BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF COLORADO

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IN THE MATTER OF THE APPLICATION OF PUBLIC SERVICE COMPANY OF COLORADO FOR A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY FOR THE GREENWOOD TO DENVER TERMINAL 230 KV TRANSMISSION PROJECT ASSOCIATED WITH THE COLORADO ENERGY PLAN, ASSOCIATED FINDINGS OF NOISE AND MAGNETIC FIELD REASONABLENESS, AND UPRATE PROJECTS

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PROCEEDING NO. 20A-XXXXE

VERIFIED APPLICATION OF PUBLIC SERVICE COMPANY OF COLORADO FOR ORDER GRANTING A CERTIFICATE OF PUBLIC CONVENIENCE AND

NECESSITY FOR THE GREENWOOD TO DENVER TERMINAL 230 KV TRANSMISSION PROJECT AND TRANSMISSION LINE UPRATE PROJECTS

ASSOCIATED WITH THE COLORADO ENERGY PLAN PORTFOLIO

In accordance with § 40-5-101, C.R.S., 4 CCR 723-3-3002, 4 CCR 723-3-

3102, 4-CCR 723-3-3206, and Decision No. C18-0761, Public Service Company of

Colorado (“Public Service” or the “Company”) hereby requests that the Colorado

Public Utilities Commission (“Commission”) grant a Certificate of Public

Convenience and Necessity (“CPCN”) to construct the Greenwood to Denver

Terminal 230 kV Transmission Project (“GDT Project” or “Project”) and three

transmission line uprate projects. The GDT Project includes: (1) installing

approximately 15 miles of new 230 kV transmission facilities located in existing

rights-of-way (“ROW”) originating at the existing Greenwood Substation located in

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the southeastern Denver Metro area, and terminating at the Denver Terminal

Substation located on the west side of the City of Denver’s city center; and (2)

modifications to the existing Greenwood, Arapahoe, and Denver Terminal

Substations to accommodate the new 230 kV circuit, including an expansion of the

Denver Terminal Substation. The Company also plans to perform minor uprates to

three existing transmission lines by modifying termination equipment within existing

substations.1

As explained in more detail below, the GDT Project and transmission line

uprates are needed to implement the Colorado Energy Plan Portfolio (“CEPP”)

approved by the Commission in Decision No. C18-0761 in Proceeding No. 16A-

0396E (i.e., the Company’s 2016 Electric Resource Plan (“ERP”) proceeding).

Public Service estimates that the construction of the Project using the preferred

approach will cost approximately $50.1 million with an additional $1.8 million for the

three transmission line uprate projects, both components plus or minus 20 percent.

In addition to granting a CPCN, Public Service requests that the Commission grant a

presumption of prudence for the costs of the Project and transmission line uprate

projects. Public Service also requests the Commission find that the projected noise

and magnetic field levels that will result from operating the GDT Project are

reasonable by rule and require no further mitigation.

1 The uprates to existing transmission lines do not require new construction or extension of transmission facilities, as the power carrying capabilities (continuous ratings) of these lines are limited by facilities other than the transmission conductors (e.g., switches, jumpers, and relay equipment in existing substations) that when replaced, allow the continuous rating of the transmission line to be the conductor rating.

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By Decision No. C18-0761, the Commission approved the Company’s CEPP

following a competitive resource solicitation process implemented by the Company

to meet its resource needs through 2023. In approving the CEPP, the Commission

granted the Company a presumption of prudence regarding future actions to pursue

these new resources, but also directed the Company to file for CPCNs for related

projects and investments. According to Paragraph 133 of Decision No. C18-0761,

the Commission directed Public Service to:

file a CPCN application for ... the additional transmission investment identified in the 120-Day Report for the Pueblo area that is part of the $204 million total transmission investment associated with the CEP Portfolio. The application for the CPCNs shall be filed pursuant to Rule 4 CCR 723-3-3102.

