NSP-Minnesota 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 NSP-Minnesota’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

MEC Acquisition — In November 2018, NSP-Minnesota reached an agreement with Southern Power Company (a subsidiary of Southern Company) to purchase MEC, a 760 MW natural gas combined cycle facility, with capacity and energy historically sold to NSP-Minnesota under PPAs expiring in 2026 and 2039, for approximately $650 million.

In September 2019, the MPUC denied NSP-Minnesota's request to purchase MEC as a rate base asset. In January 2020, the MPUC approved Xcel Energy’s plan to acquire MEC as a non-regulated investment and step into the terms of the existing PPAs with NSP-Minnesota. A newly formed non-regulated subsidiary of Xcel Energy completed the transaction to purchase MEC on Jan. 17, 2020.

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 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.

In March 2019, MPUC approved NSP-Minnesota’s proposal to refund the GE settlement proceeds back to customers through the FCA. It also decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of the pending litigation between GE and NSP-Minnesota’s insurers.

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.

On March 21, 2019, FERC announced a NOI seeking public comments on whether, and if so how, to revise ROE policies in light of the D.C. Circuit Court decision. FERC also initiated a NOI on whether to revise its policies on incentives for electric transmission investments, including the RTO membership incentive. In November 2019, the FERC issued an order adopting a new ROE methodology and settling the MISO base ROE at 9.88% (10.38% with the RTO adder), effective Sept. 28, 2016 and for the Nov. 12, 2013 to Feb. 11, 2015 refund period. The FERC also dismissed the second complaint. In December 2019, MISO TOs filed a request for rehearing. Customers also filed requests for rehearing claiming, among other points, that the FERC erred by dismissing the second complaint without refunds. NSP-Minnesota has recognized a liability for its best estimate of final refunds to customers. It is uncertain when the FERC will act on the requests for rehearing or any other pending matters related to the 2019 NOIs.

Site Remediation — Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. NSP-Minnesota may sometimes pay all or a portion of the cost to remediate sites where past activities of NSP-Minnesota’s 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 NSP-Minnesota is alleged to have sent wastes to that site.

MGP, Landfill or Disposal Sites — NSP-Minnesota is currently investigating or remediating seven MGP, landfill or other disposal sites across its service territories. NSP-Minnesota has recognized its best estimate of costs/liabilities that will result from final resolution of these issues, however, the outcome and timing is unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.

Coal Ash Regulation — NSP-Minnesota’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. Under the CCR Rule, utilities are required to complete groundwater sampling around their CCR landfills and surface impoundments. Currently, NSP-Minnesota has three regulated ash units in operation.

NSP-Minnesota is conducting groundwater sampling and, where appropriate, initiating the assessment of corrective measures and evaluating whether corrective action is required at any CCR landfills or surface impoundments. To date, groundwater monitoring consistent with the CCR Rule has not identified results above the groundwater protection standards in the rule. Therefore, at this time no corrective action requirements have been triggered for these units under the rule.

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. In November 2019, the EPA proposed rules in response to this decision. If finalized in their current form, these rules would require NSP-Minnesota to expedite closure plans for one impoundment at an estimated cost of $2 million, and the construction of a new impoundment at an estimated cost of $8.6 million. In 2019, NSP-Minnesota initiated the construction of this new impoundment, an ash pond, expected to be in service in 2020. Upon placing the new ash pond in service, the existing ash pond will be taken out of service, and closure activities as prescribed by the CCR Rule and the facility’s National Pollutant Discharge Elimination System permit will be initiated.

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”. In 2019, the EPA repealed the 2015 rule and published a draft replacement rule. Until a final rule is issued, NSP-Minnesota cannot estimate potential impacts, but anticipates 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, NSP-Minnesota estimates that ELG compliance will cost approximately $10.0 million to complete. The EPA, however, is conducting a rulemaking process to revise certain effluent limitations and pretreatment standards, which may impact compliance costs. NSP-Minnesota 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. NSP-Minnesota estimates the likely cost for complying with impingement and entrainment requirements is approximately $35.6 million, to be incurred between 2020 and 2028. NSP-Minnesota believes six 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 $191.6 million. NSP-Minnesota anticipates these costs will be fully recoverable through regulatory mechanisms.

