0.23 |
| | 0.63 |
| | 0.10 |
| |
Nuclear Fuel Supply — NSP-Minnesota is scheduled to take delivery of approximately 8712 percent of its 20162017 and approximately 1359 percent of its 20172018 enriched nuclear material requirements from sources that could be impacted by events in Ukraine and sanctions against Russia. Alternate potential sources are expected to provide the flexibility to manage NSP-Minnesota’s nuclear fuel supply to ensure that plant availability and reliability will not be negatively impacted in the near-term. Long-term, through 2024, NSP-Minnesota is scheduled to take delivery of approximately 3531 percent of its average enriched nuclear material requirements from sources that could be impacted by events in Ukraine and extended sanctions against Russia. NSP-Minnesota is closely following the progression of these events and will periodically assess if further actions are required to assure a secure supply of enriched nuclear material.
Separately, NSP-Minnesota has enriched nuclear fuel materials in process with Westinghouse Electric Corporation (Westinghouse). Westinghouse filed for Chapter 11 bankruptcy protection in March 2017. NSP-Minnesota owns materials in Westinghouse’s inventory and has contracts in place under which Westinghouse will provide certain services during an upcoming outage at PI. Westinghouse provided nuclear fuel assemblies for the upcoming PI outage under the current nuclear fuel fabrication contract. Westinghouse has indicated its intention to continue to perform under the arrangements. Based on Westinghouse’s stated intent and the interim financing secured to fund its on-going operations, NSP-Minnesota does not expect the bankruptcy to materially impact NSP-Minnesota’s operational or financial performance.
Interest Rate Risk — Xcel Energy is subject to the risk of fluctuating interest rates in the normal course of business. Xcel Energy’s risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.
At Sept. 30, 20162017 and 2015,2016, a 100-basis-point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pretax interest expense annually by approximately $4.2$5.6 million and $0.8$4.2 million, respectively. See Note 8 to the consolidated financial statements for a discussion of Xcel Energy Inc. and its subsidiaries’ interest rate derivatives.
NSP-Minnesota also maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate risk and equity price risk. At Sept. 30, 2016,2017, the fund was invested in a diversified portfolio of cash equivalents, debt securities, equity securities, and other investments. These investments may be used only for activities related to nuclear decommissioning. 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. Since the accounting for nuclear decommissioning recognizes that costs are recovered through rates, fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have ana direct impact on earnings.
Credit Risk — Xcel Energy Inc. and its subsidiaries are also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. Xcel Energy Inc. and its subsidiaries maintain credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations.
At Sept. 30, 2017, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $18.3 million, while a decrease in prices of 10 percent would have resulted in an increase in credit exposure of $1.7 million. At Sept. 30, 2016, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $11.7 million, while a decrease in prices of 10 percent would have resulted in an increase in credit exposure of $15.9 million. At Sept. 30, 2015, a 10 percent increase in commodity prices would have resulted in a decrease in credit exposure of $4.8 million, while a decrease in prices of 10 percent would have resulted in an increase in credit exposure of $11.7 million.
Xcel Energy Inc. and its subsidiaries conduct standard credit reviews for all counterparties. Xcel Energy 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. Distress in the financial markets could increase Xcel Energy’s credit risk.
Fair Value Measurements
Xcel Energy follows accounting and disclosure guidance on fair value measurements that contains a hierarchy for inputs used in measuring fair value and requires disclosure of the observability of the inputs used in these measurements. See Note 8 to the consolidated financial statements for further discussion of the fair value hierarchy and the amounts of assets and liabilities measured at fair value that have been assigned to Level 3.
Commodity Derivatives — Xcel Energy continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment and the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Sept. 30, 2016.2017. Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are deferred as other comprehensive income (OCI) or regulatory assets and liabilities. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Xcel Energy also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities. The impact of discounting commodity derivative liabilities for credit risk was immaterial to the fair value of commodity derivative liabilities at Sept. 30, 2016.2017.
