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Commitments and Contingencies
 12 Months Ended
Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies
Commitments and Contingencies
Legal
Xcel Energy is involved in various litigation matters that are being defended and handled in the ordinary course of business. Assessing whether a loss is probable or a reasonable possibility, and whether the loss or a range of loss is estimable, often involves complex judgments regarding future events. Management maintains accruals for losses that are probable of being incurred and subject to reasonable estimation. Management may be unable to estimate an amount or range of a reasonably possible loss in certain situations, including 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 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.
Gas Trading Litigation — 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.  Multiple lawsuits seeking monetary damages were commenced against e prime and its affiliates, including Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were all consolidated in the U.S. District Court in Nevada.
In the fourth quarter of 2018, four cases were settled. Two cases remain active which include an MDL matter consisting of a Colorado class (Breckenridge) and a Wisconsin class (Arandell Corp.).
Breckenridge/Colorado — Case has been remanded to the MDL panel, and is expected to be referred back to the U.S. District Court in Colorado. Xcel Energy has concluded that a loss is remote.
Arandell Corp. — In November 2017, the U.S. District Court in Nevada granted summary judgment against two plaintiffs in the Arandell Corp. case in favor of Xcel Energy and NSP-Wisconsin, leaving only three individual plaintiffs remaining in the litigation. In addition, the plaintiffs’ motions for class certification and remand back to originating courts were denied in March 2017.
Plaintiffs have asked the lower court to remand the cases back to the court where the actions were originally filed anticipating class certification. A hearing date has not been set. Xcel Energy has concluded that a loss is remote.
Line Extension Disputes — In December 2015, the DRC filed a lawsuit seeking monetary damages in the Denver District 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. The dispute involves claims by over fifty developers. In February 2018, the Colorado Supreme Court denied DRC’s petition to appeal the Denver District Court’s dismissal of the lawsuit, effectively terminating this litigation. However, in January 2018, DRC filed a new lawsuit in Boulder County District Court, asserting a single claim that PSCo was required to file its line extension agreements with the CPUC but failed to do so.
This claim is substantially similar to the arguments previously raised by DRC. PSCo filed a motion to dismiss this claim, which was granted in May 2018. DRC subsequently filed an appeal to the Colorado Court of Appeals with its opening brief in January 2019 and PSCo filed its answer brief in February 2019. It is uncertain when a decision will be rendered.
PSCo has concluded that a loss is remote with respect to both of these matters as the service agreements were developed to implement CPUC approved tariffs and PSCo has complied with the tariff provisions. If a loss were sustained, PSCo believes it would be allowed to recover costs through traditional regulatory mechanisms. Amount or range in dispute is presently unknown and no accrual has been recorded for this matter.
Rate Matters
NSP-Minnesota — Sherco — In NSP-Minnesota’s 2013 fuel reconciliation filing, the MPUC made recovery of replacement power costs associated with the 2011 incident at its Sherco Unit 3 plant provisional and subject to further review following conclusion of litigation commenced by NSP-Minnesota, SMMPA (Co-owner of Sherco Unit 3) and insurance companies against GE.
In 2018, NSP-Minnesota and SMMPA reached a settlement with GE. NSP-Minnesota has notified the MPUC of its proposal to refund the GE settlement proceeds back to customers through the FCA.
The insurance providers continued their litigation against GE and the case went to trial. In 2018, GE prevailed in the lawsuit with the insurance companies, however, the jury found comparable fault, finding that GE was 52% and NSP-Minnesota was 48% at fault. At that point in the litigation, NSP-Minnesota was no longer involved in the case and was not present to make arguments about its role in the event. The specific issue leading to the fault apportionment was also not before the jury and not relevant to the outcome of the trial.
In January 2019, the DOC recommended that NSP-Minnesota refund $20 million of previously recovered purchased power costs to its customers, based on the jury’s apportionment of fault. The OAG recommended the MPUC withhold any decision until the underlying litigation by the insurance providers (currently under appeal) is concluded. The DOC subsequently filed comments agreeing with the OAG’s recommendation to withhold a decision pending the outcome of any appeals.
NSP-Minnesota filed reply comments arguing that the DOC recommendations are without merit and that it acted prudently in operating the plant and its settlement with GE was reasonable.
MISO ROE Complaints — In November 2013 and February 2015, customers filed complaints against MISO TOs including NSP-Minnesota and NSP-Wisconsin. The first complaint argued for a reduction in the base ROE in MISO transmission formula rates from 12.38% to 9.15%, and removal of ROE adders (including those for RTO membership). The second complaint sought to reduce base ROE from 12.38% to 8.67%.
