Commitments and Contingencies

Commitments

Capital Commitments — PSCo has made commitments in connection with a portion of its projected capital expenditures. PSCo’s capital commitments primarily relate to two major projects.

CACJA — The CACJA required PSCo to file a plan to reduce annual emissions of NOx by at least 70 to 80 percent or greater from 2008 levels by 2017 from its coal fired generation resources. In September 2012, the EPA formally approved the Colorado SIP for regional haze, including resource planning changes that include early coal-fueled plant retirements, fuel switching and SCR installation.

Gas Transmission Integrity Management Programs – PSCo is proactively identifying and addressing the safety and reliability of natural gas transmission pipelines. The pipeline integrity efforts include system renewal projects and increased maintenance.

Fuel Contracts — PSCo 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 2060. PSCo is required to pay additional amounts depending on actual quantities shipped under these agreements.

The estimated minimum purchases for PSCo under these contracts as of Dec. 31, 2013, were as follows:



(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2014	$	330.3	$	384.3	$	137.2
2015	265.4		228.0		136.5
2016	232.2		225.6		77.1
2017	153.8		222.1		50.9
2018	42.5		278.4		50.8
Thereafter	424.7		1,211.1		854.4
Total	$	1,448.9	$	2,549.5	$	1,306.9

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

PPAs — PSCo has entered into PPAs with other utilities and energy suppliers with expiration dates through 2027 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. Certain PPAs accounted for as executory contracts also contain minimum energy purchase commitments. Capacity and energy 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 $72.7 million, $119.5 million and $178.8 million in 2013, 2012 and 2011, respectively. At Dec. 31, 2013, the estimated future payments for capacity and energy that PSCo is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:



(Millions of Dollars)	Capacity		Energy^(a)
2014	$	82.4	$	43.6
2015	82.6		36.8
2016	58.3		18.6
2017	35.2		3.1
2018	28.1		—
Thereafter	69.9		—
Total	$	356.5	$	102.1


^(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 — PSCo leases a variety of equipment and facilities used in the normal course of business. Three of these leases qualify as capital leases and are accounted for accordingly. The assets and liabilities at the inception of a capital lease are recorded at the lower of fair-market value or the present value of future lease payments and are amortized over the term of the contract.

WYCO was formed as a joint venture between Xcel Energy Inc. and Colorado Interstate Gas Company (CIG) to develop and lease natural gas pipeline, storage, and compression facilities. Xcel Energy Inc. has a 50 percent ownership interest in WYCO, and PSCo has no direct ownership interest. WYCO generally leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage services to PSCo under separate service agreements.

PSCo accounts for its Totem natural gas storage service arrangement with CIG as a capital lease. As a result, PSCo had $144.2 million and $148.7 million of capital lease obligations recorded for the arrangement as of Dec. 31, 2013 and 2012, respectively.

PSCo records amortization for its capital leases as cost of natural gas sold and transported on the consolidated statements of income. Total amortization expenses under capital lease assets were approximately $6.3 million, $5.7 million, and $3.2 million for 2013, 2012 and 2011, respectively. Following is a summary of property held under capital leases:



(Millions of Dollars)	Dec. 31, 2013			Dec. 31, 2012
Storage, leaseholds and rights	$	200.5		$	200.5
Gas pipeline	20.7			20.7
Property held under capital lease	221.2			221.2
Accumulated depreciation	(41.8		)	(35.5		)
Total property held under capital leases, net	$	179.4		$	185.7

The remainder of the leases, primarily for certain PPAs, office space, railcars, generating facilities, trucks, aircraft, cars and power-operated equipment are accounted for as operating leases. Total expenses under operating lease obligations were approximately $96.6 million, $77.9 million and $71.3 million for 2013, 2012 and 2011, respectively. These expenses included capacity payments for PPAs accounted for as operating leases of $79.6 million, $59.4 million and $47.9 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 payments under PPAs that have been accounted for as operating leases in accordance with the applicable accounting guidance. Future commitments under operating and capital leases are:



(Millions of Dollars)	Operating Leases		PPA Operating Leases ^{(a) (b)}		Total Operating Leases		Capital Leases
2014	$	14.8	$	94.8	$	109.6	$	30.6
2015	14.6		95.3		109.9		30.5
2016	11.7		84.0		95.7		29.3
2017	6.9		78.7		85.6		25.6
2018	6.6		79.3		85.9		25.2
Thereafter	48.0		548.6		596.6		538.2
Total minimum obligation							679.4
Interest component of obligation							(500.0		)
Present value of minimum obligation							$	179.4


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


^(b)	PPA operating leases contractually expire through 2028.

