

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:

Intervenors’ 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.

~~In December 2016, SPS reached a settlement that resolves all issues in the rate case. The total estimated rate impact is $51.8 million.~~ The final rates ~~established in the case~~ are expected to be effective retroactive to ~~July 20, 2016. In December 2016, an ALJ approved interim rates, effective as of Dec. 10, 2016. In~~Jan. 23, 2018 through a customer surcharge. A PUCT decision is expected in the ~~fourth~~third quarter of 2016, SPS deferred certain costs associated with this rate case. In January 2017, the PUCT approved the settlement and no refund of interim rates was necessary. In April 2017, SPS filed a surcharge to recover $13.8 million for the additional revenue recovered by applying the final rates to customer billing units for the period of July 20, 2016 through Dec. 9, 2016.

~~Texas 2016 Transmission Cost Recovery Factor (TCRF) Application~~ — In February 2017, SPS filed with the PUCT to recover additional annual revenue of approximately $16.1 million through its TCRF, or 1.8 percent. The filing is based upon capital transmission additions made during 2016. SPS expects a PUCT decision and implementation of TCRF rates by mid-2017.2018.

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

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

In April 2017, the NMPRC dismissed SPS’ rate case. In May 2017, SPS ~~has excluded fuel and purchased power costs~~filed a notice of appeal to the New Mexico Supreme Court. A decision from ~~base rates. This~~the New Mexico Supreme Court is not expected until the second or third quarter of 2018.

SPS plans to file another base rate case ~~also takes into account the decline in sales of 380 MW in~~by November 2017 ~~from certain wholesale customers and seeks to adjust the service life of SPS’ Tolk power plant to~~utilizing a ~~remaining life through 2030 based on the investments to provide cooling water and the risks of investments in additional environmental controls.~~HTY ending June 2017.

~~The major components~~

Table of ~~the requested rate increase are summarized below:~~

(Millions of Dollars) Request
Capital expenditures $ 20.1
Allocator changes, including wholesale load reductions 11.5
Transmission expense, net of revenue, including charges paid to Southwest Power Pool, Inc. (SPP) for construction of regionally shared transmission projects 4.7
Depreciation, including adjustment of service life for the Tolk generating station 3.6
Rate case expenses 1.1
Other, net 0.4
Requested rate increase $ 41.4
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On April 10, 2017, the hearing examiner determined that SPS’ rate filing was deficient, and recommended the NMPRC extend the procedural schedule by one month and restart the suspension period once it is determined that the deficiencies are resolved. On April 19, 2017, the NMPRC ruled to dismiss SPS’ rate case and required SPS to refile a future test year rate case. SPS filed a motion for reconsideration on April 21, 2017 and the NMPRC is expected to consider that motion on May 10, 2017.

Pending Regulatory ~~Proceedings~~Proceeding — Federal Energy Regulatory Commission (FERC)

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

In December 2015, an ~~ALJ~~administrative law judge (ALJ) recommended the FERC approve a base ROE of 10.32 percent ~~using~~for 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 ROE ~~methodology~~policy adopted in a June 2014 ~~which~~order (Opinion 531). The FERC approved the ~~FERC upheld~~ALJ recommended 10.32 percent base ROE in an order issued 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 includes~~including a 50 basis point adder for RTO membership.

~~Table~~ Various parties requested rehearing of ~~Contents~~

the September 2016 order. The requests are pending FERC action.

