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 transmission project plans.

Southeast New Mexico Transmission Development — SPS is developing a transmission expansion plan for southeastern New Mexico. The SPP, with input from SPS, is conducting a High Priority Incremental Load Study to review oil and natural gas load additions in several areas, including southeastern New Mexico. A final report is expected by SPP in April 2014. SPS has started right-of-way work on four projects for which NTCs are anticipated from SPP in early 2014.

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 or the load addition processes. A major project committed to is the TUCO to Woodward District Extra High Voltage Interchange, a 345 KV transmission line. This line connects the TUCO substation near Lubbock, Texas with the OGE substation in Woodward, Okla. The PUCT approved SPS’ CCN to build the line in 2012. It is anticipated to be complete in 2014.

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 2014 and 2033. 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, 2013, are as follows:



(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2014	$	273.8	$	20.6	$	23.7
2015	241.5		—		22.1
2016	143.8		—		22.1
2017	36.7		—		21.3
2018	—		—		15.9
Thereafter	—		—		96.1
Total	$	695.8	$	20.6	$	201.2

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 2024 for purchased power to meet system load and energy requirements and meet operating reserve obligations. In general, these contracts provide for energy payments, based on actual energy delivered and capacity payments. Capacity payments are typically contingent on the independent power producing entity meeting certain 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 $38.4 million, $36.2 million and $39.7 million in 2013, 2012 and 2011, respectively. At Dec. 31, 2013, 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)
2014	$	52.3
2015	56.5
2016	57.0
2017	58.2
2018	57.2
Thereafter	72.2
Total ^(a)	$	353.4


^(a)	Excludes contingent energy payments for renewable energy PPAs.

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 used in the normal course of business. These leases, primarily for office space, generating facilities, trucks, aircraft, cars and power-operated equipment, are accounted for as operating leases. Total expenses under operating lease obligations were approximately $64.2 million, $59.9 million and $58.8 million for 2013, 2012 and 2011, respectively. These expenses included capacity payments for PPAs accounted for as operating leases of $59.0 million, $56.0 million and $54.4 million in 2013, 2012 and 2011, 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:



	Operating		PPA		Total Operating
(Millions of Dollars)	Leases		Operating Leases ^{(a) (b)}		Leases
2014	$	3.1	$	58.3	$	61.4
2015	3.2		49.9		53.1
2016	3.2		49.9		53.1
2017	2.3		49.9		52.2
2018	1.9		49.9		51.8
Thereafter	12.7		734.1		746.8


^(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. These specific PPAs create a variable interest in the associated 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 in the future 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 827 MW of capacity under long-term PPAs as of Dec. 31, 2013 and 2012, with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2033.

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 2016 and 2017, respectively. 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 in the future, 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.

Indemnification Agreements

In connection with the sale of certain Texas electric transmission assets to Sharyland, SPS agreed to indemnify the purchaser for losses arising out of any breach of the representations, warranties and covenants under the related asset purchase agreement and for losses arising out of certain other matters, including pre-closing liabilities. SPS’ indemnification obligation is capped at $37.1 million, in the aggregate. The indemnification provisions for most representations and warranties expire in December 2014. The remaining representations and warranties, which relate to due organization and transaction authorization, survive indefinitely. SPS has recorded a $0.4 million liability related to this indemnity.

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 or other entities; and third-party sites, such as landfills, for which SPS is alleged to be a PRP that sent hazardous materials and wastes to that site.

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 Clean Water Act Effluent Limitations Guidelines (ELG) — In June 2013, the EPA published a proposed 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. Refuse derived fuel, biomass and other alternatively fueled power plants are not addressed by the proposed revisions. The proposed rule identifies four potential regulatory options and invites comments on those regulatory approaches. The options differ in the number of waste streams covered, size of the units controlled and stringency of controls. It is not yet known when the EPA will issue a finalized rule. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017 but no later than July 2022. The impact of this rule on SPS is uncertain at this time.

Proposed Coal Ash Regulation — SPS’ operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of hazardous waste. In 2010, the EPA published a proposed rule on whether to regulate coal combustion byproducts (coal ash) as hazardous or nonhazardous waste. Coal ash is currently exempt from hazardous waste regulation. SPS’ costs for the management and disposal of coal ash would significantly increase and the beneficial reuse of coal ash would be negatively impacted if the EPA ultimately issues a rule under which coal ash is regulated as hazardous waste. The EPA has entered into a consent decree to act on final regulations by December 2014. The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.

