Commitments and Contingencies

Commitments

Capital Commitments — SPS has made commitments in connection with a portion of its projected capital expenditures. SPS’ capital commitments primarily relate to the following major projects:

Transmission NTC — SPS has accepted NTCs for several hundred miles of transmission line and related substation projects based on needs identified through SPP’s various planning processes, including those associated with economics, reliability, generator interconnection and the load addition processes. Most significant are the 345 KV transmission line from TUCO to Yoakum County to Hobbs Plant and the Hobbs Plant to China Draw 345 KV transmission lines.

New Mexico and Texas Wind Projects — SPS is seeking approval from the NMPRC and the PUCT to build, own and operate 1,000 MW of new wind generation through the addition of two wind generation facilities in New Mexico and Texas.

Fuel Contracts — SPS has entered into various long-term commitments for the purchase and delivery of a significant portion of its current coal and natural gas requirements. These contracts expire in various years between 2018 and 2029. SPS is required to pay additional amounts depending on actual quantities shipped under these agreements.

The estimated minimum purchases for SPS under these contracts as of Dec. 31, 2017, are as follows:



(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2018	$	172	$	11	$	29
2019	106		—		32
2020	64		—		32
2021	20		—		27
2022	21		—		21
Thereafter	—		—		50
Total	$	383	$	11	$	191

Additional expenditures for fuel and natural gas storage and transportation will be required to meet expected future electric generation needs. SPS’ risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the cost-rate adjustment mechanisms, which provide for pass-through of most fuel, storage and transportation costs to customers.

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 typically contingent on the independent power producing entity meeting contract obligations, including plant availability requirements. 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 $58 million, $57 million and $57 million in 2017, 2016 and 2015, respectively. At Dec. 31, 2017, the estimated future payments for capacity that SPS is obligated to purchase pursuant to these executory contracts, subject to availability, are as follows:



(Millions of Dollars)	Capacity
2018	$	58
2019	20
2020	12
2021	12
2022	13
Thereafter	18
Total	$	133

Additional energy payments under these PPAs and PPAs accounted for as operating leases will be required to meet expected future electric demand.

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 under operating lease obligations were approximately $58 million, $57 million and $55 million for 2017, 2016 and 2015, respectively. These expenses include capacity payments for PPAs accounted for as operating leases of $51 million, $51 million and $49 million in 2017, 2016 and 2015, respectively, recorded to electric fuel and purchased power expenses.

Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been accounted for as operating leases in accordance with the applicable accounting guidance. Future commitments under operating leases are:



(Millions of Dollars)	Operating Leases		PPA ^{(a) (b)} Operating Leases		Total Operating Leases
2018	$	5	$	52	$	57
2019	5		51		56
2020	5		51		56
2021	5		51		56
2022	5		51		56
Thereafter	61		543		604


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


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

Variable Interest Entities — The accounting guidance for consolidation of variable interest entities requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an enterprise is a variable interest entity’s primary beneficiary.

PPAs — Under certain PPAs, SPS purchases power from independent power producing entities for which SPS is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which SPS procures the natural gas required to produce the energy that it purchases. In addition, certain solar PPAs provide SPS with 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 independent power producing entity.

SPS has determined that certain independent power producing entities are variable interest entities. SPS is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is required to be provided other than contractual payments for energy and capacity set forth in the PPAs.

SPS has evaluated each of these variable interest entities 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 has 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 897 MW of capacity under long-term PPAs at both Dec. 31, 2017 and 2016 with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2041.

Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk electric generating stations from TUCO under contracts for those facilities that 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.

No significant financial support has been, or is required to be provided to TUCO by SPS, other than contractual payments for delivered coal. However, the fuel contracts create a variable interest in TUCO due to SPS’ reimbursement of certain fuel procurement costs. SPS has determined that TUCO is a variable interest entity. 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.

Environmental Contingencies

SPS has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, SPS believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, SPS is pursuing, or intends to pursue, recovery from other PRPs and through the regulated rate process. New and changing federal and state environmental mandates can also create added financial liabilities for SPS, which are normally recovered through the regulated rate process. To the extent any costs are not recovered through the options listed above, SPS would be required to recognize an expense.