In February 2015, a second complaint seeking to reduce the MISO ROE from 12.38 percent to 8.67 percent prior to any adder was filed with the FERC, resulting in a second period of potential refund from Feb. 12, 2015 to May 11, 2016. The MPUC, the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission and the Minnesota Department of Commerce joined a joint complainant/intervenor initial brief recommending an ROE of approximately 8.81 percent. FERC staff recommended a ROE of 8.78 percent. The MISO TOs recommended a ROE of 10.92 percent. In June 2016, the ALJ recommended a ROE of 9.7 percent, ~~the midpoint of the upper half of the discounted cash flow (DCF) range,~~ applying the ~~June 2014~~methodology adopted by the FERC in Opinion 531. A final FERC decision on the second ROE ~~methodology. A decision~~complaint was expected later in 2017, but ~~could be delayed~~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 ~~lack~~D.C. Circuit’s opinion to vacate and remand Opinion 531 will affect the September 2016 FERC order or the timing and outcome of ~~a quorum at~~ the ~~FERC.~~

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

As of ~~March~~Sept. 30, 2017, NSP-Minnesota has ~~recognized a current liability~~processed 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. ~~This liability is net of refunds processed during the first quarter of 2017.~~ NSP-Minnesota has also recognized a current refund liability ~~representing~~consistent with the best estimate of the final ROE for the Feb. 12, 2015 to May 11, 2016 complaint period.

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

In ~~April~~July 2016, ~~SPP filed a request with~~ the FERC granted SPP’s request for a waiver ~~that would~~to allow SPP to recover the charges not billed since 2008. ~~The FERC approved the request in July 2016. SPS and certain other parties requested rehearing of the FERC order.~~ In November 2016, SPP billed SPS a net amount, for the period from 2008 through August 2016, of $12.8 million for these charges, to be paid over a five-year period commencing November 2016. InSPP is also billing SPS ongoing charges of approximately $0.5 million per month. On the retail level, in October 2016, SPS filed applications for deferred accounting and future recovery of related costs in ~~Texas~~New Mexico and ~~New Mexico.~~Texas. In December 2016, SPS’ New Mexico application was consolidated with its base rate case, ~~and~~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 ~~will address the issue in its next base rate case. SPS anticipates~~is now seeking to recover these SPP charges ~~authorized~~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 even where SPS’ transmission service was not dependent upon the upgrade as required by ~~FERC~~the SPP OATT. If SPS’ complaint results in additional charges or refunds, SPS will ~~be recoverable through regulatory mechanisms.~~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, 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, 2017 and June 30, 2017 appropriately represent, in all material respects, the current status of commitments and contingent liabilities and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to Xcel Energy’s financial position.

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PPAs

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

The Xcel Energy utility subsidiaries had approximately 3,537 megawatts (MW) of capacity under long-term PPAs as of ~~March 31,~~Sept. 30, 2017 and Dec. 31, 2016, with entities that have been determined to be variable interest entities. Xcel Energy has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. These agreements have expiration dates through 2041.

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Guarantees and Bond Indemnifications

Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities under specified agreements or transactions. The guarantees and bond indemnities issued by Xcel Energy Inc. guarantee payment or performance by its subsidiaries. As a result, Xcel Energy Inc.’s exposure under the guarantees and bond indemnities is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum guarantee or indemnity amount. As of ~~March 31,~~Sept. 30, 2017 and Dec. 31, 2016, Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements.

The following table presents guarantees and bond indemnities issued and outstanding for Xcel Energy:


(Millions of Dollars)	March 31, 2017		Dec. 31, 2016		Sept. 30, 2017		Dec. 31, 2016
Guarantees issued and outstanding	$	18.6	$	18.8	$	19.1	$	18.8
Current exposure under these guarantees	0.1		0.1		—		0.1
Bonds with indemnity protection	43.6		43.0		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 Manufactured Gas Plant (MGP) Site — NSP-Wisconsin ~~has been~~was named a potentially responsible party (PRP) for contamination at a site in Ashland, Wis. The Ashland/Northern States Power Lakefront Superfund Site (the Site) includes NSP-Wisconsin property, previously operated as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park); and an area of Lake Superior’s Chequamegon Bay adjoining the park.

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

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

~~At March 31,~~The 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, 2017 and Dec. 31, 2016, NSP-Wisconsin had recorded a total liability of ~~$62.1~~$31.1 million and $64.3 million, respectively, for the entire site.

