SPS is involved in various litigation matters 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 losses 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, management does not anticipate that the ultimate liabilities, if any, would have a material effect on SPS’ financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

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. SPP had not been charging its customers for these upgrades, even though the SPP OATT had allowed SPP to do so since 2008. In 2016, the FERC granted SPP’s request to recover previously unbilled charges and SPP subsequently billed SPS approximately $13 million.

In July 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting SPP the right to recover previously unbilled charges was remanded to the FERC. In February 2019, the FERC reversed its 2016 decision and ordered SPP to refund charges retroactively collected from its transmission customers, including SPS, related to periods before September 2015. In March 2020, SPP and Oklahoma Gas & Electric separately filed petitions for review of the FERC’s orders at the D.C. Circuit. SPS has intervened in both appeals in support of FERC. Any refunds received by SPS are expected to be given back to SPS customers through future rates.

In October 2017, SPS filed a separate related complaint asserting SPP assessed upgrade charges to SPS in violation of the SPP OATT. In March 2018, the FERC issued an order denying the SPS complaint. SPS filed a request for rehearing in April 2018. The FERC issued a tolling order granting a rehearing for further consideration in May 2018. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the amount through future SPS customer rates. In October 2020, SPS filed a petition for review of the FERC’s March 2018 order and May 2018 tolling order at the D.C. Circuit. This appeal is stayed pending the outcome of the separate appeal initiated in 2020 by Oklahoma Gas & Electric and SPP.

SPP Filing to Assign GridLiance Facilities to SPS Rate Zone — In August 2018, SPP filed a request with the FERC to amend its OATT to include costs of the GridLiance High Plains, LLC. facilities in the SPS rate zone. In a previous filing, the FERC determined that some of these facilities did not qualify as transmission facilities under the SPP OATT. SPP’s proposed tariff changes resulted in an increase in the annual transmission revenue requirement of $10 million per year, with $6 million allocated to SPS’ retail customers. The remaining $4 million would be paid by other wholesale loads in the SPS rate zone. On March 16, 2020, GridLiance also filed additional rate increases for 2020 which would raise their annual revenue requirement to $14 million, with approximately $9 million allocated to SPS’ retail customers. The hearing portion of this proceeding was concluded on Sept. 11, 2020.

The initial post-hearing brief was filed on Oct. 27, 2020 and the ALJ’s decision on this case is expected on May 3, 2021. The FERC will then rule on the judge’s decision and either sustain it, overturn it, or order further proceedings. SPS has incurred approximately $15 million in associated charges as of Dec. 31, 2020. In August 2020, FERC issued an order on a question certified by the hearing judge for the FERC’s review, in which FERC made certain findings in SPS’ favor regarding the legal standard that applies to the ongoing hearing proceeding. In November 2020, FERC denied GridLiance’s request for rehearing of this August 2020 order. In December 2020, GridLiance filed a petition for review at the D.C. Circuit of the August 2020 and November 2020 orders on the certified question.

Wind Operating Commitments — PUCT and NMPRC orders related to the Hale and Sagamore wind projects included certain operating and savings minimums. In general, annual generation must exceed a net capacity factor of 48%. If annual generation is below the guaranteed level, SPS would be obligated to refund an amount equal to foregone PTCs and fuel savings. Additionally, retail customer savings must exceed project costs included in base rates over the first ten years of operations. SPS would be required to refund excess costs, if any, after ten years of operations. As of Dec. 31, 2020, SPS does not expect refunds to be probable under either of these commitments.

Contract Termination — SPS and Lubbock Power & Light are parties to a 25-year, 170 MW partial requirements contract. In October 2020, Lubbock Power & Light initiated discussions with SPS concerning the interpretation of contractual terms related to early termination and default. If the parties are unable to reach resolution, the contract calls for the matter to proceed to arbitration. The amount of any damages depends on multiple factors and is currently unknown.

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

SPS is currently remediating a former disposal site. SPS 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.

Federal CWA WOTUS Rule — In April 2020, the EPA and U.S. Army Corps of Engineers (“Agencies”) replaced the 2015 WOTUS rule and narrowed the definition of WOTUS (“2020 WOTUS Rule”). The new definition simplifies the process whether waters are subject to CWA jurisdiction and streamlines the permitting process. SPS does not anticipate that compliance costs will be material.