Commodity derivative assets and liabilities assigned to Level 3 typically consist of FTRs, as well as forwards and options that are long-term in nature. Level 3 commodity derivative assets and liabilities represent 1.33.0 percent and 8.07.6 percent of total assets and liabilities, respectively, measured at fair value at Sept. 30, 2016.2017.
Determining the fair value of FTRs requires numerous management forecasts that vary in observability, including various forward commodity prices, retail and wholesale demand, generation and resulting transmission system congestion. Given the limited observability of management’s forecaststransparency in the auction process, fair value measurements for several of these inputs, these instrumentsFTRs have been assigned a Level 3. Level 3 commodity derivatives assets and liabilities included $27.8$63.0 million and $3.2$2.8 million of estimated fair values, respectively, for FTRs held at Sept. 30, 2016.2017.
Determining the fair value of certain commodity forwards and options can require management to make use of subjective price and volatility forecasts which extend to periods beyond those readily observable on active exchanges or quoted by brokers. When less observable forward price and volatility forecasts are significant to determining the value of commodity forwards and options, these instruments are assigned to Level 3. There were no$5.5 million in Level 3 commodity forwardsderivative assets and no liabilities for options held at Sept. 30, 2016.2017. There were $0.2 million of Level 3 derivative assets held as forwards at Sept. 30, 2017.
Liquidity and Capital Resources
| | | | Nine Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
(Millions of Dollars) | | 2016 | | 2015 | | 2017 | | 2016 |
Cash provided by operating activities | | $ | 2,413 |
| | $ | 2,490 |
| | $ | 2,367 |
| | $ | 2,425 |
|
Net cash provided by operating activities decreased $77$58 million for the nine months ended Sept. 30, 20162017 compared with the nine months ended Sept. 30, 2015.2016. The decrease was primarily due to higher interest payments and pension contributions, lower income tax refunds received, and the timing of vendor payments, customer receipts, refunds, and recovery onof certain electric and natural gas riders and incentive programs,incentives, partially offset by timing of vendor payments and higher net income, excluding amounts related to non-cash operating activities (e.g., depreciation and deferred tax expenses and a charge related to the Monticello LCM/EPU project in 2015)expenses).
| | | | Nine Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
(Millions of Dollars) | | 2016 | | 2015 | | 2017 | | 2016 |
Cash used in investing activities | | $ | (2,206 | ) | | $ | (2,139 | ) | | $ | (2,239 | ) | | $ | (2,206 | ) |
Net cash used in investing activities increased $67$33 million for the nine months ended Sept. 30, 20162017 compared with the nine months ended Sept. 30, 2015.2016. The increase was primarily attributable to higher capital expenditures related to the establishment ofRush Creek wind generation facility, partially offset by lower capital expenditures related to the Courtenay wind farm and fewer rabbi truststrust investments in 2016 and the impact of higher insurance proceeds received in 2015.
| | | | Nine Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
(Millions of Dollars) | | 2016 | | 2015 | | 2017 | | 2016 |
Cash provided by (used in) financing activities | | $ | 62 |
| | $ | (26 | ) | |
Cash (used in) provided by financing activities | | | $ | (45 | ) | | $ | 49 |
|
Net cash provided byused in financing activities was $62$45 million for the nine months ended Sept. 30, 20162017 compared with net cash used inprovided by financing activities of $26$49 million for the nine months ended Sept. 30, 2015, or a2016. The change of $88 million. The difference was primarily dueattributable to lower repayments of short-term debt, partially offset by higher repayments of long-term debt and dividend payments.payments, partially offset by increased net short and long-term debt proceeds.
Capital Requirements
Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios.
