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 the following major projects:

Advanced Grid Intelligence and Security Initiative — PSCo is pursuing projects to update and advance its electric distribution grid to increase reliability and security standards, meet customer expectations, offer additional customer choice and control over energy usage and implement new rate structures.

Rush Creek Wind Farm — PSCo has gained approval to build, own and operate a 600 MW wind generation facility and proposed transmission line in Colorado.

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 primarily pipeline assessment and maintenance projects.

Electric Distribution Integrity Management Programs — PSCo is assessing aging infrastructure for distribution assets and replacing worn components to increase system performance.

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 2017 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, 2016, are as follows:



(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2017	$	241.2	$	293.6	$	117.8
2018	143.1		185.7		69.0
2019	68.6		179.7		37.1
2020	48.5		184.3		36.6
2021	49.6		191.5		34.4
Thereafter	293.4		171.2		609.9
Total	$	844.4	$	1,206.0	$	904.8

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 2032 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 $44.0 million, $69.5 million and $69.5 million in 2016, 2015 and 2014, respectively. At Dec. 31, 2016, the estimated future payments for capacity and energy that PSCo is obligated to purchase pursuant to these executory contracts, subject to availability, are as follows:



(Millions of Dollars)	Capacity		Energy^(a)
2017	$	24.3	$	4.4
2018	20.1		—
2019	11.5		—
2020	3.0		—
2021	3.0		—
Thereafter	16.4		—
Total	$	78.3	$	4.4


^(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 — 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, LLC (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 $127.0 million and $132.9 million of capital lease obligations recorded for the arrangement as of Dec. 31, 2016 and 2015, 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 $8.1 million, $8.2 million, and $7.2 million for 2016, 2015 and 2014, respectively. Following is a summary of property held under capital leases:



(Millions of Dollars)	Dec. 31, 2016			Dec. 31, 2015
Gas storage facilities	$	200.5		$	200.5
Gas pipeline	20.7			20.7
Property held under capital leases	221.2			221.2
Accumulated depreciation	(65.3		)	(57.2		)
Total property held under capital leases, net	$	155.9		$	164.0

The remainder of the leases, primarily for office space, railcars, generating facilities, vehicles, aircraft and power-operated equipment, are accounted for as operating leases. Total expenses under operating lease obligations were approximately $118.2 million, $130.5 million and $126.2 million for 2016, 2015 and 2014, respectively. These expenses include capacity payments for PPAs accounted for as operating leases of $102.4 million, $113.5 million and $110.1 million in 2016, 2015 and 2014, 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 and capital leases are:



(Millions of Dollars)	Operating Leases		PPA ^{(a) (b)} Operating Leases		Total Operating Leases		Capital Leases
2017	$	11.0	$	96.3	$	107.3	$	25.7
2018	10.2		96.6		106.8		25.3
2019	10.3		97.5		107.8		25.1
2020	10.3		98.4		108.7		24.9
2021	9.7		99.4		109.1		23.8
Thereafter	45.2		483.7		528.9		462.7
Total minimum obligation							587.5
Interest component of obligation							(431.6		)
Present value of minimum obligation							$	155.9


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


^(b)	PPA operating leases contractually expire through 2032.

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 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 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 1,571 MW and 1,802 MW of capacity under long-term PPAs as of Dec. 31, 2016, and 2015, respectively, with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2032.

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 wastes to that site.

MGP Sites — PSCo is currently involved in investigating and/or remediating several MGP sites where 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 2017. PSCo had accrued $1.7 million for both of these sites at Dec. 31, 2016 and 2015, 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.

Coal Ash Regulation — PSCo’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. In 2015, the EPA published a final rule regulating the management and disposal of coal combustion residuals (“CCR” or coal ash) as a nonhazardous waste. In December 2016, the Water Infrastructure Improvements for the Nation Act (WIIN Act) was signed into law, which includes provisions that allow the CCR rule to be implemented through a state or federal based permit program and that give the EPA direct enforcement authority. PSCo is in the process of evaluating whether the costs of implementing the CCR rule under the potential federal and/or state permit programs could have a material impact on the results of operations, financial position or cash flows.

In 2015, industry and environmental non-governmental organizations sought judicial review of the final CCR rule. In June 2016, the D.C. Circuit issued an order remanding and vacating certain elements of the rule as a result of partial settlements with these parties. A final court decision is anticipated in the first half of 2017. Until a final decision is reached in the case, it is uncertain whether the litigation or partial settlements will have any significant impact on results of operations, financial position or cash flows on PSCo. PSCo believes that these associated costs would be recoverable through regulatory mechanisms.