In September 2016, the FERC issued an order granting a 10.32% base ROE (10.82% with the RTO adder) effective for the first complaint period of Nov. 12, 2013 to Feb. 11, 2015 and subsequent to the date of the order. The D.C. Circuit subsequently vacated and remanded FERC Opinion No. 531, which had established the ROE methodology on which the September 2016 FERC order was based.
In October 2018, the FERC issued a NETO base ROE order that addressed the D.C. Circuit’s actions on Opinion No. 531. Under a new proposed two step ROE approach, the FERC has indicated an intention to dismiss an ROE complaint if the existing ROE falls within the range of just and reasonable ROEs based on equal weighting of the DCF, CAPM, and Expected Earnings models. The FERC proposes that if necessary, it would then set a new ROE by averaging the results of these models plus a Risk Premium model.
With respect to the MISO TOs, the FERC subsequently made preliminary determinations in a November 2018 order that the MISO base ROE in effect for the first complaint period (12.38%) was outside the range of reasonableness, and should be reduced. The FERC indicated its preliminary analysis using the new ROE approach resulted in a base ROE of 10.28% for the first compliant period, compared to the previously ordered base ROE of 10.32%. A procedural schedule has been set for the first half of 2019, with the FERC expected to act no earlier than the second half of 2019. NSP-Minnesota has recognized a current refund liability consistent with its best estimate of the final ROE.
SPP OATT Upgrade Costs — Under the SPP OATT, costs of 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 charge for these upgrades since 2008, but SPP had not been charging its customers for these upgrades. In 2016, the FERC granted SPP’s request to recover these previously unbilled charges. SPP subsequently billed SPS approximately $13 million for these charges.
In July 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting SPP the right to recover these previously unbilled charges was remanded to the FERC. Assessment of these charges (from 2008 - 2016) is being reviewed by the FERC, which is expected to rule in the first quarter of 2019.
In October 2017, SPS filed a separate complaint against SPP asserting that SPP has assessed upgrade charges to SPS in violation of the SPP OATT. The FERC has granted a rehearing for further consideration in May 2018. The timing of FERC action on the SPS rehearing is uncertain. If SPS’ complaint results in additional charges or refunds, it will seek to recover or refund the differential in future rate proceedings.
Environmental
New and changing federal and state environmental mandates can create financial liabilities for Xcel Energy, which are normally recovered through the regulated rate process.
Site Remediation — Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. Xcel Energy Inc.’s subsidiaries may sometimes pay all or a portion of the cost to remediate sites where past activities of their predecessors or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which one or more of Xcel Energy Inc.’s subsidiaries are alleged to have sent wastes to that site.
MGP Sites
Ashland MGP Site — NSP-Wisconsin was named a responsible party for contamination at the Ashland/Northern States Power Lakefront Superfund Site (the Site) in Ashland, Wisconsin. Remediation and restoration activities are anticipated to be completed in 2019 and groundwater treatment activities will continue for many years.
Current cost estimate for remediation of the entire site is approximately $192 million, of which approximately $165 million has been spent. As of Dec. 31, 2018 and 2017, NSP-Wisconsin recorded a total liability of $27 million and $30 million, respectively, for the entire site.
NSP-Wisconsin has deferred the unrecovered portion of the estimated Site remediation costs as a regulatory asset. The PSCW has 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 10-year period and to apply a 3% carrying cost to the unamortized regulatory asset.
MGP, Landfill or Disposal Sites — Xcel Energy is currently investigating or remediating twelve MGP, landfill or other disposal sites across its service territories, in addition to the Ashland MGP Site, and these activities will continue through at least 2019. Xcel Energy accrued $9 million as of Dec. 31, 2018 and $19 million as of Dec. 31, 2017 for these sites. There may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of the costs incurred.
Environmental Requirements — Water and Waste
Coal Ash Regulation — Xcel Energy’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. In 2015, the EPA published the CCR Rule. Litigation was brought challenging the rule in the D.C. Circuit.
Under the CCR Rule, utilities are required to complete groundwater sampling around their CCR landfills and surface impoundments. Xcel Energy has identified at least two sites in Colorado where SSLs exist in the groundwater near landfills and/or impoundments. Xcel Energy has completed removal of CCR from these impoundments and plans to close these landfills. By the end of 2019, only nine of Xcel Energy’s regulated ash units are expected to be in operation. Xcel Energy is conducting additional groundwater sampling and will evaluate whether corrective action is required at any CCR landfills or surface impoundments.
Until Xcel Energy completes its assessment, it is uncertain what impact, if any, there will be on the operations, financial condition or cash flows. In August 2018, the D.C. Circuit ruled that the EPA cannot allow utilities to continue to use unlined impoundments (including clay lined impoundments) for the storage or disposal of coal ash. Litigation is ongoing regarding the deadline for closing or retrofitting these impoundments. The decision will require Xcel Energy to expedite closure of one impoundment in Minnesota (see ARO removal costs below) and will require construction of a new impoundment, which is estimated to cost $6 million.