Capital Expenditures —— The current estimated base capital expenditure programs ofexpenditures for Xcel Energy’s operating companiesEnergy for years 20172018 through 20212022 are shown in the table below:
| | | | Capital Forecast | | Base Capital Forecast |
(Millions of Dollars) | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | 2017 - 2021 Total | |
By Subsidiary | | | | | | | | | | | | | |
By Subsidiary (Millions of Dollars) | | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | 2018 - 2022 Total |
NSP-Minnesota | | $ | 1,195 |
| | $ | 1,170 |
| | $ | 1,515 |
| | $ | 1,405 |
| | $ | 1,220 |
| | $ | 6,505 |
| | $ | 1,370 |
| | $ | 1,910 |
| | $ | 1,450 |
| | $ | 1,590 |
| | $ | 1,500 |
| | $ | 7,820 |
|
PSCo | | 1,590 |
| | 1,670 |
| | 1,190 |
| | 1,030 |
| | 980 |
| | 6,460 |
| | 1,650 |
| | 1,020 |
| | 950 |
| | 1,150 |
| | 1,410 |
| | 6,180 |
|
SPS | | 610 |
| | 570 |
| | 490 |
| | 400 |
| | 450 |
| | 2,520 |
| | 1,020 |
| | 1,140 |
| | 710 |
| | 470 |
| | 540 |
| | 3,880 |
|
NSP-Wisconsin | | 250 |
| | 280 |
| | 250 |
| | 280 |
| | 300 |
| | 1,360 |
| | 250 |
| | 250 |
| | 240 |
| | 280 |
| | 290 |
| | 1,310 |
|
Other | | 10 |
| | 10 |
| | 510 |
| | 510 |
| | 500 |
| | 1,540 |
| |
Other (a) | | | 20 |
| | (90 | ) | | (90 | ) | | (30 | ) | | — |
| | (190 | ) |
Total capital expenditures | | $ | 3,655 |
| | $ | 3,700 |
| | $ | 3,955 |
| | $ | 3,625 |
| | $ | 3,450 |
| | $ | 18,385 |
| | $ | 4,310 |
| | $ | 4,230 |
| | $ | 3,260 |
| | $ | 3,460 |
| | $ | 3,740 |
| | $ | 19,000 |
|
| | | | Capital Forecast | | Base Capital Forecast |
(Millions of Dollars) | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | 2017 - 2021 Total | |
By Function | | | | | | | | | | | | | |
By Function (Millions of Dollars) | | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | 2018 - 2022 Total |
Electric distribution | | | $ | 750 |
| | $ | 810 |
| | $ | 870 |
| | $ | 1,110 |
| | $ | 1,380 |
| | $ | 4,920 |
|
Renewables | | | 1,410 |
| | 1,860 |
| | 880 |
| | 270 |
| | — |
| | 4,420 |
|
Electric transmission | | $ | 795 |
| | $ | 840 |
| | $ | 750 |
| | $ | 690 |
| | $ | 805 |
| | $ | 3,880 |
| | 770 |
| | 540 |
| | 570 |
| | 860 |
| | 980 |
| | 3,720 |
|
Electric distribution | | 760 |
| | 865 |
| | 950 |
| | 905 |
| | 955 |
| | 4,435 |
| |
Electric generation | | 670 |
| | 685 |
| | 655 |
| | 405 |
| | 485 |
| | 2,900 |
| | 520 |
| | 370 |
| | 290 |
| | 520 |
| | 530 |
| | 2,230 |
|
Natural gas | | 400 |
| | 415 |
| | 420 |
| | 420 |
| | 415 |
| | 2,070 |
| | 460 |
| | 400 |
| | 410 |
| | 420 |
| | 510 |
| | 2,200 |
|
Renewables | | 610 |
| | 555 |
| | 915 |
| | 925 |
| | 500 |
| | 3,505 |
| |
Other | | 420 |
| | 340 |
| | 265 |
| | 280 |
| | 290 |
| | 1,595 |
| |
Other (b) | | | 400 |
| | 250 |
| | 240 |
| | 280 |
| | 340 |
| | 1,510 |
|
Total capital expenditures | | $ | 3,655 |
| | $ | 3,700 |
| | $ | 3,955 |
| | $ | 3,625 |
| | $ | 3,450 |
| | $ | 18,385 |
| | $ | 4,310 |
| | $ | 4,230 |
| | $ | 3,260 |
| | $ | 3,460 |
| | $ | 3,740 |
| | $ | 19,000 |
|
| |
(a) | Other category includes intercompany transfers for safe harbor wind turbines. |
| |
(b) | Amounts in other category are net of intercompany transfers. |
The base capital expenditure programs of forecast does not include the Colorado Energy Plan, which if approved could increase the total capital investment up to $1.5 billion.