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NSP-Wisconsin has deferred the unrecovered portion of the estimated Site remediation costs as a regulatory asset. The ~~Public Service Commission of Wisconsin (PSCW)~~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 ~~for~~which included recovery of additional expenses associated with remediating the Site. ~~In December 2016,~~If approved, the ~~PSCW issued a written order approving the requested increase in~~ annual recovery of MGP clean-up costs would increase from ~~$7.6 million in 2016 to~~ $12.4 million in ~~2017.~~

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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 and commenced an investigation of the historic MGP and adjacent properties (the Fargo MGP Site). NSP-Minnesota has recommended that targeted source removal of impacted soils and historic MGP infrastructure should be performed. The North Dakota Department of Health approved NSP-Minnesota’s proposed cleanup plan in January 2017. ~~The~~It is anticipated that remediation activities will be performed in 2018, although the timing and final scope of remediation is dependent on whether ~~current property owners will agree to provide~~ 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 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 ~~May 2017.~~January 2018.

As of ~~March 31,~~Sept. 30, 2017 and Dec. 31, 2016, NSP-Minnesota had recorded a liability of ~~$11.1~~$16.2 million and $11.3 million, respectively, for the Fargo MGP Site. The current cost estimate for the remediation of the site is approximately $23.0 million, of which approximately $6.8 million has been spent. In December 2015, the ~~NDPSC~~North 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 to perform the approved remediation ~~final designs that will be developed to implement~~(including the ~~approved cleanup plan~~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 ~~nine~~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 ~~$2.9~~$4.5 million and $2.0 million for these sites ~~at March 31,~~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

Federal Clean Water Act (CWA) Waters of the United States Rule — In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) published a final rule that significantly ~~expands~~expanded the types of water bodies regulated under the CWA and ~~broadens~~broadened the scope of waters subject to federal jurisdiction. The final rule will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule and subsequently ruled that it, rather than the federal district courts, had jurisdiction over challenges to the rule. In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges to the rule. A ruling is expected byin the ~~end~~first quarter of ~~2017.~~2018.

In February 2017, President Trump issued an executive order requiring the EPA and the Corps to review and revise the final rule. ~~The executive order directs~~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 ~~consider interpreting the term~~develop a new definition of “Waters of the U.S.” ~~in a manner that is more narrow than the final rule. In March 2017, the EPA and the Corps published formal notice of the agencies’ intent to review the final rule and engage in further rulemaking.~~

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Federal CWA Effluent Limitations Guidelines (ELG) — In 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals.

~~Xcel Energy estimates that the capital cost to comply with the ELG rule for Colorado will range from $21 million to $32 million;~~

~~The estimated compliance cost for NSP-Minnesota’s Allen S. King Plant is approximately $10 million;~~

~~Xcel Energy continues to evaluate the cost of compliance at its other NSP-Minnesota and NSP-Wisconsin facilities potentially affected by this rule; and~~

~~The anticipated costs of compliance with the final rule at SPS are not expected to have a material impact on the results of operations, financial position or cash flows.~~

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

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Air

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

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

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

In October 2017, the EPA published a proposed rule to repeal the CPP, ~~have filed briefs opposing~~based on an analysis that the CPP exceeds the EPA’s ~~motion. A court ruling~~statutory authority under the Clean Air Act (CAA). The EPA will take public comment on the ~~EPA’s motion is expected in the second quarter of 2017.~~