Site Remediation — Various federal and state environmental laws impose liability, without regard to the legality of the original conduct, 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 or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former manufactured gas plants operated by SPS, its predecessors, or other entities; and third-party sites, such as landfills, for which SPS is alleged to be a PRP that sent wastes to that site.

MGP, Landfill or Disposal Sites — SPS is currently involved in investigating and/or remediating an MGP, landfill or other disposal site. SPS has identified one site where contamination is present and where investigation and/or remediation activities are currently underway. Other parties may have responsibility for some portion of the investigation and/or remediation activities that are underway. SPS anticipates that the investigation or remediation activities will continue through at least 2018. SPS has accrued $0.1 million for the site as of Dec. 31, 2017 and 2016, respectively. There may be insurance recovery and/or recovery from other PRPs that will offset any costs incurred. SPS anticipates that any amounts spent will be fully recovered from customers.

Environmental Requirements

Water and Waste

Asbestos Removal — Some of SPS’ facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. SPS has recorded an estimate for final removal of the asbestos as an ARO. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is not expected to be material and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Federal CWA Waters of the United States Rule — In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) published a final rule that significantly expanded the types of water bodies regulated under the CWA and broadened the scope of waters subject to federal jurisdiction. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule and subsequently ruled that it, rather than the federal district courts, had jurisdiction over challenges to the rule. In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges to the rule. A ruling is expected in 2018.

In February 2017, President Trump issued an executive order requiring the EPA and the Corps to review and revise the final rule. On June 2017, the agencies issued a proposed rule that rescinds the final rule and reinstates the prior definition of “Water of the U.S.” The agencies are also undertaking a rulemaking to develop a new definition of “Waters of the U.S.”

Federal CWA Effluent Limitations Guidelines (ELG) — In 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. In 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport until November 2020 while the agency conducts a rulemaking process to potentially revise the effluent limitations and pretreatment standards for these waste streams.

Air

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

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

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

In October 2017, the EPA published a proposed rule to repeal the CPP, based on an analysis that the CPP exceeds the EPA’s statutory authority under the CAA. In the proposal, the EPA stated it has not yet determined whether it will promulgate a new rule to regulate GHG emissions from existing EGUs. In December 2017, the EPA issued an Advanced Notice of Proposed Rulemaking to take and consider comments on whether to issue a future rule and what such a rule should include.

CSAPR — CSAPR addresses long range transport of PM and ozone by requiring reductions in SO₂ and NOx from utilities in the eastern half of the United States, including Texas, using an emissions trading program.

CSAPR was adopted to address interstate emissions impacting downwind states’ attainment of the ozone and particulate NAAQS. As the EPA revises NAAQS, it will consider whether to make any further reductions to CSAPR emission budgets and whether to change which states are included in the emissions trading program.

In September 2017, the EPA adopted a final rule that withdraws Texas from the CSAPR particle program and determines that further emission reductions in Texas are not needed to address interstate particle transport. Texas is no longer subject to the annual SO₂ and NO_X emission budgets under CSAPR. In November 2017, the National Parks Conservation Association and Sierra Club appealed this rule to the D.C. Circuit Court. In January 2018, the Court granted SPS’ motion to intervene in support of the EPA’s final rule.

Regional Haze Rules — The regional haze program requires SO₂, NO_X and PM emission controls at power plants and other industrial facilities to reduce visibility impairment in national parks and wilderness areas. The program is divided into two parts: BART and reasonable further progress. Texas’ first regional haze plan has undergone federal review as described below.

BART Determination for Texas: The EPA published a proposed BART rule for Texas in January 2017 that could have required installation of dry scrubbers to reduce SO₂ emissions from Harrington Units 1 and 2. Investment costs associated with dry scrubbers for Harrington Units 1 and 2 could have been approximately $400 million. In October 2017, the EPA 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 from units in 2019 and future years. The anticipated costs of compliance are not expected to have a material impact on the results of operations, financial position or cash flows; and SPS believes that compliance costs would be recoverable through regulatory mechanisms.