Xcel Energy areEnergy’s capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from the estimates due to changes in electric and natural gas projected load growth, regulatory decisions, legislative initiatives, reserve margin requirements, the availability of purchased power, alternative plans for meeting long-term energy needs, compliance with environmental requirements, renewable portfolio standardsregulation, and merger, acquisition and divestiture opportunities. The table above does not include potential expenditures of Xcel Energy’s transmission-only subsidiaries.
Financing for Capital Expenditures through 2022 — Xcel Energy issues debt and equity securities to refinance retiring maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for other general corporate purposes. Xcel Energy does not anticipate issuing any equity to fund its capital investment program for 2017-2021. The current estimated financing plans of Xcel Energy Inc. and its subsidiaries for the years 20172018 through 20212022 are shown in the table below.
|
| | | | |
(Millions of Dollars) | | |
Funding Capital Expenditures | | |
Cash from Operations* | | $ | 13,920 |
|
New Debt** | | 4,695 |
|
Equity through the Dividend Reinvestment Program (DRIP) and Benefit Programs
| | 385 |
|
Base Capital Expenditures 2018-2022 | | $ | 19,000 |
|
| | |
Maturing Debt | | $ | 3,450 |
|
* Net of dividends and pension funding.
** Reflects a combination of short and long-term debt; net of refinancing.
|
| | | | |
(Millions of Dollars) | | |
Funding Capital Expenditures | | |
Cash from Operations* | | $ | 13,465 |
|
New Debt** | | 4,920 |
|
Equity | | — |
|
2017-2021 Capital Expenditures | | $ | 18,385 |
|
| | |
Maturing Debt | | $ | 3,550 |
|
| |
** | Reflects a combination of short and long-term debt. |
Regulation of Derivatives — In July 2010, financial reform legislation was passed that provides for the regulation of derivative transactions amongst other provisions. Provisions within the bill provide the Commodity Futures Trading Commission (CFTC) and the SEC with expanded regulatory authority over derivative and swap transactions. The CFTC ruled that swap dealing activity conducted by entities for the preceding 12 months under a notional limit, initially set at $8 billion, will fall under the general de minimis threshold and will not subject an entity to registering as a swap dealer. The de minimis threshold is scheduled to be reduced to $3 billion in 2017.2018. Xcel Energy’s current and projected swap activity is well below these de minimis thresholds. The bill also contains provisions that exempt certain derivatives end users from much of the clearing and margin requirements and Xcel Energy’s Board of Directors has renewed the end-user exemption on an annual basis. Xcel Energy is currently meeting all reporting requirements and transaction restrictions.
Pension Fund — Xcel Energy’s pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities, and alternative investments, including private equity, real estate, hedge fund of funds and commodity investments.
In January 2016,2017, contributions of $125.0$150.0 million were made across four of Xcel Energy’s pension plans;
In 2015,2016, contributions of $90.0$125.2 million were made across four of Xcel Energy’s pension plans; and
For future years, contributions will be made as deemed appropriate based on evaluation of various factors including the funded status of the plans, minimum funding requirements, interest rates and expected investment returns.
Capital Sources
Short-Term Funding Sources — Xcel Energy uses a number of sources to fulfill short-term funding needs, including operating cash flow, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend in large part on financing needs for construction expenditures, working capital and dividend payments.
Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash operating and short-term investment accounts. At Sept. 30, 2016,2017, approximately $281.7$100.9 million of cash was held in these accounts.