~~Xcel Energy~~proposal for 60 days. The EPA stated it has ~~undertaken~~not yet determined whether it will promulgate a ~~number of initiatives that reduce~~new rule to regulate GHG emissions and respond to state renewable and energy efficiency goals. The CPP could require additional emission reductions in states in which Xcel Energy operates. If state plans do not provide credit for the investments Xcel Energy has already made to reduce GHG emissions, or if they require additional initiatives or emission reductions, then their requirements would potentially impose additional substantial costs. Xcel Energy cannot predict the costs of compliance with the final rule once it takes effect due to the uncertainty about what, if anything, the final rules may require. Xcel Energy believes compliance costs will be recoverable through regulatory mechanisms. If Xcel Energy’s regulators do not allow recovery of all or a part of the cost of capital investment or the operating and maintenance (O&M) costs incurred to comply with the CPP or cost recovery is not provided in a timely manner, it could have a material impact on results of operations, financial position or cash flows.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. The Best Available Retrofit Technology (BART) requirements of the EPA’s regional haze rules require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. Under BART, regional haze plans identify facilities that will have to reduce Sulfur Dioxide (SO₂₎₂), Nitrogen Oxide (NOx) and ~~Particulate Matter (PM)~~particulate 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, 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 ~~are being~~ implemented in those states. States are required to revise their plans every ten years. The next plans for Minnesota and Colorado will be due in 2021. Texas’ first regional haze plan ~~is still undergoing~~has undergone federal review as described below. ~~President Trump’s Administration has not yet taken any public position regarding its views of the proposed and final regional haze regulations affecting SPS facilities in Texas.~~

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~~Actions affecting Harrington Units:~~BART Determinations for Texas: Texas developed a State Implementation Plan (SIP) that ~~finds~~found 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 2014, the EPA proposed to approve the BART portion of the SIP, with substitution of CSAPR compliance for Texas’ reliance on CAIR. In January 2016, the EPA adopted a final rule that ~~defers~~deferred its approval of CSAPR compliance as BART until the EPA ~~considers~~considered further adjustments to CSAPR emission budgets under the D.C. Circuit Court’s remand of the Texas SO₂emission budgets. ~~In June 2016, the EPA issued a memorandum which allows Texas to voluntarily adopt the CSAPR emission budgets limiting annual SO~~₂ and NOx emissions and rely on those emission budgets to satisfy Texas’ BART obligations under the regional haze rules. The Texas Commission on Environmental Quality (TCEQ) has not utilized this option. The EPA then published a proposed rule in January 2017 that could have had the effect of requiring installation of dry scrubbers to reduce SO₂ emissions from Harrington Units 1 and 2. Investment costs associated with dry scrubbers for Harrington Units 1 and 2 could behave been approximately $400 million. ~~The EPA’s deadline to issue~~In September 2017, the EPA issued a final rule adopting a Texas only SO₂ trading program as a BART Alternative. The program allocated SO₂ allowances to electric generating units in Texas, including all three Harrington units and both Tolk units, consistent with their allocation under CSAPR, resulting in an emissions budget for Texas that is ~~September 2017.~~consistent with the EPA’s 2012 rule. SPS expects the allowance allocations to be sufficient for SO₂ emissions from Harrington and Tolk units in 2019 and future years. The anticipated costs of compliance are not expected to have a material impact on the results of operations, financial position or cash flows; and SPS believes that compliance costs would be recoverable through regulatory mechanisms.

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

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Revisions to the National Ambient Air Quality Standard (NAAQS) for Ozone — In 2015, the EPA revised the NAAQS for ozone by lowering the eight-hour standard from 75 parts per billion (ppb) to 70 ppb. 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

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

~~The~~e 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. ~~Five~~Six of the cases ~~have since been settled and seven~~ remain active, which ~~include~~includes one multi-district litigation (MDL) matter consisting 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 November 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 ~~dismissed~~in favor of e prime and Xcel Energy ~~from~~in Sinclair Oil and Farmland. Plaintiffs in both cases appealed this decision to the ~~Farmland lawsuit, and Farmland has appealed the dismissal.~~Ninth Circuit. Motions for summary judgment were also filed by defendants, including e prime, in all of the remaining lawsuits. ~~In March 2017 the U.S. District Court issued an order dismissing the claims against~~These motions were denied and e prime subsequently filed an appeal in September 2017. Dates for all matters pending before the ~~Sinclair lawsuit and denied plaintiffs motions for class certification in the other lawsuits. The U.S. District Court did~~Ninth Circuit have not ~~grant e prime’s summary judgment motions in the Wisconsin or Colorado cases.~~been scheduled. Xcel Energy, NSP-Wisconsin and e prime have concluded that a loss is remote.