Federal Clean Water Act (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. PSCo estimates that the capital cost to comply with the ELG rule will range from $9 million to $21 million, and could change as PSCo continues to assess alternate compliance technologies. PSCo believes that compliance costs would be recoverable through regulatory mechanisms.

Federal CWA Section 316(b) — Section 316(b) of 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. The EPA published the final 316(b) rule in 2014. The rule prescribes technology for protecting fish that get stuck on plant intake screens (known as impingement) and describes a process for site-specific determinations by each state for sites that must protect the small aquatic organisms that pass through the intake screens into the plant cooling systems (known as entrainment). The timing of compliance with the requirements will vary from plant-to-plant since the new rule does not have a final compliance deadline. PSCo does not anticipate the cost of compliance will have a material impact on the results of operations, financial position or cash flows.

Federal CWA Waters of the United States Rule — In June 2015, the EPA and the U.S. Army Corps of Engineers published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The expansion of the term “Waters of the U.S.” will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. 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 by June 2017.

Air

GHG Emission Standard for Existing Sources (Clean Power Plan or CPP) — In 2015, a final rule was published by the EPA for GHG emission standards for existing power plants. Under the rule, states were required to develop implementation plans by September 2016, with the possibility of an extension to September 2018, or submit to a federal plan for the state prepared by the EPA. Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets. The CPP was challenged by multiple parties in the D.C. Circuit Court. In January 2016, the D.C. Circuit Court denied requests to stay the effectiveness of the rule. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. In September 2016, the D.C. Circuit Court heard oral arguments in the consolidated challenges to the CPP. 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. During the pendency of the stay, states are not required to submit implementation plans and the EPA will not enforce deadlines or issue a federal plan for any state. Colorado is continuing formal planning efforts.

PSCo has undertaken a number of initiatives that reduce GHG emissions and respond to state renewable and energy efficiency goals. The CPP could require additional emission reductions in Colorado. If the state plan does not provide credit for the investments PSCo has already made to reduce GHG emissions, or if it requires additional initiatives or emission reductions, then its requirements would potentially impose additional substantial costs. Until PSCo has more information about a SIP or the EPA finalizes its proposed federal plan for the states that do not develop related plans, PSCo cannot predict the costs of compliance with the final rule once it takes effect. PSCo believes compliance costs will be recoverable through regulatory mechanisms. If PSCo’s regulators do not allow recovery of all or a part of the cost of capital investment or the O&M costs incurred to comply with the CPP or cost recovery is not provided in a timely manner, it could have a material impact on results of operations, financial position or cash flows.

Implementation of the NAAQS for SO₂ — The EPA adopted a more stringent NAAQS for SO₂ in 2010. The EPA is requiring states to evaluate areas in three phases. The first phase includes areas near PSCo’s Pawnee plant. The Pawnee plant recently installed an SO₂ scrubber to reduce SO₂ emissions. In June 2016, the EPA issued final designations which found the area near the Pawnee plant is “unclassifiable.” It is anticipated that the area near the Pawnee plant will be able to show compliance with the NAAQS through air dispersion modeling performed by the Colorado Department of Public Health and Environment.

The areas near the remaining PSCo power plants, Comanche and Hayden, which utilize scrubbers to control SO₂emissions, will be evaluated in the next designation phase, ending December 2017. In late 2016, PSCo submitted air dispersion modeling to the Colorado Department of Public Health and Environment and the EPA which demonstrated that PSCo’s Comanche and Hayden plants comply with the NAAQS. If an area is designated nonattainment in 2020, the states will need to evaluate all SO₂ sources in the area. The state would then submit an implementation plan, which would be due by 2022, designed to achieve the NAAQS by 2025. PSCo cannot evaluate the impacts until the designation of nonattainment areas is made and any required state plan has been developed. PSCo believes that should SO₂ control systems 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. The Denver Metropolitan Area is currently not meeting the prior ozone standard and will therefore not meet the new, more stringent, standard, however PSCo’s scheduled retirement of coal fired plants in Denver should help in any plan to mitigate non-attainment.

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, natural gas storage, thermal and common general property. The electric production obligations include asbestos, ash-containment facilities, radiation sources, storage tanks and control panels. The asbestos recognition associated with electric production includes certain specific plants. The AROs recorded for PSCo steam and other production relate to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills. 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.

PSCo recognized an ARO for the retirement costs of natural gas mains and lines and for the retirement of above ground gas gathering, extraction and wells related to 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, lithium batteries, mercury and street lighting lamps. The electric and common general AROs include small obligations related to storage tanks and radiation sources.