Federal CWA WOTUS Rule — In 2015, the EPA and Corps published a final rule that significantly broadened the scope of waters under the CWA that are subject to federal jurisdiction, referred to as “WOTUS”. The Rule has been subject to significant litigation and is currently stayed in a portion of the country. Xcel Energy cannot estimate potential impacts until the legal and administrative processes are finalized, but expects costs will be recoverable through regulatory mechanisms.
Federal CWA ELG — In 2015, the EPA issued a final ELG rule for power plants that discharge treated effluent to surface waters as well as utility-owned landfills that receive CCRs. In 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport until November 2020. After 2020, Xcel Energy estimates that ELG compliance will cost approximately $12 million to complete. The EPA, however, is conducting a rulemaking process to potentially revise the effluent limitations and pretreatment standards, which may impact compliance costs. Xcel Energy anticipates these costs will be fully recoverable through regulatory mechanisms.
Federal CWA Section 316(b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing impingement and entrainment of aquatic species. Xcel Energy estimates the likely cost for complying with impingement and entrainment requirements is approximately $40 million, to be incurred between 2019 and 2028. Xcel Energy believes six NSP-Minnesota plants and two NSP-Wisconsin plants could be required by state regulators to make improvements to reduce impingement and entrainment. The exact total cost of the impingement and entrainment improvements is uncertain, but could be up to approximately $200 million. Xcel Energy anticipates these costs will be fully recoverable through regulatory mechanisms.
Environmental Requirements — Air
Regional Haze Rules — The regional haze program requires SO2, NOX and PM emission controls at power plants to reduce visibility impairment in national parks and wilderness areas. The program includes BART and reasonable further progress.
The requirements of the first regional haze plans developed by Minnesota and Colorado have been approved and implemented. Texas’ first regional haze plan has undergone federal review as described below.
BART Determination for Texas: The EPA has issued a revised final rule adopting a BART alternative Texas only SO2 trading program that applies to all Harrington and Tolk units. Under the trading program, SPS expects the allowance allocations to be sufficient for SO2 emissions. The anticipated costs of compliance are not expected to have a material impact; and SPS believes that compliance costs would be recoverable through regulatory mechanisms.
Several parties have challenged whether the final rule issued by the EPA should be considered to have met the requirements imposed in a Consent Decree entered by the United States District Court for the District of Columbia that established deadlines for the EPA to take final action on state regional haze plan submissions. The court has required status reports from the parties while the EPA works on the reconsideration rulemaking.
In December 2017, the National Parks Conservation Association, Sierra Club, and Environmental Defense Fund appealed the EPA’s 2017 final BART rule to the Fifth Circuit and filed a petition for administrative reconsideration. In January 2018, the court granted SPS’ motion to intervene in the Fifth Circuit litigation in support of the EPA’s final rule. The court has held the litigation in abeyance while the EPA decided whether to reconsider the rule. In August 2018, the EPA started a reconsideration rulemaking. It is not known when the EPA will make a final decision on this proposal.
Reasonable Progress Rule: In 2016, the EPA adopted a final rule establishing a federal implementation plan for reasonable further progress under the regional haze program for the state of Texas. The rule imposes SO2 emission limitations that would require 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 $600 million. SPS appealed the EPA’s decision and obtained a stay of the final rule.
In March 2017, the Fifth Circuit remanded the rule to the EPA for reconsideration, leaving the stay in effect. In a future rulemaking, the EPA will address whether SO2 emission reductions beyond those required in the BART alternative rule are needed at Tolk under the “reasonable progress” requirements. The EPA has not announced a schedule for acting on the remanded rule.
Implementation of the NAAQS for SO2 — The EPA has designated all areas near SPS’ generating plants as attaining the SO2 NAAQS with an exception. The EPA issued final designations which found the area near the SPS Harrington plant 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.
If the area near the Harrington plant is designated nonattainment in 2020, the TCEQ will need to develop an implementation plan, designed to achieve the NAAQS by 2025. The TCEQ could require additional SO2 controls at Harrington as part of such a plan. Xcel Energy cannot evaluate the impacts until the final designation 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 condition or cash flows.
AROs — AROs have been recorded for Xcel Energy’s assets. For nuclear assets, the ARO is associated with the decommissioning of the NSP-Minnesota nuclear generating plants, Monticello and PI.
Aggregate fair value of NSP-Minnesota’s legally restricted assets, for funding future nuclear decommissioning, was $2.1 billion for 2018 and 2017.
Xcel Energy’s AROs were as follows:
 