~~Table of Contents~~

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 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. The matter has been fully briefed and plaintiff has requested oral arguments.~~petition to appeal the decision with the Colorado Supreme Court. It is uncertain whether the Colorado Supreme Court will grant the petition. DRC also brought a proceeding before the CPUC as assignee on behalf of two developers, Ryland Homes and Richmond Homes of Colorado. In March 2016, the 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. ~~DRC filed its brief in February~~In July 2017, ~~and PSCo’s answer brief~~a stipulation to dismiss this lawsuit with prejudice was filed ~~in March 2017.~~on behalf of all parties and granted by the Denver District Court.

Table of Contents

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


7.	Borrowings and Other Financing Instruments

Short-Term Borrowings

Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. NSP-Wisconsin does not participate in the money pool. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. The money pool balances are eliminated in consolidation.

Commercial Paper — Xcel Energy Inc. and its utility subsidiaries meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities. Commercial paper outstanding for Xcel Energy was as follows:


(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2017			Year Ended Dec. 31, 2016			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	605			392			514			392
Average amount outstanding	557			485			679			485
Maximum amount outstanding	719			1,183			867			1,183
Weighted average interest rate, computed on a daily basis	0.97		%	0.74		%	1.50		%	0.74		%
Weighted average interest rate at period end	1.18			0.95			1.53			0.95



Minnesota		41-0448030
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

414 Nicollet Mall
Minneapolis, Minnesota		55401
(Address of principal executive offices)		(Zip Code)



Large accelerated filer x		Accelerated filer ¨
Non-accelerated filer ¨		Smaller reporting company ¨
(Do not check if smaller reporting company)		Emerging growth company ¨



Class		Outstanding at ~~April 24,~~October 23, 2017
Common Stock, $2.50 par value		507,762,881 shares



PART I	FINANCIAL INFORMATION
Item 1 —	Financial Statements (unaudited)	3
	CONSOLIDATED STATEMENTS OF INCOME	3
	CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME	4
	CONSOLIDATED STATEMENTS OF CASH FLOWS	5
	CONSOLIDATED BALANCE SHEETS	6
	CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY	7
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	89
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3237
Item 3 —	Quantitative and Qualitative Disclosures about Market Risk	4957
Item 4 —	Controls and Procedures	4958

PART II	OTHER INFORMATION
Item 1 —	Legal Proceedings	4958
Item 1A —	Risk Factors	4958
Item 2 —	Unregistered Sales of Equity Securities and Use of Proceeds	5059
Item 6 —	Exhibits	5059

SIGNATURES		5160

	Certifications Pursuant to Section 302	1
	Certifications Pursuant to Section 906	1
	Statement Pursuant to Private Litigation	1

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 March 31						Three Months Ended Sept. 30						Nine Months Ended Sept. 30
		2017			2016			2017			2016			2017			2016
Operating revenues
Electric		$	2,299,060		$	2,185,119		$	2,783,569		$	2,799,964		$	7,420,646		$	7,209,225
Natural gas		625,703			565,689			214,253			221,956			1,129,795			1,046,544
Other		21,659			21,465			19,075			18,227			57,806			56,500
Total operating revenues		2,946,422			2,772,273			3,016,897			3,040,147			8,608,247			8,312,269