Regional Haze Rules — The regional haze program requires sulfur dioxide, nitrogen oxide and particulate matter emission controls at power plants to reduce visibility impairment in national parks and wilderness areas. The program includes reasonable further progress. The requirements of the first regional haze plans developed by Minnesota have been approved and implemented.



	2019
(Millions of Dollars)	Jan. 1, 2019		Amounts Incurred (a)		Amounts Settled (b)			Accretion		Cash Flow Revisions (c)			Dec. 31, 2019
Electric
Nuclear	$	1,968.3	$	—	$	—		$	99.5	$	—		$	2,067.8
Wind	104.9		10.3		—			4.8		(6.9		)	113.1
Steam and other production	49.2		—		(3.2		)	1.8		(1.0		)	46.8
Distribution	14.5		—		—			0.6		—			15.1
Miscellaneous	1.8		—		—			—		(1.6		)	0.2
Natural gas
Transmission and distribution	38.2		—		—			1.6		(3.6		)	36.2
Miscellaneous	0.2		—		—			0.1		—			0.3
Common
Miscellaneous	0.8		—		—			—		—			0.8
Total liability	$	2,177.9	$	10.3	$	(3.2	)	$	108.4	$	(13.1	)	$	2,280.3



	2018
(Millions of Dollars)	Jan. 1, 2018		Amounts Settled (a)			Accretion		Cash Flow Revisions (b)			Dec. 31, 2018 (c)
Electric
Nuclear	$	1,873.6	$	—		$	94.7	$	—		$	1,968.3
Wind	94.1		—			4.3		6.5			104.9
Steam and other production	64.0		(6.6		)	2.1		(10.3		)	49.2
Distribution	5.8		—			0.2		8.5			14.5
Miscellaneous	1.9		—			—		(0.1		)	1.8
Natural gas
Transmission and distribution	43.6		—			1.8		(7.2		)	38.2
Miscellaneous	0.2		—			—		—			0.2
Common
Miscellaneous	0.7		—			0.1		—			0.8
Total liability	$	2,083.9	$	(6.6	)	$	103.2	$	(2.6	)	$	2,177.9

Indeterminate AROs — Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of NSP-Minnesota’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2019. Therefore, an ARO has not been recorded for these facilities.

Removal Costs — NSP-Minnesota records a regulatory liability for the plant removal costs that are recovered currently in rates. Removal costs have accumulated based on varying rates as authorized by the appropriate regulatory entities. NSP-Minnesota has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Removal costs as of Dec. 31, 2019 and 2018 were $520.3 million and $484.6 million, respectively.

Nuclear Insurance — NSP-Minnesota’s public liability for claims from any nuclear incident is limited to $13.9 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has secured $450.0 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $13.5 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 $137.6 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 $20.5 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 $2.7 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage up to $350.0 million, 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 $12.0 million for business interruption insurance and $35.1 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.

Obligations for decommissioning are expected to be funded 100% by the external decommissioning trust fund. The 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 had $2.4 billion of assets held in external decommissioning trusts at Dec. 31, 2019. 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 as an ARO.



	Regulatory Basis
(Millions of Dollars)	2019			2018
Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars)	$	3,012.3		$	3,012.3
Effect of escalating costs	688.2			538.9
Estimated decommissioning cost obligation (in current dollars)	3,700.5			3,551.2
Effect of escalating costs to payment date	7,505.0			7,654.3
Estimated future decommissioning costs (undiscounted)	11,205.5			11,205.5
Effect of discounting obligation (using average risk-free interest rate of 2.39% and 3.33% for 2019 and 2018, respectively)	(5,562.2		)	(6,911.5		)
Discounted decommissioning cost obligation	$	5,643.3		$	4,294.0
Assets held in external decommissioning trust	$	2,439.6		$	2,054.7
Underfunding of external decommissioning fund compared to the discounted decommissioning obligation	3,203.7			2,239.3

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.