 
Dec. 31, 2018
(Millions 
of Dollars)
 
Jan. 1, 2018
 
Amounts
Incurred
(a)
 
Amounts
Settled
(b)
 
Accretion
 
Cash Flow Revisions (c)
 
Dec. 31, 2018
Electric
 
 
 
 
 
 
 
 
 
 
 
 
Nuclear
 
$
1,874

 
$
—

 
$
—

 
$
94

 
$
—

 
$
1,968

Steam, hydro, and other production
 
192

 
—

 
(14
)
 
8

 
(9
)
 
177

Wind
 
96

 
12

 
—

 
4

 
7

 
119

Distribution
 
21

 
—

 
—

 
1

 
20

 
42

Miscellaneous
 
5

 
—

 
—

 
—

 
2

 
7

Natural gas
 
 
 
 
 
 
 
 
 
 
 
 
Transmission and distribution
 
282

 
—

 
—

 
13

 
(46
)
 
249

Miscellaneous
 
4

 
—

 
—

 
—

 
—

 
4

Common
 
 
 
 
 
 
 
 
 
 
 
 
Miscellaneous
 
1

 
—

 
—

 
—

 
—

 
1

Non-utility
 
 
 
 
 
 
 
 
 
 
 
 
Miscellaneous
 
—

 
1

 
—

 
—

 
—

 
1

Total liability
 
$
2,475

 
$
13

 
$
(14
)
 
$
120

 
$
(26
)
 
$
2,568

(a) 
Amounts incurred related to the PSCo Rush Creek wind farm and Nicollet Projects community solar gardens, which were placed in service in 2018.
(b) 
Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities.
(c) 
In 2018, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by increased discount rates. Changes in electric distribution AROs primarily related to increased labor costs.
 