Amended Credit AgreementsFacilities — - In June 2016,NSP-Minnesota, NSP-Wisconsin, PSCo, SPS and Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS entered into amended each have five-year credit agreements with a syndicate of banks. The total borrowing limit under the amended credit agreements remained at $2.75 billion. The amended credit agreements have substantially the same terms and conditions as the prior credit agreements with the following exceptions:
The maturity extended from October 2019 to June 2021.
The Eurodollar borrowing margins on these lines of credit were reduced to a range of 75 to 150 basis points per year, from a range of 87.5 to 175 basis points per year, based upon applicable long-term credit ratings.
The commitment fees, calculated on the unused portionsize of the lines of credit were reduced to a range of 6 to 22.5 basis points per year, from a range of 7.5 to 27.5 basis points per year, also based on applicable long-termfacilities is $2.75 billion, and each credit ratings.facility terminates in June 2021.
NSP-Minnesota, PSCo, SPS and Xcel Energy Inc., NSP-Minnesota, PSCo, and SPS each have the right to request an extension of the revolving credit facility termination date for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility termination date for an additional one-year period. All extension requests are subject to majority bank group approval.
Credit Facilities —As of Oct. 24, 2016,2017, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs: | | (Millions of Dollars) | | Credit Facility (a) | | Drawn (b) | | Available | | Cash | | Liquidity | | Credit Facility (a) | | Drawn (b) | | Available | | Cash | | Liquidity |
Xcel Energy Inc. | | $ | 1,000 |
| | $ | 263 |
| | $ | 737 |
| | $ | — |
| | $ | 737 |
| | $ | 1,000 |
| | $ | 366 |
| | $ | 634 |
| | $ | 1 |
| | $ | 635 |
|
PSCo | | 700 |
| | 22 |
| | 678 |
| | 1 |
| | 679 |
| | 700 |
| | 4 |
| | 696 |
| | 18 |
| | 714 |
|
NSP-Minnesota | | 500 |
| | 11 |
| | 489 |
| | — |
| | 489 |
| | 500 |
| | 22 |
| | 478 |
| | — |
| | 478 |
|
SPS | | 400 |
| | 5 |
| | 395 |
| | 1 |
| | 396 |
| | 400 |
| | 3 |
| | 397 |
| | 49 |
| | 446 |
|
NSP-Wisconsin | | 150 |
| | 37 |
| | 113 |
| | 1 |
| | 114 |
| | 150 |
| | 119 |
| | 31 |
| | 1 |
| | 32 |
|
Total | | $ | 2,750 |
| | $ | 338 |
| | $ | 2,412 |
| | $ | 3 |
| | $ | 2,415 |
| | $ | 2,750 |
| | $ | 514 |
| | $ | 2,236 |
| | $ | 69 |
| | $ | 2,305 |
|
| |
(a) | These credit facilities expire in June 2021. |
| |
(b) | Includes outstanding commercial paper and letters of credit. |
Commercial Paper — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. The authorized levels for these commercial paper programs are:
$1 billion for Xcel Energy Inc.;
$700 million for PSCo;
$500 million for NSP-Minnesota;
$400 million for SPS; and
$150 million for NSP-Wisconsin.
Commercial paper outstanding for Xcel Energy was as follows:
| | (Amounts in Millions, Except Interest Rates) | | Three Months Ended Sept. 30, 2016 | | Year Ended Dec. 31, 2015 | | Three Months Ended Sept. 30, 2017 | | Year Ended Dec. 31, 2016 |
Borrowing limit | | $ | 2,750 |
| | $ | 2,750 |
| | $ | 2,750 |
| | $ | 2,750 |
|
Amount outstanding at period end | | 366 |
| | 846 |
| | 514 |
| | 392 |
|
Average amount outstanding | | 477 |
| | 601 |
| | 679 |
| | 485 |
|
Maximum amount outstanding | | 609 |
| | 1,360 |
| | 867 |
| | 1,183 |
|
Weighted average interest rate, computed on a daily basis | | 0.77 | % | | 0.48 | % | | 1.50 | % | | 0.74 | % |
Weighted average interest rate at period end | | 0.77 |
| | 0.82 |
| | 1.53 |
| | 0.95 |
|
Money Pool — Xcel Energy received FERC approval to establish a utility money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The utility money pool 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. The money pool balances are eliminated in consolidation.