While the GDT Project is not located in the Pueblo area, it comprises part of

the transmission investment associated with the CEPP as identified in the 120-Day

Report and discussed in Decision No. C18-0761. In addition to the network

upgrades that are the subject of this CPCN application, the total transmission

investment associated with the CEPP includes two other categories of transmission

investment as initially described in the Company’s 120-Day Report, including: (1)

voltage control facilities for which the Company filed a CPCN Application on

December 20, 2019 (Proceeding No. 19A-0728E), and (2) interconnection facilities

(i.e., Badger Hills switching station2 located in the Pueblo area and other switching

stations/substations necessary to interconnect CEPP generation facilities), which will

be the subject of a future CPCN Application, likely filed after the Commission has 2 The proposed switching station identified as Badger Hills throughout Proceeding No. 16A-0396E has been renamed “Mirasol” at Pueblo’s request.

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issued a final decision in the Company’s ongoing ERP Amendment filing

(Proceeding No. 19A-0530E).

In support of its request for a CPCN for the GDT Project and transmission line

uprates, Public Service is including with this Application the pre-filed Direct

Testimony and accompanying Attachments of the following three witnesses:

Mr. Thomas W. Green, Consulting Engineer, Xcel Energy Services Inc.

(“XES”). Mr. Green supports the Company’s Application by providing a detailed

description of the GDT Project, transmission line uprates, and the system benefits

they will provide. Mr. Green presents and explains transmission studies performed

to evaluate the Project and uprates, system alternatives that were investigated, and

the Company’s analysis and conclusions regarding the system studies. He explains

how the Company’s planning comports with Commission Rule 3627, including the

stakeholder outreach, and discusses the Company’s planned Transmission Cost

Adjustment (“TCA”) cost recovery. Mr. Green’s Direct Testimony establishes that

the Project and transmission line uprates are needed from a reliability perspective

and are in the public interest.

Mr. Stanley (“Parker”) Wrozek, Senior Manager, Transmission Engineering

with XES. Mr. Wrozek addresses the transmission line design criteria associated

with the GDT Project, including the details of the structures and conductor. Mr.

Wrozek also presents the results of the noise and magnetic field analyses that were

performed for the Project and identifies the specific reasonableness findings that the

Company is requesting regarding transmission magnetic field and audible noise

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levels. Finally, Mr. Wrozek discusses the Project’s estimated costs and construction

timeline.

Ms. Carly R. Rowe, Manager, Siting and Land Rights with XES. Ms. Rowe

describes the siting, permitting, and land rights associated with the Project, including

the Company’s public outreach activities that have occurred or are planned to occur.

Ms. Rowe also explains the estimated timing associated with public outreach and

construction-related activities and discusses the land use cost estimates associated

with the Project.

In further support of its request, Public Service states as follows:

I. REQUEST FOR A CPCN

A. Information Required by Rule 3102(b)(I)

1. Please see Section IV below for the information required by Rule

3002(b) and (c).

B. Facts Relied Upon to Show that the Public Convenience and Necessity Require Granting this Application (Rule 3102(b)(II))

2. The GDT Project and transmission line uprates arise from the

Transmission Planning studies that occurred to implement the new generation

facilities approved as part of the CEPP. The CEPP will develop a significantly

cleaner energy mix and reduce carbon emissions in Colorado through the specific

acquisition and retirement of certain generation facilities through 2025. Through the

CEPP, the Company will add approximately 1,100 MW of wind generation

(approximately 162 MW of which is existing), 700 MW of solar generation, and 275

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MW of battery storage (all embedded in solar plus storage projects) to the system.3

Public Service will also retire 660 MW of coal-fired generating facilities (Comanche 1

in 2022 and Comanche 2 in 2025) in southern Colorado. Through the course of the

2016 ERP and in its 120-Day Report where it presented the CEPP, Public Service

indicated that a number of additional investments, including transmission network

upgrades, would be necessary to accommodate the CEPP. The GDT Project

encompasses transmission network upgrades that will be necessary to reliably

deliver CEPP generation to load in the Denver Metro area.