 
Dec. 31, 2017
(Millions 
of Dollars)
 
Jan. 1, 2017
 
Amounts Incurred
 
Amounts Settled (a)
 
Accretion
 
Cash Flow Revisions (b)
 
Dec. 31, 2017
Electric
 
 
 
 
 
 
 
 
 
 
 
 
Nuclear
 
$
2,249

 
$
—

 
$
—

 
$
114

 
$
(489
)
 
$
1,874

Steam, hydro, and other production
 
205

 
1

 
(29
)
 
9

 
6

 
192

Wind
 
92

 
—

 
—

 
4

 
—

 
96

Distribution
 
20

 
—

 
—

 
1

 
—

 
21

Miscellaneous
 
5

 
—

 
—

 
—

 
—

 
5

Natural gas
 
 
 
 
 
 
 
 
 
 
 
 
Transmission and distribution
 
205

 
—

 
—

 
8

 
69

 
282

Miscellaneous
 
4

 
—

 
—

 
—

 
—

 
4

Common
 
 
 
 
 
 
 
 
 
 
 
 
Miscellaneous
 
2

 
—

 
(1
)
 
—

 
—

 
1

Total liability
 
$
2,782

 
$
1

 
$
(30
)
 
$
136

 
$
(414
)
 
$
2,475


(a) 
Amounts settled related to asbestos abatement, closure of ash containment facilities, and removal and disposal of storage tanks and other above ground equipment.
(b) 
In 2017, AROs were revised for changes in timing and estimates of cash flows. Nuclear AROs decreased due to updated assumptions. Changes in gas transmission and distribution AROs were primarily related to increased labor costs.
Indeterminate AROs — Other plants or buildings may contain asbestos due to the age of many of Xcel Energy’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2018. Therefore, an ARO was not recorded for these facilities.
Removal Costs — Xcel Energy records a regulatory liability for the plant removal costs of its utility subsidiaries that are recovered currently in rates. Removal costs have accumulated based on varying rates as authorized by the appropriate regulatory entities. The utility subsidiaries have estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates.
Accumulated balances by entity at Dec. 31:
(Millions of Dollars)
 
2018
 
2017
NSP-Minnesota
 
$
485

 
$
442

PSCo
 
344

 
346

SPS
 
188

 
197

NSP-Wisconsin
 
158

 
146

Total Xcel Energy
 
$
1,175

 
$
1,131

Nuclear Related
Nuclear Insurance — NSP-Minnesota’s public liability for claims from any nuclear incident is limited to $14.1 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has secured $450 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $13.6 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government.
NSP-Minnesota is subject to assessments of up to $138 million per reactor-incident for each of its three licensed reactors, for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $21 million per reactor-incident during any one year. Maximum assessments are subject to inflation adjustments by the NRC and state premium taxes. The NRC’s last adjustment was effective November 2018.
NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from NEIL and EMANI. The coverage limits are $2.3 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage, including the cost of replacement power during prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term.
All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL and EMANI to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. NSP-Minnesota could be subject to annual maximum assessments of approximately $18 million for business interruption insurance and $39 million for property damage insurance if losses exceed accumulated reserve funds.
Nuclear Fuel Disposal — NSP-Minnesota is responsible for temporarily storing spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from U.S. nuclear plants, but no such facility is yet available.
NSP-Minnesota owns temporary on-site storage facilities for spent fuel at its Monticello and PI nuclear plants, which consist of storage pools and dry cask facilities. The Monticello dry-cask storage facility currently stores all 30 of the authorized canisters. The PI dry-cask storage facility currently stores 44 of the 64 authorized casks. Monticello’s future spent fuel will continue to be placed in its spent fuel pool. The decommissioning plan addresses the disposition of spent fuel at the end of the licensed life.
Regulatory Plant Decommissioning Recovery — Decommissioning activities for NSP-Minnesota’s nuclear facilities are planned to begin at the end of each unit’s operating license and be completed by 2091. NSP-Minnesota’s current operating licenses allow continued use of its Monticello nuclear plant until 2030 and its PI nuclear plant until 2033 for Unit 1 and 2034 for Unit 2.
Future decommissioning costs of nuclear facilities are estimated through triennial periodic studies that assess the costs and timing of planned nuclear decommissioning activities for each unit.
Obligation for decommissioning is expected to be funded 100% by the external decommissioning trust fund. This cost study assumes the external decommissioning fund will earn an after-tax return between 5.23% and 6.30% Realized and unrealized gains on fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Decommissioning costs are quantified in 2014 dollars. Escalation rates are 4.36% for plant removal activities and 3.36% for fuel management and site restoration activities.
NSP-Minnesota has accumulated $2.1 billion of assets held in external decommissioning trusts in 2018. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation. Xcel Energy believes future decommissioning costs will continue to be recovered in customer rates. The following amounts were prepared on a regulatory basis and not directly recorded in the financial statements (ARO).
 