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, PSCo purchases power from independent power producing entities for which PSCo is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which PSCo 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.

PSCo has determined that certain independent power producing entities are variable interest entities. PSCo 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.

PSCo 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. PSCo has 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. PSCo had approximately 1,441 MW and 1,433 MW of capacity under long-term PPAs as of Dec. 31, 2013, and 2012, respectively, with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2028.

Environmental Contingencies

PSCo has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, PSCo believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, PSCo 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 PSCo, which are normally recovered through the regulated rate process. To the extent any costs are not recovered through the options listed above, PSCo 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. PSCo may sometimes pay all or a portion of the cost to remediate sites where past activities of PSCo or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs operated by PSCo, its predecessors, or other entities; and third-party sites, such as landfills, for which PSCo is alleged to be a PRP that sent hazardous materials and wastes to that site.

MGP Sites — PSCo is currently involved in investigating and/or remediating several MGP sites where hazardous or other regulated materials may have been deposited. PSCo has identified two sites, where former MGP activities have or may have resulted in site contamination and are under current investigation and/or remediation. At some or all of these MGP sites, there are other parties that may have responsibility for some portion of any remediation. PSCo anticipates that the majority of the remediation at these sites will continue through at least 2014. PSCo had accrued $1.2 million and $0.4 million for both these sites at Dec. 31, 2013 and 2012, respectively. There may be insurance recovery and/or recovery from other PRPs that will offset any costs incurred. PSCo anticipates that any amounts spent will be fully recovered from customers.

Environmental Requirements

Water and waste

Asbestos Removal — Some of PSCo’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. PSCo 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 (CWA) 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 PSCo is uncertain at this time.

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 adverse environmental impacts to aquatic species. In 2011, the EPA published the proposed rule that sets standards for minimization of aquatic species impingement, but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office. A final rule is anticipated in April 2014. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the uncertainty of the final regulatory requirements.

Proposed Coal Ash Regulation — PSCo’s 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. PSCo’s 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. PSCo 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 PSCo’s 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.

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. PSCo expects to comply with the EGU MATS rule through a combination of mercury and other emission control projects. PSCo 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, Colorado identified the PSCo facilities that will have to reduce SO₂, NOx and PM emissions under BART and set emissions limits for those facilities.

In 2011, the Colorado Air Quality Control Commission approved a SIP that included the CACJA emission reduction plan as satisfying regional haze requirements for the facilities included in the CACJA plan. In addition, the SIP included a BART determination for Comanche Units 1 and 2. The EPA approved the SIP in 2012. Emission controls at the Hayden and Pawnee plants are projected to cost $359.5 million and are expected to be installed between 2014 and 2017. PSCo anticipates these costs will be fully recoverable in rates.

The Colorado Mining Association (CMA) challenged the SIP in Colorado District Court. The District Court dismissed the CMA’s challenge in 2012, and the Colorado Court of Appeals upheld the District Court’s decision in November 2013. The CMA did not petition for review by the Colorado Supreme Court, thus ending the case.

In March 2013, WildEarth Guardians petitioned the U.S. Court of Appeals for the 10^th Circuit to review the EPA’s decision approving the SIP. WildEarth Guardians has stated it will challenge the BART determination made for Comanche Units 1 and 2. In comments before the EPA, WildEarth Guardians urged that current emission limitations be made more stringent or that SCR be added to the units. PSCo intervened in the case. The 10^th Circuit is scheduled to hear argument in November 2014, following completion of the briefs in August 2014.