Operating expenses
Electric fuel and purchased power		925,221			861,852			1,006,160			1,037,263			2,850,480			2,755,083
Cost of natural gas sold and transported		365,134			312,117			63,998			67,566			543,452			469,754
Cost of sales — other		8,587			8,245			8,451			8,648			25,216			25,225
Operating and maintenance expenses		586,430			577,410			541,539			590,009			1,706,102			1,764,397
Conservation and demand side management program expenses		67,533			57,436
Conservation and demand side management expenses								73,728			63,914			206,121			177,266
Depreciation and amortization		365,204			320,020			371,091			328,503			1,102,015			971,057
Taxes (other than income taxes)		142,094			145,323			133,571			117,190			410,591			400,982
Total operating expenses		2,460,203			2,282,403			2,198,538			2,213,093			6,843,977			6,563,764

Operating income		486,219			489,870			818,359			827,054			1,764,270			1,748,505

Other income, net		6,446			4,250			5,089			578			14,143			6,388
Equity earnings of unconsolidated subsidiaries		7,875			13,182			7,080			9,701			22,496			32,500
Allowance for funds used during construction — equity		14,313			13,113			23,483			17,199			54,182			45,042

Interest charges and financing costs
Interest charges — includes other financing costs of $5,858 and $6,336, respectively		165,934			156,443
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
Allowance for funds used during construction — debt		(7,022		)	(5,990		)	(10,724		)	(7,532		)	(25,359		)	(20,206		)
Total interest charges and financing costs		158,912			150,453			157,079			158,325			472,573			465,074

Income before income taxes		355,941			369,962			696,932			696,207			1,382,518			1,367,361
Income taxes		116,664			128,650			204,791			238,412			423,844			471,459
Net income		$	239,277		$	241,312		$	492,141		$	457,795		$	958,674		$	895,902

Weighted average common shares outstanding:
Basic		508,278			508,667			508,581			508,941			508,468			508,840
Diluted		508,774			509,150			509,242			509,566			509,052			509,396

Earnings per average common share:
Basic		$	0.47		$	0.47		$	0.97		$	0.90		$	1.89		$	1.76
Diluted		0.47			0.47			0.97			0.90			1.88			1.76

Cash dividends declared per common share		$	0.36		$	0.34		$	0.36		$	0.34		$	1.08		$	1.02

See Notes to Consolidated Financial Statements



x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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			Retained Earnings			Accumulated Other Comprehensive Loss			Total Common Stockholders’ Equity
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
Net income									895,902						895,902
Other comprehensive income												4,792			4,792
Dividends declared on common stock									(520,968		)				(520,968		)
Issuances of common stock	486		1,216			15,110									16,326
Repurchases of common stock	(69	)	(173		)	(2,810		)							(2,983		)
Share-based compensation						(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

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


(Thousands of Dollars)	March 31, 2017			Dec. 31, 2016			Sept. 30, 2017			Dec. 31, 2016
Accounts receivable, net
Accounts receivable	$	832,540		$	827,112		$	859,242		$	827,112
Less allowance for bad debts	(51,292		)	(50,823		)	(51,621		)	(50,823		)
	$	781,248		$	776,289		$	807,621		$	776,289


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



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


(Millions of Dollars, incremental)	2016		2017		2018		2019			Total
Settlement revenues	$	74.99	$	59.86	$	—	$	50.12		$	184.97
(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		59.95		—		—		(0.20		)	59.75
Total rate impact	$	134.94	$	59.86	$	—	$	49.92		$	244.72	$	134.94	$	59.86	$	—	$	49.92		$	244.72


^(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.


^(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.