3. Specifically, the GDT Project and transmission line uprates are

necessary to increase reliability and mitigate potential unacceptable transmission

loading conditions due to additional generation facilities associated with the

Company’s CEPP coming online, by providing another transmission path into the

Denver Metro load center. As explained in more detail below, the Company’s

detailed transmission studies show the potential for overloading on numerous lines

in the Denver Metro area during high generation dispatch conditions, particularly

from the CEPP’s new renewable generation resources located near the Company’s

Comanche and Missile Site Substations.

4. As further explained in the Company’s 120-Day Report and in Mr.

Green’s Direct Testimony supporting this Application, transmission upgrades are

required in the Denver Metro area to reliably accommodate the Commission-

approved CEPP generation facilities. Mr. Green further explains that the GDP 3 MW figures for solar and solar with storage are approximate and subject to modification pending a final decision in the 2016 ERP Amendment proceeding (Proceeding No. 19A-0530E).

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Project and transmission line uprates will provide the transmission system upgrades

that are necessary to accommodate the CEPP while maintaining system reliability in

the Denver Metro area.

C. Description of the Proposed Facilities to be Constructed (Rule 3102(b)(III))

5. The GDT Project involves constructing approximately 15 miles of 230

kV transmission line using 1272 aluminum conductor steel-reinforced (“ACSR”)

Bittern conductor in existing transmission line ROW. For purposes of its CPCN

filing, the Company presents and describes the Project in five segments (Segments

1 through 5) between existing substations, as different work (i.e., rebuilding,

reconductoring and/or re-energizing) will occur within each segment to establish the

new 230 kV circuit.

6. Table 1 below provides a description of the existing and proposed

transmission infrastructure by Project segment.

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Table 1: Existing and Proposed Transmission Infrastructure

Project Segment Identification (length in miles)

Existing Transmission Infrastructure

Proposed Transmission Infrastructure

Project Segment construction description Segment 1: Greenwood Substation – Englewood Substation

5.6 milesDouble circuit 115 kV de-energized transmission line on steel lattice structures.

New 230 kV single circuit monopole structures.

Segment 1 involves rebuilding approximately 5.6 miles of an existing 115 kV double circuit line to a single circuit 230 kV line from the Greenwood Substation to the Englewood Substation (bypassing the Englewood Substation). The existing structures will be removed and replaced with new 230 kV single circuit monopole structures within the existing right of way. The Greenwood Substation will be modified to allow for the new 230 kV line termination. There will be no modifications at the Englewood Substation.

Segment 2: Englewood Substation to Englewood Tap 0.5 miles

Double circuit 115 kV transmission line on steel lattice structures, one circuit de-energized.

Double circuit 115/230 kV monopole structures.

Segment 2 involves replacing four existing double-circuit 115 kV lattice structures with four monopole structures that will support the existing 115 kV line and the new 230 kV circuit between Englewood Substation (bypassing the Substation) and the Englewood Tap. There will be no modifications at the Englewood Substation.

Segment 3: Englewood Tap to Arapahoe Substation 3.4 miles

Double circuit 115/230 kV transmission line on steel lattice structures.

Double circuit 230 kV on existing structures.

Segment 3 involves reconductoring approximately 3.4 miles of the existing double circuit 115/230 kV line to double circuit 230 kV by replacing the conductors on the structures so that both circuits will operate at 230 kV. The Arapahoe Substation will be modified within the existing property fence line to accommodate the new 230 kV circuit.

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Project Segment Identification

(length in miles)Existing Transmission

Infrastructure

Proposed Transmission Infrastructure

Project Segment construction description Segment 4: Arapahoe Substation to South Substation

2.0 miles Double circuit 230 kV transmission line on monopole structures. One side is currently energized at 115 kV.

Double circuit 230 kV transmission line on existing monopole structures.