 
Regulatory Basis
(Millions of Dollars)
 
2018
 
2017
Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars)
 
$
3,012

 
$
3,012

Effect of escalating costs
 
539

 
396

Estimated decommissioning cost obligation (in current dollars)
 
3,551

 
3,408

Effect of escalating costs to payment date
 
7,654

 
7,797

Estimated future decommissioning costs (undiscounted)
 
11,205

 
11,205

Effect of discounting obligation (using average risk-free interest rate of 3.33% and 2.80% for 2018 and 2017, respectively)
 
(6,911
)
 
(6,398
)
Discounted decommissioning cost obligation
 
$
4,294

 
$
4,807

Assets held in external decommissioning trust
 
$
2,055

 
$
2,143

Underfunding of external decommissioning fund compared to the discounted decommissioning obligation
 
2,239

 
2,664


Calculations and data used by the regulator in approving NSP-Minnesota’s rates are useful in assessing future cash flows. Regulatory basis information is a means to reconcile amounts previously provided to the MPUC and utilized for regulatory purposes to amounts used for financial reporting.
Reconciliation of the discounted decommissioning cost obligation - regulated basis to the ARO recorded in accordance with GAAP:
(Millions of Dollars)
 
2018
 
2017
Discounted decommissioning cost obligation - regulated basis
 
$
4,294

 
$
4,807

Differences in discount rate and market risk premium
 
(1,447
)
 
(1,403
)
O&M costs not included for GAAP
 
(879
)
 
(1,041
)
ARO differences between 2017 and 2014 cost studies
 
—

 
(489
)
Nuclear production decommissioning ARO - GAAP
 
$
1,968

 
$
1,874


Decommissioning expenses recognized as a result of regulation:
(Millions of Dollars)
 
2018
 
2017
 
2016
Annual decommissioning recorded as depreciation expense: (a) (b)
 
$
20

 
$
20

 
$
20


(a) 
Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.
(b) 
Decommissioning expenses in 2018, 2017 and 2016 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14 million.
The 2014 nuclear decommissioning filing, approved in 2015, was used for regulatory presentation in 2018, 2017 and 2016. The 2017 filing, effective Jan. 1, 2019, has been approved by the MPUC.
Leases — Xcel Energy has three leases accounted for as capital leases. The assets and liabilities of a capital lease are recorded at the lower of fair market value of the leased asset or the present value of future lease payments and are amortized over the term of the contract.
WYCO is a joint venture with CIG to develop and lease natural gas pipeline, storage and compression facilities. Xcel Energy Inc. has a 50% ownership interest in WYCO. WYCO leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage and transportation services to PSCo under separate service agreements.
PSCo accounts for its Totem natural gas storage service arrangement with CIG as a capital lease. Xcel Energy Inc. eliminates 50% of the capital lease obligation related to WYCO in the consolidated balance sheet along with an equal amount of Xcel Energy Inc.’s equity investment in WYCO.
PSCo records amortization for its capital lease assets as electric fuel and purchased power and cost of natural gas sold and transported on the consolidated statements of income.
Property held under capital leases:
(Millions of Dollars)
 