1.	Summary of Significant Accounting Policies


2.	Accounting Pronouncements


3.	Selected Balance Sheet Data


(Thousands of Dollars)	March 31, 2017		Dec. 31, 2016		Sept. 30, 2017		Dec. 31, 2016
Inventories
Materials and supplies	$	321,518	$	312,430	$	320,195	$	312,430
Fuel	150,025		181,752		166,173		181,752
Natural gas	47,538		110,044		130,307		110,044
	$	519,081	$	604,226	$	616,675	$	604,226


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



(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



(Millions of Dollars)	Request
Capital expenditures	$	20.1
Allocator changes, including wholesale load reductions	11.5
Transmission expense, net of revenue, including charges paid to Southwest Power Pool, Inc. (SPP) for construction of regionally shared transmission projects	4.7
Depreciation, including adjustment of service life for the Tolk generating station	3.6
Rate case expenses	1.1
Other, net	0.4
Requested rate increase	$	41.4


(Millions of Dollars)	Credit Facility ^(a)		Drawn ^(b)		Available		Credit Facility ^(a)		Drawn ^(b)		Available
Xcel Energy Inc.	$	1,000	$	391	$	609	$	1,000	$	422	$	578
PSCo	700		34		666		700		4		696
NSP-Minnesota	500		47		453		500		21		479
SPS	400		116		284		400		3		397
NSP-Wisconsin	150		33		117		150		92		58
Total	$	2,750	$	621	$	2,129	$	2,750	$	542	$	2,208


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


	March 31, 2017												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	$	24,161	$	24,161	$	—	$	—	$	—	$	24,161	$	32,727	$	32,727	$	—	$	—	$	—	$	32,727
Commingled funds:
Non U.S. equities	272,437		178,990		—		—		98,876		277,866		257,487		204,502		—		—		86,654		291,156
Emerging market debt funds	94,772		—		—		—		101,269		101,269		97,285		—		—		—		106,842		106,842
Commodity funds	106,571		—		—		—		88,749		88,749
Private equity investments	137,176		—		—		—		194,912		194,912		139,185		—		—		—		192,098		192,098
Real estate	125,410		—		—		—		187,609		187,609		129,219		—		—		—		195,506		195,506
Other commingled funds	151,048		—		—		—		161,936		161,936		146,179		14,964		—		—		145,313		160,277
Debt securities:
Government securities	27,369		—		27,199		—		—		27,199		45,310		—		44,944		—		—		44,944
U.S. corporate bonds	127,841		—		128,799		—		—		128,799		251,138		—		252,868		—		—		252,868
Non U.S. corporate bonds	25,345		—		25,556		—		—		25,556		46,245		—		46,611		—		—		46,611
Municipal bonds	5		—		5		—		—		5
Equity securities:
U.S. equities	275,101		501,543		—		—		—		501,543		258,075		509,564		—		—		—		509,564
Non U.S. equities	188,763		232,851		—		—		—		232,851		152,575		224,139		—		—		—		224,139
Total	$	1,555,999	$	937,545	$	181,559	$	—	$	833,351	$	1,952,455	$	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 ~~$131.9~~$131.8 million of equity investments in unconsolidated subsidiaries and ~~$103.6~~$111.7 million of rabbi trust assets and miscellaneous investments.


^(b)	Due to limited availability of published pricing and a lack of immediate redeemability, certain fund investments measured at NAV are not required to be categorized within the fair value hierarchy.


	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	$	—	$	1,100	$	3,017	$	23,082	$	27,199	$	—	$	1,275	$	2,303	$	41,366	$	44,944
U.S. corporate bonds	354		38,741		74,617		15,087		128,799		3,834		64,119		150,741		34,174		252,868
International corporate bonds	—		8,085		13,443		4,028		25,556
Municipal bonds	—		—		5		—		5
Non U.S. corporate bonds											—		13,793		26,651		6,167		46,611
Debt securities	$	354	$	47,926	$	91,082	$	42,197	$	181,559	$	3,834	$	79,187	$	179,695	$	81,707	$	344,423


(Amounts in Thousands) ^(a)(b)	March 31, 2017	Dec. 31, 2016	Sept. 30, 2017	Dec. 31, 2016
Megawatt hours of electricity	31,838	46,773	78,733	46,773
Million British thermal units of natural gas	92,801	121,978	62,279	121,978
Gallons of vehicle fuel			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.