In 2010, two environmental groups petitioned the DOI to certify that 12 coal-fired boilers and one coal-fired cement kiln in Colorado are contributing to visibility problems in Rocky Mountain National Park. The following PSCo plants are named in the petition: Cherokee, Hayden, Pawnee and Valmont. The groups allege the Colorado BART rule is inadequate to satisfy the CAA mandate of ensuring reasonable further progress towards restoring natural visibility conditions in the park. It is not known when the DOI will rule on the petition.

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 PSCo 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.

Notice of Violation (NOV) — In 2002, PSCo received an NOV from the EPA alleging violations of the New Source Review (NSR) requirements of the CAA at the Comanche Station and Pawnee Generating Station in Colorado. The NOV alleges that various maintenance, repair and replacement projects at the plants in the mid to late 1990s should have required a permit under the NSR process. PSCo believes it has acted in full compliance with the CAA and NSR process. PSCo also believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. PSCo disagrees with the assertions contained in the NOV and intends to vigorously defend its position. It is not known whether any costs would be incurred as a result of this NOV.

Asset Retirement Obligations

Recorded AROs — AROs have been recorded for property related to the following: electric production (steam, wind, other and hydro), electric distribution and transmission, natural gas production, natural gas transmission and distribution, and general property. The electric production obligations include asbestos, ash-containment facilities, radiation sources, storage tanks, control panels. The asbestos recognition associated with the steam production includes certain plants. This asbestos abatement removal obligation originated in 1973 with the CAA, which applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal. The AROs recorded for PSCo steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills and the origination dates on the ARO recognition for ash containment facilities at steam plants was the in-service dates of the various facilities. PSCo has also recorded AROs for the retirement and removal of assets at certain wind production facilities for which the land is leased and removal is required by contract, with the origination dates being the in-service date of the various facilities.

PSCo recognized an ARO for the retirement costs of its natural gas mains and the retirement of above ground gas storage facilities. In addition, an ARO was recognized for the removal of electric, transmission and distribution equipment, which consists of many small potential obligations associated with PCBs, mineral oil, storage tanks, treated poles, lithium batteries, mercury and street lighting lamps. The common general AROs include small obligations related to storage tanks, radiation sources and office buildings. These assets have many 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 PSCo’s AROs is shown in the tables below for the years ended Dec. 31, 2013 and 2012, respectively:



(Thousands of Dollars)	Beginning Balance Jan. 1, 2013		Liabilities Recognized		Liabilities Settled			Accretion		Revisions to Prior Estimates			Ending Balance Dec. 31, 2013
Electric plant
Steam and other production asbestos	$	19,734	$	—	$	(941	)	$	1,247	$	3,874		$	23,914
Steam and other production ash containment	12,919		—		—			684		15,631			29,234
Wind production	2,928		—		—			25		—			2,953
Electric distribution	6,392		—		—			178		(5,394		)	1,176
Other	627		—		—			60		330			1,017
Natural gas plant
Gas transmission and distribution	842		—		—			53		(107		)	788
Gas gathering	—		575		—			—		—			575
Common and other property
Common miscellaneous	309		—		—			29		403			741
Total liability	$	43,751	$	575	$	(941	)	$	2,276	$	14,737		$	60,398



(Thousands of Dollars)	Beginning Balance Jan. 1, 2012		Liabilities Recognized		Liabilities Settled			Accretion		Revisions to Prior Estimates			Ending Balance Dec. 31, 2012
Electric plant
Steam and other production asbestos	$	23,062	$	—	$	(9,372	)	$	1,536	$	4,508		$	19,734
Steam and other production ash containment	9,449		—		—			499		2,971			12,919
Wind production	—		2,928		—			—		—			2,928
Electric distribution	8,005		—		—			290		(1,903		)	6,392
Other	583		—		—			25		19			627
Natural gas plant
Gas transmission and distribution	810		—		—			48		(16		)	842
Common and other property
Common miscellaneous	298		—		—			11		—			309
Total liability	$	42,207	$	2,928	$	(9,372	)	$	2,409	$	5,579		$	43,751

In 2013, PSCo revised asbestos, ash containment facilities, radiation sources, miscellaneous electric production, electric transmission and distribution, natural gas transmission and distribution and common general AROs due to revised estimated cash flows. Additionally, in 2013, an ARO was recorded to reflect the expected costs with the retirement of certain gas gathering facilities and an ARO was settled for the asbestos abatement at the Cameo generating facility.