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 coal combustion residuals. In October 2020, the EPA published a final rule revising the regulations. SPS anticipates that compliance costs will not be material and will be fully recoverable through regulatory mechanisms.

Regional Haze Rules — The regional haze program requires SO2, nitrogen oxide and particulate matter emission controls at power plants to reduce visibility impairment in national parks and wilderness areas. The program includes BART and reasonable further progress. Texas’ first regional haze plan has undergone federal review.

All states are now subject to a second round of regional haze planning/rulemaking, focusing on additional reductions to meet reasonable progress requirements. Any additional impacts to SPS facilities are expected to be minimal.

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. 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. The EPA reaffirmed the rule in August 2020 with minor changes.

The 2020 EPA Action has been challenged. All pending actions could be consolidated, and may proceed in the Fifth Circuit or the D.C. Circuit, where a parallel challenge has been filed. The timing of final decisions is unclear.

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. As states are now proceeding with the second regional haze planning period, the EPA may choose not to act 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 Harrington plant as “unclassifiable.” The area near the Harrington plant was monitored for the three years ending in 2019 and the monitoring showed the area to be exceeding the standard.

To address this issue, SPS negotiated an order with the TCEQ providing for the end of coal combustion and the conversion of the Harrington plant to a natural gas fueled facility by Jan. 1, 2025.

SPS believes 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.


	2020
(Millions of Dollars)	Jan. 1, 2020		Amounts Incurred (a)		Amounts Settled (b)		Accretion		Dec. 31, 2020 (c)
Electric
Steam and other production	$	51	$	—	$	(2)	$	3	$	52
Wind	16		33		—		1		50
Distribution	10		—		—		—		10
Total liability	$	77	$	33	$	(2)	$	4	$	112


	2019
(Millions of Dollars)	Jan. 1, 2019		Amounts Incurred (a)		Amounts Settled (b)		Accretion		Cash Flow Revisions (c)		Dec. 31, 2019
Electric
Steam and other production	$	22	$	—	$	(2)	$	1	$	30	$	51
Wind	—		16		—		—		—		16
Distribution	9		—		—		1		—		10
Miscellaneous	1		—		—		—		(1)		—
Total liability	$	32	$	16	$	(2)	$	2	$	29	$	77

(c)In 2019, AROs were revised for changes in timing and estimates of cash flows. Changes in steam production AROs primarily related to the cost estimates to remediate ponds at production facilities.

Indeterminate AROs — Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of SPS’ facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2020. Therefore, an ARO has not been recorded for these facilities.

SPS evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. 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 SPS’ rights to use leased assets. 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 SPS’ 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 4.4%). SPS has elected 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. Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the balance sheet.


(Millions of Dollars)	Dec. 31, 2020		Dec. 31, 2019
PPAs	$	500	$	500
Other	50		48
Gross operating lease ROU assets	550		548
Accumulated amortization	(58)		(26)
Net operating lease ROU assets	$	492	$	522


(Millions of Dollars)	PPA (a) (b) Operating Leases		Other Operating Leases		Total Operating Leases
2021	$	46	$	3	$	49
2022	46		3		49
2023	46		3		49
2024	46		3		49
2025	46		3		49
Thereafter	359		43		402
Total minimum obligation	589		58		647
Interest component of obligation	(139)		(17)		(156)
Present value of minimum obligation	450		41		491
Less current portion					(28)
Noncurrent operating and finance lease liabilities					$	463

Weighted-average remaining lease term in years					13.0

Non-Lease PPAs — SPS has entered into PPAs with other utilities and energy suppliers with various expiration dates through 2024 for purchased power to meet system load and energy requirements and operating reserve obligations.

In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Capacity payments are contingent on the IPP 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.

Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts, were payments for capacity of $12 million, $20 million and $58 million in 2020, 2019 and 2018, respectively.

Fuel Contracts — SPS has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal and natural gas requirements. These contracts expire between 2021 and 2033. SPS is required to pay additional amounts depending on actual quantities shipped under these agreements.


(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2021	$	80	$	33	$	31
2022	35		—		31
2023	—		—		29
2024	—		—		16
2025	—		—		12
Thereafter	—		—		20
Total	$	115	$	33	$	139

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

SPS 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. SPS concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance.

SPS had approximately 1,197 MW of capacity under long-term PPAs at both Dec. 31, 2020 and 2019 with entities that have been determined to be VIEs. These agreements have expiration dates through 2041.

Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk plant from TUCO Inc. 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.