	Three Months Ended March 31, 2017																	Three Months Ended Sept. 30, 2017
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:							Pre-Tax Gains (Losses) Recognized During the Period in Income					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)					Pre-Tax Gains Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	1,359	^(a)	$	—			$	—				$	—		$	—			$	1,579		^(a)	$	—			$	—
Vehicle fuel and other commodity																		38			—				(11		)	^(b)	—				—
Total	$	—	$	—		$	1,359		$	—			$	—				$	38		$	—			$	1,568			$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—		$	—			$	1,001		^(c)		$	—		$	—			$	—			$	—			$	1,282	^(c)
Electric commodity	—		794			—			(3,998		)	^(d)	—					—			17,750				—				(3,122		)	^(d)	—
Natural gas commodity	—		(6,161		)	—			1,075			^(e)	(4,070		)	^(e)		—			(2,076		)		—				—				—
Total	$	—	$	(5,367	)	$	—		$	(2,923	)		$	(3,069	)			$	—		$	15,674			$	—			$	(3,122	)		$	1,282




	Nine Months Ended Sept. 30, 2017
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:								Pre-Tax Gains (Losses) Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss				Regulatory Assets and (Liabilities)
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	4,257		^(a)	$	—			$	—
Vehicle fuel and other commodity	81		—			(16		)	^(b)	—				—
Total	$	81	$	—		$	4,241			$	—			$	—
Other derivative instruments
Commodity trading	$	—	$	—		$	—			$	—			$	8,069		^(c)
Electric commodity	—		17,245			—				(9,435		)	^(d)	—
Natural gas commodity	—		(9,921		)	—				1,075			^(e)	(4,070		)	^(e)
Total	$	—	$	7,324		$	—			$	(8,360	)		$	3,999




	Three Months Ended Sept. 30, 2016
	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:						Pre-Tax Losses Reclassified into Income During the Period from:						Pre-Tax Gains (Losses) Recognized During the Period in Income
(Thousands of Dollars)	Accumulated Other Comprehensive Loss			Regulatory (Assets) and Liabilities			Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	1,502	^(a)	$	—		$	—
Vehicle fuel and other commodity	(6		)	—			46		^(b)	—			—
Total	$	(6	)	$	—		$	1,548		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	—		$	—		$	1,779		^(c)
Electric commodity	—			15,497			—			2,491		^(d)	—
Natural gas commodity	—			(5,737		)	—			—			(6		)	^(e)
Total	$	—		$	9,760		$	—		$	2,491		$	1,773


	Three Months Ended March 31, 2016																	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 Gains (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	$	—		$	—		$	1,485	^(a)	$	—		$	—				$	—		$	—			$	4,470	^(a)	$	—		$	—
Vehicle fuel and other commodity	(6		)	—			57		^(b)	—			—					7			—				150		^(b)	—			—
Total	$	(6	)	$	—		$	1,542		$	—		$	—				$	7		$	—			$	4,620		$	—		$	—
Other derivative instruments

Commodity trading	$	—		$	—		$	—		$	—		$	1,009		^(c)		$	—		$	—			$	—		$	—		$	3,269		^(c)
Electric commodity	—			(265		)	—			8,631		^(d)	—					—			14,528				—			30,024		^(d)	—
Natural gas commodity	—			(2,702		)	—			11,666		^(e)	(5,024		)	^(e)		—			(2,376		)		—			11,666		^(e)	(5,005		)	^(e)
Total	$	—		$	(2,967	)	$	—		$	20,297		$	(4,015	)			$	—		$	12,152			$	—		$	41,690		$	(1,736	)


^(b)	Amounts are recorded to ~~O&M~~operating and maintenance (O&M) expenses.


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


^(d)	Amounts are recorded to electric fuel and purchased power. These derivative settlement ~~gain~~gains and ~~loss amounts~~losses 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.


^(a)	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.