Commitments and Contingencies

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Legal

SPS 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 complex judgments about future events. Management maintains accruals for 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 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 SPS’ financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Rate Matters

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 the charges not billed since 2008. 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 charges was remanded to the FERC. SPS’ recovery of these charges (from 2008 through 2016) is being reviewed by the FERC, which is expected to rule in the first quarter of 2019.

In October 2017, SPS filed a complaint against SPP regarding the amounts billed asserting that SPP has assessed upgrade charges to SPS in violation of the SPP OATT. The FERC has granted a rehearing of further consideration in May 2018. The timing of the FERC action on the SPS rehearing is uncertain. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the differential in future rate proceedings.

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 the 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 could result in an increase in the ATRR of $9.5 million per year, with $6 million allocated to SPS’ retail customers.

The remaining $3.5 million would be paid by other wholesale loads in the SPS rate zone. In September 2018, SPS protested the proposed SPP tariff charges, and asked the FERC to reject the SPP filing. On October 31, 2018, the FERC issued an order accepting the proposed charges as of November 1, 2018. In December 2018, the FERC hosted a settlement hearing over the matter. A hearing will be ordered if a settlement is not reached.

SPS Filing to Modify Wholesale Transmission Rates - In 2018, SPS filed revisions to its wholesale transmission formula rate. The proposal includes an update to the depreciation rates for transmission plant. The new formula rate would provide flow-back of “excess” ADIT resulting from the TCJA and recover certain wholesale regulatory commission expenses.

The proposed changes would increase wholesale transmission revenues by approximately $9.4 million, with approximately $4.4 million of the total being recovered in SPP regional transmission rates. SPS proposed that the formula rate changes be effective February 1, 2019.

In January 2019, the FERC issued an order accepting the proposed rate changes as of February 1, 2019, subject to refund and settlement procedures. The first settlement conference is expected in the first quarter of 2019.

Environmental

New and changing federal and state environmental mandates can create financial liabilities for SPS, 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. SPS may sometimes pay all or a portion of the cost to remediate sites where past activities of its 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.

MGP, Landfill or Disposal Sites — SPS is currently investigating or remediating one MGP, landfill or other disposal site across its service territories, and these activities will continue through at least 2019. SPS accrued $0.1 million as of Dec. 31, 2018 and 2017, respectively, for this site. There may be insurance recovery and/or recovery from other potentially responsible parties, offsetting some portion of costs incurred.

Environmental Requirements — Water and Waste

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. SPS 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, SPS estimates that ELG compliance will be immaterial.

The EPA, however, is conducting a rulemaking process to potentially revise the effluent limitations and pretreatment standards, which may impact compliance costs. SPS estimates these costs will be fully recoverable through regulatory mechanisms.

Environmental Requirements — Air

Regional Haze Rules — The regional haze program requires SO₂, NO_X 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. 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 January 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 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. SPS cannot evaluate the impacts until the final designation is made and any required state plans are developed. SPS believes that should SO₂ control systems be required for a plant, compliance costs or the costs of alternative cost-effective generation will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows.

AROs — AROs have been recorded for SPS’ assets.

SPS’ AROs were as follows:



	Dec. 31, 2018
(Millions of Dollars)	Balance Jan. 1, 2018		Accretion		Cash Flow Revisions ^(a)		Balance Dec. 31, 2018 ^(b)
Electric
Steam production	$	20.3	$	1.2	$	0.5	$	22.0
Distribution	7.0		0.3		1.8		9.1
Other	1.2		0.1		—		1.3
Total liability	$	28.5	$	1.6	$	2.3	$	32.4


^(a)	In 2018, AROs were revised for changes in timing and estimates of cash flows. Changes in electric distribution AROs were primarily related to increased labor costs.


^(b)	There were no ARO amounts incurred or settled in 2018.



	Dec. 31, 2017
(Millions of Dollars)	Balance Jan. 1, 2017		Accretion		Cash Flow Revisions ^(a)			Balance Dec. 31, 2017 ^(b)
Electric plant
Steam production	$	20.7	$	1.3	$	(1.7	)	$	20.3
Distribution	6.8		0.2		—			7.0
Other	1.2		—		—			1.2
Total liability	$	28.7	$	1.5	$	(1.7	)	$	28.5


^(a)	In 2017, an asbestos ARO was revised for changes in timing of estimated cash flows.


^(b)	There were no ARO amounts incurred or settled in 2018.

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, 2018. Therefore, an ARO has not been recorded for these facilities.

Removal Costs — SPS records a regulatory liability for the plant removal costs that are recovered currently in rates. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates.

These removal costs have accumulated based on varying rates as authorized by the appropriate regulatory entities. SPS 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, 2018 and 2017 were $188 million and $197 million respectively.

Leases — SPS leases a variety of equipment and facilities. These leases, primarily for office space, generating facilities, vehicles, aircraft and power-operated equipment, are accounted for as operating leases.

Total expenses (including capacity payments) under operating lease obligations for SPS 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	$	59.0	$	57.8	$	56.6
Capacity payments	51.1		51.4		50.6

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 leases are:



(Millions of Dollars)	Operating Leases		PPA ^{(a) (b)} Operating Leases		Total Operating Leases
2019	$	5.2	$	46.7	$	51.9
2020	5.2		46.2		51.4
2021	5.1		46.2		51.3
2022	5.1		46.2		51.3
2023	5.1		46.2		51.3
Thereafter	56.3		450.8		507.1


^(a)	Amounts do not include PPAs accounted for as executory contracts.


^(b)	PPA operating leases contractually expire through 2033.

Non-Lease PPAs — SPS has entered into PPAs with other utilities and energy suppliers with expiration dates through 2033 for purchased power to meet system load and energy requirements and meet 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 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 $57.6 million, $58.4 million and $56.8 million in 2018, 2017 and 2016, respectively.

At Dec. 31, 2018, the estimated future payments for capacity that SPS is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:



(Millions of Dollars)	Capacity
2019	$	20.3
2020	12.0
2021	12.2
2022	12.4
2023	12.6
Thereafter	5.7
Total	$	75.2

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 2019 and 2033. SPS 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		Natural gas supply		Natural gas storage and transportation
2019	$	127.3	$	20.3	$	30.3
2020	83.9		—		30.3
2021	41.0		—		25.2
2022	41.2		—		19.3
2023	—		—		14.1
Thereafter	—		—		33.6
Total	$	293.4	$	20.3	$	152.8

VIEs — 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 and 897 MW of capacity under long-term PPAs at Dec. 31, 2018 and 2017, respectively, 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 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.