Air

EPA GHG Regulation — In 2009, the EPA issued its “endangerment” finding that GHG emissions pose a threat to public health and welfare. This finding required the EPA to adopt GHG emission standards for mobile sources. In 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which are applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold. These rules were upheld on appeal to the D.C. Circuit. The U.S. Supreme Court has granted review on one issue related to these rules, specifically whether the EPA’s regulation of GHG emissions from mobile sources triggered, by operation of law, new source review permitting requirements for stationary sources, which was the EPA’s basis for adopting the 2011 permitting rules. The Court is scheduled to hear arguments in February 2014. A ruling is anticipated by June 2014. SPS is unable to determine the cost of compliance with these new EPA requirements as it is not clear whether these requirements will apply to future changes at SPS’ power plants.

GHG Emission Standard for Existing Sources and NSPS Proposal — In June 2013, President Obama issued a memorandum directing the EPA to develop GHG emission standards for existing power plants. The memorandum anticipates the EPA will issue a proposed GHG emission standard for existing power plants in June 2014. It is not possible to evaluate the impact of existing source standards until the upcoming proposal and final requirements are known.

In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which seeks to establish CO₂ emission rates for coal-fired power plants that reflect emission reductions using partial carbon capture and storage technology (CCS). The EPA’s proposed CO₂ emission limits for gas-fired power plants reflect emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known.

CSAPR — In 2011, the EPA issued the CSAPR to address 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. The CSAPR would have set more stringent requirements than the proposed Clean Air Transport Rule and would have required plants in Texas to reduce their SO₂and annual NOx emissions. The rule also would have created an emissions trading program.

In August 2012, the D.C. Circuit vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated that the EPA must continue administering the CAIR pending adoption of a valid replacement. In December 2013, the U.S. Supreme Court heard oral arguments on the D.C. Circuit’s 2012 decision to vacate the CSAPR. A decision is anticipated by June 2014. It is not yet known whether the D.C. Circuit’s decision will be upheld, or how the EPA might approach a replacement rule. Therefore, it is not known what requirements may be imposed in the future.

As the EPA continues administering the CAIR while the CSAPR or a replacement rule is pending, SPS expects to comply with the CAIR as described below.

CAIR — In 2005, the EPA issued the CAIR to further regulate SO₂ and NOx emissions. Under the CAIR’s cap and trade structure, companies can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems. In the SPS region, installation of low-NOx combustion control technology was completed in 2012 on Tolk Unit 1. SPS plans to install the same combustion control technology on Tolk Unit 2 in the second quarter of 2014. These installations will reduce or eliminate SPS’ need to purchase NOx emission allowances. SPS had sufficient SO₂ allowances to comply with the CAIR in 2013 and has sufficient allowances for 2014. At Dec. 31, 2013, the estimated annual CAIR NOx allowance cost for SPS did not have a material impact on the results of operations, financial position or cash flows.

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. SPS expects to comply with the EGU MATS rule through a combination of mercury and other emission control projects. SPS believes EGU MATS costs will be recoverable through regulatory mechanisms and does not expect a material impact on results of operations, financial position or cash flows.

Regional Haze Rules — In 2005, the EPA amended the BART requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. In its first regional haze SIP, Texas identified the SPS facilities that will have to reduce SO₂, NOx and PM emissions under BART and then set emissions limits for those facilities.

Harrington Units 1 and 2 are potentially subject to BART. Texas has developed a SIP that finds the CAIR equal to BART for EGUs. As a result, no additional controls beyond CAIR compliance would be required. In May 2012, the EPA deferred its review of the SIP in its final rule allowing states to find that CSAPR compliance meets BART requirements for EGUs. It is not yet known how the U.S. Supreme Court’s review of the CSAPR may impact the EPA’s approval of the SIP.