Dec. 31, 2018
 
Dec. 31, 2017
Gas storage facilities
 
$
201

 
$
201

Gas pipeline
 
21

 
21

Property held under capital leases
 
222

 
222

Accumulated depreciation
 
(77
)
 
(71
)
Total property held under capital leases, net
 
$
145

 
$
151


Remaining leases, primarily for real estate and certain natural gas generating facilities operated under PPAs, as well as railcars, aircraft and other equipment, are accounted for as operating leases.
Total expenses (including capacity payments) under operating lease obligations for Xcel Energy and the corresponding capacity payments for PPAs accounted for as operating leases for the year ended Dec. 31:
(Millions of Dollars)
 
2018
 
2017
 
2016
Total expense
 
$
248

 
$
246

 
$
255

Capacity payments
 
210

 
210

 
216


Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been accounted for as operating leases.
Future commitments under operating and capital leases:
(Millions of Dollars)
 
Operating
Leases
 
PPA (a) (b)
Operating
Leases
 
Total
Operating
Leases
 
Capital Leases
 
2019
 
$
32

 
$
207

 
$
239

 
$
14

 
2020
 
26

 
208

 
234

 
14

 
2021
 
25

 
210

 
235

 
14

 
2022
 
24

 
197

 
221

 
12

 
2023
 
22

 
186

 
208

 
12

 
Thereafter
 
154

 
883

 
1,037

 
220

 
Total minimum obligation
286

 
Interest component of obligation
(201
)
 
Present value of minimum obligation
$
85

(c) 
(a) 
Amounts do not include PPAs accounted for as executory contracts.
(b) 
PPA operating leases contractually expire through 2034.
(c) 
Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.
Non-Lease PPAs — NSP Minnesota, PSCo and SPS have entered into PPAs with other utilities and energy suppliers with expiration dates through 2039 for purchased power to meet system load and energy requirements, meet operating reserve obligations and as part of wholesale and commodity trading activities. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs accounted for as executory contracts contain minimum energy purchase commitments.
Capacity and energy payments are contingent on the IPPs meeting contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of price adjustments on our financial results are mitigated through purchased energy cost recovery mechanisms.
Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $131 million, $168 million and $191 million in 2018, 2017 and 2016, respectively.
At Dec. 31, 2018, the estimated future payments for capacity and energy that the utility subsidiaries of Xcel Energy are obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:
(Millions of Dollars)
 
Capacity
 
Energy (a)
2019
 
$
86

 
$
99

2020
 
70

 
109

2021
 
78

 
157

2022
 
77

 
173

2023
 
79

 
177

Thereafter
 
125

 
328

Total
 
$
515

 
$
1,043

(a) 
Excludes contingent energy payments for renewable energy PPAs.
Fuel Contracts — Xcel Energy has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal, nuclear fuel and natural gas requirements. These contracts expire between 2019 and 2060. Xcel Energy is required to pay additional amounts depending on actual quantities shipped under these agreements.
Estimated minimum purchases under these contracts as of Dec. 31, 2018:
(Millions of Dollars)
 