In 2012, PSCo revised asbestos, ash containment facilities and electric transmission and distribution AROs due revised estimated cash flows. Additionally, in 2012, an ARO was recorded to reflect the expected costs with the retirement of certain wind production facilities.

Indeterminate AROs —PSCo has underground natural gas storage facilities that have special closure requirements for which the final removal date cannot be determined, therefore an ARO has not been recorded.

Removal Costs — PSCo 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, PSCo 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, 2013 and 2012 were $359 million and $365 million, respectively.

Legal Contingencies

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

Employment, Tort and Commercial Litigation

Pacific Northwest FERC Refund Proceeding — In July 2001, the FERC ordered a preliminary hearing to determine whether there were unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for December 2000 through June 2001. PSCo supplied energy to the Pacific Northwest markets during this period and has been a participant in the hearings. In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances, the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered. Subsequent to the ruling, the FERC has allowed the parties to request additional evidence. Parties have claimed that the total amount of transactions with PSCo subject to refund is $34 million. In June 2003, the FERC issued an order terminating the proceeding without ordering further proceedings. Certain purchasers filed appeals of the FERC’s orders in this proceeding with the Ninth Circuit.

In an order issued in August 2007, the Ninth Circuit remanded the proceeding back to the FERC and indicated that the FERC should consider other rulings addressing overcharges in the California organized markets. The Ninth Circuit denied a petition for rehearing in April 2009, and the mandate was issued.

The FERC issued an order on remand establishing principles for the review proceeding in October 2011. In September 2012, the City of Seattle filed its direct case against PSCo and other Pacific Northwest sellers claiming refunds for the period January 2000 through June 2001. The City of Seattle indicated that for the period June 2000 through June 2001 PSCo had sales to the City of Seattle of approximately $50 million. The City of Seattle did not identify specific instances of unlawful market activity by PSCo, but rather based its claim for refunds on market dysfunction in the Western markets. PSCo submitted its answering case in December 2012.

In April 2013, the FERC issued an order on rehearing. The FERC confirmed that the City of Seattle would be able to attempt to obtain refunds back from January 2000, but reaffirmed the transaction-specific standard that the City of Seattle and other complainants would have to comply with to obtain refunds. In addition, the FERC rejected the imposition of any market-wide remedies. Although the FERC order on rehearing established the period for which the City of Seattle could seek refunds as January 2000 through June 2001, it is unclear what claim the City of Seattle has against PSCo prior to June 2000. In the proceeding, the City of Seattle does not allege specific misconduct or tariff violations by PSCo but instead asserts generally that the rates charged by PSCo and other sellers were excessive.

A hearing in this case was held before a FERC ALJ and concluded in October 2013. The matter is presently being briefed, and the ALJ is expected to issue an initial decision on or before March 18, 2014.

Preliminary calculations of the City of Seattle’s claim for refunds from PSCo are approximately $28 million excluding interest. PSCo has concluded that a loss is reasonably possible with respect to this matter; however, given the surrounding uncertainties, PSCo is currently unable to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter. In making this assessment, PSCo considered two factors. First, not withstanding PSCo’s view that the City of Seattle has failed to apply the standard that the FERC has established in this proceeding, and the recognition that this case raises a novel issue and the FERC’s standard has been challenged on appeal to the Ninth Circuit, the outcome of such an appeal cannot be predicted with any certainty. Second, PSCo would expect to make equitable arguments against refunds even if the City of Seattle were to establish that it was overcharged for transactions. If a loss were sustained, PSCo would attempt to recover those losses from other PRPs. No accrual has been recorded for this matter.

Other Contingencies

See Note 11 for further discussion.