Revisions to National Ambient Air Quality Standards (NAAQS) for PM — In December 2012, the EPA lowered the primary health-based NAAQS for annual average fine PM and retained the current daily standard for fine PM. In areas where SPS operates power plants, current monitored air concentrations are below the level of the final annual primary standard. The EPA is expected to designate non-compliant locations by December 2014. States would then study the sources of the nonattainment and make emission reduction plans to attain the standards. It is not possible to evaluate the impact of this regulation further until the final designations have been made.

Asset Retirement Obligations

Recorded AROs — AROs have been recorded for property related to the following: electric steam production, electric distribution and transmission, and general property. The electric production obligations include asbestos, ash containment facilities, storage tanks and control panels. The asbestos recognition associated with the steam production includes certain plants. This asbestos abatement removal obligation originated in 1973 with the CAA applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal. The AROs also have been recorded for SPS steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills and the AROs origination dates on the ARO recognition for ash-containment facilities at steam plants were the in-service dates of the various facilities.

An ARO was recognized for the removal of electric transmission and distribution equipment at SPS, which consists of many small potential obligations associated with PCBs, mineral oil, storage tanks, treated poles, lithium batteries, mercury and street lighting lamps. The electric general AROs include small obligations related to storage tanks, radiation sources and office buildings. These assets have numerous in-service dates for which it is difficult to assign the obligation to a particular year. Therefore, the obligation was measured using an average service life.

A reconciliation of SPS’ AROs is shown in the tables below for the years ended Dec. 31, 2013 and 2012:



(Thousands of Dollars)	Beginning Balance Jan. 1, 2013		Liabilities Settled			Accretion		Revisions to Prior Estimates			Ending Balance Dec. 31, 2013
Electric plant
Steam production asbestos	$	10,979	$	(118	)	$	747	$	—		$	11,608
Steam production ash containment	764		—			48		(3		)	809
Electric distribution	5,303		—			171		630			6,104
Other	561		—			42		251			854
Total liability	$	17,607	$	(118	)	$	1,008	$	878		$	19,375



(Thousands of Dollars)	Beginning Balance Jan. 1, 2012		Liabilities Settled		Accretion		Revisions to Prior Estimates			Ending Balance Dec. 31, 2012
Electric plant
Steam production asbestos	$	20,803	$	—	$	1,422	$	(11,246	)	$	10,979
Steam production ash containment	719		—		45		—			764
Electric distribution	5,202		—		188		(87		)	5,303
Other	542		—		20		(1		)	561
Total liability	$	27,266	$	—	$	1,675	$	(11,334	)	$	17,607

In 2013, SPS revised ash containment facilities, miscellaneous electric production, electric transmission and distribution and electric general AROs due to revised estimated cash flows. Additionally, in 2013, an ARO was settled for the asbestos abatement at the Riverview generating facility. In 2012, SPS revised asbestos and electric transmission and distribution AROs due to revised estimated cash flows.

Removal Costs — SPS records a regulatory liability for the plant removal costs of steam and other generation, transmission and distribution facilities. 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, 2013 and 2012, were $53 million and $67 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.

Employment, Tort and Commercial Litigation

Exelon Wind (formerly John Deere Wind) Complaint — Several lawsuits in Texas state and federal courts and regulatory proceedings have arisen out of a dispute concerning SPS’ payments for energy and capacity produced from the Exelon Wind subsidiaries’ projects. There are two main areas of dispute. First, Exelon Wind claims that it established legally enforceable obligations (LEOs) for each of its 12 wind facilities in 2005 through 2008 that require SPS to buy power based on SPS’ forecasted avoided cost as determined in 2005 through 2008. Although SPS has refused to accept Exelon Wind’s LEOs, SPS accepts that it must take energy from Exelon Wind under SPS’ PUCT-approved QF Tariff. Second, Exelon Wind has raised various challenges to SPS’ PUCT-approved QF Tariff, which became effective in August 2010. The state and federal lawsuits and regulatory proceedings are in various stages of litigation, including a pending appeal by SPS in the Fifth Circuit Court of Appeals. SPS believes the likelihood of loss in these lawsuits and proceedings is remote based primarily on existing case law and while it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome, SPS believes such loss would not be material based upon its belief that it would be permitted to recover such costs, if needed, through its various fuel clause mechanisms. No accrual has been recorded for this matter.

Other Contingencies

See Note 10 for further discussion.