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 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 matter is now submitted to the court.

In December 2017, the National Parks Conservation Association, Sierra Club, and Environmental Defense Fund appealed the EPA’s October 2017 final BART rule to the Fifth Circuit, and filed a petition for administrative reconsideration of the final rule with the EPA. In January 2018, the court granted SPS’ motion to intervene in the Fifth Circuit litigation in support of the EPA’s final rule.

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 approximately $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 of the regional haze program. The risk of these controls being imposed along with the risk of investments to provide additional cooling water to Tolk have caused SPS to seek to decrease the remaining depreciable life of the Tolk units. The EPA has not announced a schedule for acting on the remanded rule.

Implementation of the NAAQS for SO₂ — The EPA adopted a more stringent NAAQS for SO₂ in 2010, and evaluated areas in three phases. In December 2017, the EPA adopted a final rule that completed its initial designations of areas attaining or not attaining the standard. The EPA’s final actions designate all areas near SPS generating plants as meeting the SO₂ NAAQS with one exception. In June 2016, 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 Texas Commission on Environmental Quality (TCEQ) will need to develop an implementation plan, which would be due by 2022, 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 or require upgrades 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.

Revisions to the NAAQS for Ozone — In 2015, the EPA revised the NAAQS for ozone by lowering the eight-hour standard from 75 parts per billion (ppb) to 70 ppb. In November 2017, the EPA published final designations of areas that meet the 2015 ozone standard. SPS meets the 2015 ozone standard in all areas where its generating units operate.

Asset Retirement Obligations

Recorded AROs — AROs have been recorded for property related to the following: electric steam and other production, electric distribution and transmission, and general property. The electric production obligations include asbestos, processed water containment facilities which are included under the category of ash-containment, storage tanks and control panels. The asbestos recognition associated with electric production includes certain specific plants.

SPS recognized AROs for the removal of electric transmission and distribution equipment, which consists of obligations associated with polychlorinated biphenyl, mineral oil, mercury and street lighting lamps. The electric general ARO includes small obligations related to storage tanks.

A reconciliation of SPS’ AROs for the years ended Dec. 31, 2017 and 2016 is as follows:



(Thousands of Dollars)	Beginning Balance Jan. 1, 2017		Accretion		Cash Flow Revisions ^(a)			Ending Balance Dec. 31, 2017 ^(b)
Electric plant
Steam production asbestos	$	19,070	$	1,155	$	(1,676	)	$	18,549
Electric distribution	6,799		249		—			7,048
Steam production ash containment	1,593		85		—			1,678
Other	1,201		48		—			1,249
Total liability	$	28,663	$	1,537	$	(1,676	)	$	28,524


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


^(b)	There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2017.



(Thousands of Dollars)	Beginning Balance Jan. 1, 2016		Accretion		Cash Flow Revisions			Ending Balance Dec. 31, 2016 ^(a)
Electric plant
Steam production asbestos	$	17,981	$	1,089	$	—		$	19,070
Steam production ash containment	1,513		80		—			1,593
Electric distribution	6,559		240		—			6,799
Other	1,180		42		(21		)	1,201
Total liability	$	27,233	$	1,451	$	(21	)	$	28,663


^(a)	There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2016.

Indeterminate AROs — Outside of the known and 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 amount of asbestos or cost of removal could be determined as of Dec. 31, 2017. Therefore, an ARO has not been recorded for these facilities.

Removal Costs — SPS records a regulatory liability for the plant removal costs of generation, transmission and distribution facilities 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 over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long time periods over which the amounts were accrued and the changing of rates over time, SPS has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Accordingly, the recorded amounts of estimated future removal costs are considered regulatory liabilities. Removal costs as of Dec. 31, 2017 and 2016 were $197 million and $209 million, respectively.

Legal Contingencies

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 a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on SPS’ financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Other Contingencies

See Note 10 for further discussion.