NSP-Minnesota, PSCo and SPS participate in the money pool pursuant to approval from their respective state regulatory commissions. NSP-Wisconsin does not participate in the money pool.
Financing — Xcel Energy issues debt and equity securities to refinance retiring maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for other general corporate purposes.
Xcel Energy Inc. and its utility subsidiaries’During 2017, financing plans reflect the following:
Xcel Energy Inc. plans to issue approximately $300 million of senior unsecured bonds;
NSP-Minnesota plans to issue approximately $600 million of first mortgage bonds;
NSP-Wisconsin plans to issue approximately $100 million of first mortgage bonds;
PSCo plans to issue approximately $400 million of first mortgage bonds; and
SPS plans to issue approximately $150 million of first mortgage bonds.
During 2016, Xcel Energy Inc. and its utility subsidiaries issued and anticipate issuing the following:
In March, Xcel Energy Inc.PSCo issued $400 million of 2.4 percent senior notes due March 15, 2021 and $350 million of 3.3 percent senior notes due June 1, 2025;
In May, NSP-Minnesota issued $350 million of 3.6 percent first mortgage bonds due May 15, 2046;
In June, PSCo issued $250 million of 3.553.80 percent first mortgage bonds due June 15, 2046;2047;
In August, SPS issued $300$450 million of 3.43.70 percent first mortgage bonds due Aug. 15, 2046;2047;
NSP-Minnesota issued $600 million of 3.60 percent first mortgage bonds due Sept. 15, 2047;
NSP-Wisconsin plans to issue approximately $100 million of first mortgage bonds in the fourth quarter; and
Xcel Energy Inc. plans to issue short-term debt in the fourth quarter to meet financing needs.
Xcel Energy Inc. and its utility subsidiaries’ 2018 financing plans reflect the following:
Xcel Energy Inc. plans to issue approximately $800$750 million of senior notes in the fourth quarter.unsecured bonds;
NSP-Minnesota plans to issue approximately $300 million of first mortgage bonds;
NSP-Wisconsin plans to issue approximately $150 million of first mortgage bonds;
PSCo plans to issue approximately $700 million of first mortgage bonds; and
SPS plans to issue approximately $300 million of first mortgage bonds.
Financing plans are subject to change, depending on capital expenditures, internal cash generation, market conditions and other factors. Xcel Energy does not anticipate issuing any additional equity, beyond its DRIP and benefit programs, over the next five years based on its current base capital expenditure plan.
Debt Redemption
On Aug. 30, 2017, SPS reacquired $250 million of debt with a coupon rate of 8.75 percent and an original maturity date of Dec. 1, 2018. The redemption resulted in payment of an early redemption premium of $21.6 million which was deferred as a regulatory asset.
On Sept. 29, 2017, NSP-Minnesota reacquired $500 million of debt with a coupon rate of 5.25 percent and an original maturity date of March 1, 2018. The redemption resulted in payment of an early redemption premium of $7.9 million which was deferred as a regulatory asset.
Off-Balance-Sheet Arrangements
Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives
Xcel Energy’s revised 2016narrowed 2017 GAAP and ongoing earnings guidance is $2.17$2.27 to $2.22$2.32 per share, compared with the previous issued guidance of $2.12$2.25 to $2.27$2.35 per share.(a)Key assumptions related to 2016 earnings are detailed below:assumptions:
Constructive outcomes in all rate case and regulatory proceedings.
Normal weather patterns are experienced for the remainder of the year.