Coal
 
Nuclear fuel
 
Natural gas supply
 
Natural gas supply and transportation
2019
 
$
461

 
$
127

 
$
416

 
$
268

2020
 
260

 
51

 
263

 
255

2021
 
149

 
99

 
254

 
245

2022
 
109

 
79

 
114

 
234

2023
 
61

 
99

 
60

 
170

Thereafter
 
108

 
337

 
—

 
923

Total
 
$
1,148

 
$
792

 
$
1,107

 
$
2,095

VIEs 
PPAs — Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from IPPs for which the utility subsidiaries are required to reimburse 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. Xcel Energy has determined that certain IPPs are VIEs. Xcel Energy is not subject to risk of loss from the operations of these entities, and no significant financial support is required other than contractual payments for energy and capacity.
In addition, certain solar PPAs provide an option to purchase emission allowances or sharing provisions related to production credits generated by the solar facility under contract. These specific PPAs create a variable interest in the IPP.
Xcel Energy evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities.
Xcel Energy 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. Xcel Energy’s utility subsidiaries had approximately 3,770 MW and 3,537 MW of capacity under long-term PPAs at Dec. 31, 2018 and 2017, respectively, with entities that have been determined to be VIEs. Agreements have expiration dates through 2041.
Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk plants from TUCO under contracts that will expire in December 2022. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers.
SPS has not provided any significant financial support to TUCO, other than contractual payments for delivered coal. However, the fuel contracts create a variable interest in TUCO due to SPS’ reimbursement of fuel procurement costs. SPS has determined that TUCO is a VIE. SPS has concluded that it is not the primary beneficiary of TUCO because SPS does not have the power to direct the activities that most significantly impact TUCO’s economic performance.
Low-Income Housing Limited Partnerships — Eloigne and NSP-Wisconsin have entered into limited partnerships for the construction and operation of affordable rental housing developments which qualify for low-income housing tax credits. Xcel Energy Inc. has determined Eloigne and NSP-Wisconsin’s low-income housing partnerships to be VIEs primarily due to contractual arrangements within each limited partnership that establish sharing of ongoing voting control and profits and losses that does not align with the partners’ proportional equity ownership. Eloigne and NSP-Wisconsin have the power to direct the activities that most significantly impact these entities’ economic performance. Therefore, Xcel Energy Inc. consolidates these limited partnerships in its consolidated financial statements. Xcel Energy’s risk of loss for these partnerships is limited to its capital contributions, adjusted for any distributions and its share of undistributed profits and losses; no significant additional financial support has been, or is required to be provided to the limited partnerships by Eloigne or NSP-Wisconsin.
Amounts reflected in Xcel Energy’s consolidated balance sheets for the Eloigne and NSP-Wisconsin low-income housing limited partnerships:
(Millions of Dollars)
 
Dec. 31, 2018
 
Dec. 31, 2017
Current assets
 
$
5

 
$
6

Property, plant and equipment, net
 
42

 
46

Other noncurrent assets
 
1

 
1

Total assets
 
$
48

 
$
53

 
 
 
 
 
Current liabilities
 
$
7

 
$
9

Mortgages and other long-term debt payable
 
26

 
26

Other noncurrent liabilities
 
—

 
1

Total liabilities
 
$
33

 
$
36

Other
Technology Agreements — Xcel Energy has a contract that extends through December 2022 with IBM for information technology services. Contract is cancelable at Xcel Energy’s option, although Xcel Energy would be obligated to pay 50% of the contract value for early termination. Xcel Energy capitalized or expensed $81 million, $98 million and $119 million associated with the IBM contract in 2018, 2017 and 2016, respectively.
Xcel Energy’s contract with Accenture for information technology services extends through December 2020. Contract is cancelable at Xcel Energy’s option, although there are financial penalties for early termination. Xcel Energy capitalized or expensed $46 million, $16 million and $35 million associated with the Accenture contract in 2018, 2017 and 2016, respectively.
Committed minimum payments under these obligations:
(Millions of Dollars)
 
IBM Agreement
 
Accenture Agreement
2019
 
$
30

 
$
11

2020
 
16

 
11

2021
 
16

 
—

2022
 
7

 
—

2023
 
—

 
—

Thereafter
 
—

 
—


Guarantees and Bond Indemnifications — Xcel Energy Inc. and its subsidiaries enter into contractual guarantees in limited circumstances. Xcel Energy Inc. may guarantee the subsidiaries’ obligations in the event they fail to perform and may provide guarantees in certain indemnification agreements. Xcel Energy Inc.’s guarantees from the subsidiaries are not individually material with maximum potential liability totaling $6 million as of Dec. 31, 2018. Payment for these guarantees is considered remote.