In April 2015, the EPA published the final rule regulating the management and disposal of coal combustion byproducts (e.g., coal ash) as a nonhazardous waste to the Federal Register. The rule became effective in October 2015. The estimated costs to comply with the final rule were incorporated into the cash flow revisions in 2015.

A reconciliation of PSCo’s AROs for the years ended Dec. 31, 2016 and 2015 is as follows:



(Thousands of Dollars)	Beginning Balance Jan. 1, 2016		Liabilities Recognized		Accretion		Cash Flow Revisions ^(a)			Ending Balance Dec. 31, 2016 ^(b)
Electric plant
Steam and other production asbestos	$	38,676	$	—	$	1,877	$	(103	)	$	40,450
Steam and other production ash containment	70,767		—		3,078		(1,245		)	72,600
Wind production	1,992		—		19		61			2,072
Electric distribution	1,130		—		45		6,494			7,669
Other	1,054		214		46		206			1,520
Natural gas plant
Gas transmission and distribution	122,168		—		5,009		33,542			160,719
Other	3,925		—		155		—			4,080
Common and other property
Common miscellaneous	796		—		28		(371		)	453
Total liability	$	240,508	$	214	$	10,257	$	38,584		$	289,563


^(a)	In 2016, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the gas transmission and distribution AROs were mainly related to increased miles of gas mains.


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



(Thousands of Dollars)	Beginning Balance Jan. 1, 2015		Accretion		Cash Flow Revisions ^(a)			Ending Balance Dec. 31, 2015 ^(b)
Electric plant
Steam and other production asbestos	$	36,856	$	1,820	$	—		$	38,676
Steam and other production ash containment	61,885		2,769		6,113			70,767
Wind production	2,095		18		(121		)	1,992
Electric distribution	1,182		47		(99		)	1,130
Other	1,150		46		(142		)	1,054
Natural gas plant
Gas transmission and distribution	117,474		4,694		—			122,168
Other	3,886		153		(114		)	3,925
Common and other property
Common miscellaneous	768		28		—			796
Total liability	$	225,296	$	9,575	$	5,637		$	240,508


^(a)	In 2015, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the ash containment ARO were mainly related to the final coal ash rule mentioned above.


^(b)	There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2015.

Indeterminate AROs — Outside of the known and recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of PSCo’s facilities, but no confirmation or measurement of the amount of asbestos or cost of removal could be determined as of Dec. 31, 2016. Therefore, an ARO has not been recorded for these facilities.

Removal Costs — PSCo 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, 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, 2016 and 2015 were $367 million and $364 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 — A complaint with the FERC posed that sales made in the Pacific Northwest in 2000 and 2001 through bilateral contracts were unjust and unreasonable under the Federal Power Act. The City of Seattle (the City) alleged between $34 million to $50 million in sales with PSCo were subject to refund. In 2003, the FERC terminated the proceeding, although it was later remanded back to the FERC in 2007 by the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).

In May 2015, the FERC rejected the City’s claim that any of the sales made resulted in an excessive burden and concluded that the City failed to establish a causal link between any contracts and any claimed unlawful market activity. In February 2016, the City appealed this decision to the Ninth Circuit.

In October 2016, a settlement was reached that resolved all outstanding claims between and among the City and the respondents, including PSCo. Settlement terms required PSCo to pay the City $15,000 and the City to withdraw its pending appeal with the Ninth Circuit. These terms have been met, bringing this matter to a close.

Line Extension Disputes — In December 2015, Development Recovery Company (DRC) filed a lawsuit in Denver State Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric service agreements entered into by PSCo and various developers. The dispute involves assigned interests in those claims by over fifty developers. In May 2016, the district court granted PSCo’s motion to dismiss the lawsuit, concluding that jurisdiction over this dispute resides with the CPUC. In June 2016, DRC filed a notice of appeal. The matter has been fully briefed and plaintiff has requested oral arguments. DRC also brought a proceeding before the CPUC as assignee on behalf of two developers, Ryland Homes and Richmond Homes of Colorado. In March 2016, the ALJ issued an order rejecting DRC’s claims for additional allowances and refunds. In June 2016, the ALJ’s determination was approved by the CPUC. DRC did not file a request for reconsideration before the CPUC contesting the decision, but filed an appeal in Denver District Court in August 2016. DRC filed its brief in February 2017 and PSCo’s answer brief will be due March 2017.

PSCo has concluded that a loss is remote with respect to this matter as the service agreements were developed to implement CPUC approved tariffs and PSCo has complied with the tariff provisions. Also, if a loss were sustained, PSCo believes it would be allowed to recover these costs through traditional regulatory mechanisms. The amount or range in dispute is presently unknown and no accrual has been recorded for this matter.

Other Contingencies

See Note 11 for further discussion.