Weather-normalized retail electric utility sales are projected to be relatively flat.within a range of 0 percent to 0.5 percent over 2016 levels.
Weather-normalized retail firm natural gas sales are projected to be relatively flat.within a range of 0 percent to 0.5 percent over 2016 levels.
Capital rider revenue is projected to increase by $35$45 million to $45 million over 2015 levels.
The change in O&M expenses is projected to be within a range of 0 percent to 1 percent from 2015 levels.
Depreciation expense is projected to increase approximately $185 million to $195 million over 2015 levels. Approximately $20 million of the increased depreciation expense and amortization will be recovered through the renewable development fund rider (not included in the capital rider) in Minnesota.
Property taxes are projected to increase approximately $20 million to $25 million over 2015 levels.
Interest expense (net of AFUDC — debt) is projected to increase $50 million to $60 million over 2015 levels.
AFUDC — equity is projected to increase approximately $0 million to $10 million from 2015 levels.
The ETR is projected to be approximately 34 percent to 36 percent.
Average common stock and equivalents are projected to be approximately 509 million shares.
Xcel Energy’s 2017 ongoing earnings guidance is $2.25 to $2.35 per share.(a) Key assumptions related to 2017 earnings are detailed below:
Constructive outcomes in all rate case and regulatory proceedings.
Normal weather patterns are experienced for the year.
Weather-normalized retail electric utility sales are projected to increase 0 percent to 0.5 percent.
Weather-normalized retail firm natural gas sales are projected to increase 0 percent to 0.5 percent.
Capital rider revenue is projected to increase by $65 million to $75$55 million over 2016 levels.
O&M expenses are projected to be flat.
Depreciation expense is projected to increase approximately $160$180 million to $170$190 million over 2016 levels.
Property taxes are projected to increasebe within a range of approximately $0 million to $10 million over 2016 levels.
Interest expense (net of AFUDC — debt) is projected to increase $5$10 million to $15$20 million over 2016 levels.
AFUDC — equity is projected to increase approximately $10 million to $20 million from 2016 levels.
The ETR is projected to be approximately 32 percent to 3431 percent.
Average common stock and equivalents are projected to be approximately 509 million shares.
Xcel Energy 2018 Earnings Guidance — Xcel Energy’s 2018 GAAP and ongoing earnings guidance is $2.37 to $2.47 per share.(a) Key assumptions:
Constructive outcomes in all rate case and regulatory proceedings.
Normal weather patterns.
Weather-normalized retail electric sales are projected to be within a range of 0 percent to 0.5 percent over 2017 levels.
Weather-normalized retail firm natural gas sales are projected to be within a range of 0 percent to 0.5 percent below 2017 levels.
Capital rider revenue is projected to increase by $40 million to $50 million over 2017 levels.
O&M expenses are projected to be flat.
Depreciation expense is projected to increase approximately $120 million to$130 million over 2017 levels.
Property taxes are projected to increase approximately $35 million to $45 million over 2017 levels.
Interest expense (net of AFUDC — debt) is projected to increase $20 million to $30 million over 2017 levels.
AFUDC — equity is projected to increase approximately $20 million to $30 million from 2017 levels.
The ETR is projected to be approximately 30 percent to 32 percent.
Average common stock and equivalents are projected to be approximately 510 million shares.
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(a) | Given theOngoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown nature of adjustments that may be necessary to reconcile ongoing diluted EPS to GAAP diluted EPS,adjustments. Xcel Energy is unable to forecast if any of these items will occur or provide a quantitative reconciliation of the guidance for ongoing diluted EPS to corresponding GAAP diluted EPS. |
Long-Term EPS and Dividend Growth Rate Objectives—
Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:
Deliver long-term annual EPS growth of 45 percent to 6 percent based on ongoing 2015 EPSoff of $2.10;a 2017 base of $2.30 per share (which represents the midpoint of the 2017 guidance range of $2.25 to $2.35 per share);
Deliver annual dividend increases of 5 percent to 7 percent;
Target a dividend payout ratio of 60 percent to 70 percent; and
Maintain senior unsecured debt credit ratings in the BBB+ to A range.
Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management’s view, not reflective of ongoing operations.
Item 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See Management’s Discussion and Analysis — Derivatives, Risk Management and Market Risk under Item 2.
Item 4 — CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Xcel Energy maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of Sept. 30, 2016,2017, based on an evaluation carried out under the supervision and with the participation of Xcel Energy’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures were effective.
Internal Control Over Financial Reporting
Effective JanuaryIn 2016, Xcel Energy implemented the general ledger modules, as well as initiated deployment of work management systems modules, of a new enterprise resource planning (ERP) system to improve certain financial and related transaction processes. During 2016 and 2017, Xcel Energy will continue implementingis continuing to implement additional modules and expects to beginincluding the conversion of existing work management systems to this new ERP system.same system during 2017. In connection with this ongoing implementation, Xcel Energy has updated and will continueis updating its internal control over financial reporting, as necessary, to accommodate modifications to its business processes and accounting procedures.systems. Xcel Energy does not expect thebelieve that this implementation of the additional modules to materially affectwill have an adverse effect on its internal control over financial reporting.
No changes in Xcel Energy’s internal control over financial reporting occurred during the most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, Xcel Energy’s internal control over financial reporting.
Part II — OTHER INFORMATION
Item 1 — LEGAL PROCEEDINGS
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.
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
Xcel Energy Inc.’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, 2015,2016, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.
Item 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table provides information about our purchases of equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Exchange Act for the quarter ended Sept. 30, 2016:2017:
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| | | | | | | | | | | | | |
| | Issuer Purchases of Equity Securities |
Period | | Total Number of Shares Purchased | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs |
July 1, 2016 — July 31, 2016 | | — |
| | $ | — |
| | — |
| | — |
|
Aug. 1, 2016 — Aug. 31, 2016 (a) | | 47,802 |
| | 42.22 |
| | — |
| | — |
|
Sept. 1, 2016 — Sept. 30, 2016 | | — |
| | — |
| | — |
| | — |
|
Total | | 47,802 |
| | | | — |
| | — |
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(a)
| Xcel Energy Inc. | Issuer Purchases of Equity Securities |
Period | | Total Number of Shares Purchased | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of Publicly Announced Plans or onePrograms | | Maximum Number (or Approximate Dollar Value) of its agents periodically purchases common shares in order to satisfy obligations underShares That May Yet Be Purchased Under the Stock Equivalent Plan for Non-Employee Directors.Plans or Programs |
July 1, 2017 — July 31, 2017 | | — |
| | $ | — |
| | — |
| | — |
|
Aug. 1, 2017 — Aug. 31, 2017 | | — |
| | — |
| | — |
| | — |
|
Sept. 1, 2017 — Sept. 30, 2017 | | — |
| | — |
| | — |
| | — |
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Total | | — |
| | | | — |
| | — |
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Item 4 — MINE SAFETY DISCLOSURES
None.
Item 5 — OTHER INFORMATION
None.
Item 6 — EXHIBITS
* Indicates incorporation by reference
+ Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors
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3.01* |
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3.02* | |
4.01* | |
| Third Amendment |
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101 | The following materials from Xcel Energy Inc.’s Quarterly Report on Form 10-Q for the quarter ended Sept. 30, 20162017 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) the Consolidated Statements of Common Stockholders’ Equity, (vi) Notes to Consolidated Financial Statements, and (vii) 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.
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| | XCEL ENERGY INC. |
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Oct. 28, 201627, 2017 | By: | /s/ JEFFREY S. SAVAGE |
| | Jeffrey S. Savage |
| | Senior Vice President, Controller |
| | (Principal Accounting Officer) |
| | |
| | /s/ ROBERT C. FRENZEL |
| | Robert C. Frenzel |
| | Executive Vice President, Chief Financial Officer |
| | (Principal Financial Officer) |