(Millions of Dollars)	2019			2018
Discounted decommissioning cost obligation - regulated basis	$	5,643.3		$	4,294.0
Differences in discount rate and market risk premium	(2,295.2		)	(1,446.4		)
O&M costs not included for GAAP	(1,280.3		)	(879.3		)
Nuclear production decommissioning ARO - GAAP	$	2,067.8		$	1,968.3

The 2014 nuclear decommissioning filing, approved in 2015, was used for regulatory presentation in 2019, 2018 and 2017. The 2017 filing, effective Jan. 1, 2019, has been approved by the MPUC. In December 2019, the MPUC verbally approved for NSP-Minnesota to delay any increase to the annual funding requirement until 2021.

NSP-Minnesota evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. Under ASC Topic 842, adopted by NSP-Minnesota on Jan. 1, 2019, a contract contains a lease if it conveys the exclusive right to control the use of a specific asset. A contract determined to contain a lease is evaluated further to determine if the arrangement is a finance lease.

ROU assets represent NSP-Minnesota's rights to use leased assets. Starting in 2019, the present value of future operating lease payments are recognized in current and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets.

Most of NSP-Minnesota’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the estimated incremental borrowing rate (weighted-average of 3.8%).

NSP-Minnesota has elected to utilize the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from minimum lease payments for the purposes of lease accounting and disclosure.



(Millions of Dollars)	2019		2018		2017
Operating leases
PPA capacity payments	$	75.9	$	62.5	$	62.7
Other operating leases ^(a)	9.1		13.7		14.2
Total operating lease expense ^(b)	$	85.0	$	76.2	$	76.9



(Millions of Dollars)	PPA ^{(a) (b)} Operating Leases			Other Operating Leases			Total Operating Leases
2020	$	93.5		$	7.9		$	101.4
2021	94.9			8.0			102.9
2022	96.4			11.9			108.3
2023	97.9			7.0			104.9
2024	99.5			6.8			106.3
Thereafter	119.8			44.9			164.7
Total minimum obligation	602.0			86.5			688.5
Interest component of obligation	(66.2		)	(16.7		)	(82.9		)
Present value of minimum obligation	$	535.8		$	69.8		605.6
Less current portion							(79.9		)
Noncurrent operating lease liabilities							$	525.7

Weighted-average remaining lease term in years							6.7



(Millions of Dollars)	PPA^{(a) (b)}Operating Leases		Other Operating Leases		Total Operating Leases
2019	$	65.0	$	13.5	$	78.5
2020	66.1		8.4		74.5
2021	67.1		8.4		75.5
2022	68.2		8.1		76.3
2023	69.3		7.3		76.6
Thereafter	143.5		36.0		179.5

Non-Lease PPAs — NSP-Minnesota has entered into PPAs with other utilities and energy suppliers with various expiration dates through 2033 for purchased power to meet system load and energy requirements, 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, and total energy payments on those contracts were $102.4 million, $104.7 million and $96.7 million in 2019, 2018 and 2017, respectively.

Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $53.8 million, $52.7 million and $84.1 million in 2019, 2018 and 2017, respectively.

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 financial results are mitigated through purchased energy cost recovery mechanisms.

Fuel Contracts — NSP-Minnesota 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 in various years between 2020 and 2037. NSP-Minnesota is required to pay additional amounts depending on actual quantities shipped under these agreements.

Estimated minimum purchases for these contracts as of Dec. 31, 2019:



(Millions of Dollars)	Coal		Nuclear fuel		Natural gas supply		Natural gas storage and transportation
2020	$	171.3	$	53.8	$	36.8	$	133.0
2021	85.2		102.5		1.4		129.8
2022	51.9		85.3		0.8		124.3
2023	35.1		103.0		—		107.8
2024	0.9		74.5		—		101.1
Thereafter	2.6		275.1		—		273.6
Total ^(a)	$	347.0	$	694.2	$	39.0	$	869.6

Under certain PPAs, NSP-Minnesota purchases power from IPPs for which NSP-Minnesota is required to reimburse fuel costs, or to participate in tolling arrangements under which NSP-Minnesota procures the natural gas required to produce the energy that it purchases. NSP-Minnesota has determined that certain IPPs are VIEs. NSP-Minnesota 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. NSP-Minnesota 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.

NSP-Minnesota 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. NSP-Minnesota had approximately 1,347 MW and 1,002 MW of capacity under long-term PPAs at Dec. 31, 2019 and 2018, respectively, with entities that have been determined to be VIEs. These agreements have expiration dates through 2039.