Segment 4 involves reenergizing approximately 2.0 miles of an existing 115 kV line to 230 kV from the Arapahoe Substation to the South Substation (bypassing the South Substation). The existing 115 kV circuit will be connected to an existing deenergized 115 kV circuit between Arapahoe and South substations and will then be energized to 230 kV. No changes to the currently energized 230 kV circuit will occur. There will be no modifications at the South Substation.

Segment 5: South Substation to Denver Terminal Substation 3.9 miles

Single circuit 230 kV transmission line on monopole structures.

Double circuit 230 kV transmission line on monopole structures.

Segment 5 involves rebuilding approximately 3.9 miles of existing monopole single circuit 230 kV line from the South Substation (bypassing the South Substation) to the Denver Terminal Substation within existing right of way and replacing the existing structures with monopole structures to accommodate double circuit 230 kV transmission line. The Denver Terminal Substation will be modified to accommodate the new 230 kV line termination. There will be no modifications to the South Substation.

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7. The Company also plans to perform several minor uprates to three

existing transmission lines to accommodate the CEPP’s additional generation

capacity. These lines are the:

x Greenwood-Monaco 230 kV line;

x Leetsdale-Monaco 230 kV line; and

x Daniels Park-Prairie-Greenwood 230 kV line.

8. The Company refers to these as uprates rather than upgrades, since

the modifications do not require new construction or extension of facilities, and do

not result in a change in voltage. The power carrying capabilities (continuous

ratings) of these lines are presently limited by facilities other than the transmission

line conductors. Those facilities include termination equipment within substations at

each end of the lines (for example, switches, jumpers, and relay equipment). These

uprates will replace those facilities to allow the continuous rating to be the conductor

rating.

D. Estimated Project Costs (Rule 3102(b)(IV))

9. Public Service estimates that the GDT Project will cost approximately

$50.1 million. An itemized breakdown of these costs into categories for land,

substations, and transmission lines is provided in the Direct Testimony of Mr.

Wrozek. Ms. Rowe discusses the Company’s expected lack of need to acquire new

land for the Project; however, there will be land use costs associated with the GDT

Project, which are included within the Transmission Line and Substation category

costs presented in the Direct Testimony of Mr. Wrozek.

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10. The total cost for the three uprates is estimated to be approximately

$1.8 million.

11. In the Company’s experience, the final Project costs, once completed

and placed in service, are expected to be within plus or minus 20 percent of this

estimate (i.e., $51.9 million total estimate for both components). The primary

reasons for a level of accuracy within 20 percent include: (1) the final engineering

design on which the estimates are based is not complete; (2) final costs for materials

and construction may differ from estimates; and (3) the Company has not yet

received bid information for facilities.

E. Anticipated Construction Start Date, Construction Period, and In-Service Date (Rule 3102(b)(V))

12. The GDT Project is included in the Company’s capital budget and

Public Service plans to commence construction in July 2021. The Company

anticipates it will take approximately 18 months for Project construction with an in-

service date of December 2022. Mr. Wrozek discusses the Project timeline in his

Direct Testimony.

13. The Company anticipates the uprates will be installed by the end of

2020.

F. Vicinity Map (Rule 3102(b)(VI))

14. Maps showing the general area and/or actual locations where facilities

will be constructed, population centers, major highways, and county and state

boundaries are provided in or attached to the testimonies of Mr. Green and Ms.

Rowe.

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G. Electric One-Line Diagram (Rule 3102(b)(VII))

15. A one-line diagram of the Project can be found attached to the Direct

Testimony of Mr. Green.

H. Alternatives Studied (Rule 3102(b)(VIII))

16. The Greenwood to Denver Terminal 230 kV Transmission Project

System Impact Study Report (“Study Report”) sponsored and discussed by Mr.

Green describes the analysis that was performed and the various alternatives that

were considered to address the potential impacts of the CEPP. While some of the

transmission and non-transmission alternatives included in the Study Report were

deemed infeasible for various reasons (e.g., siting and land rights issues or inability

to fully mitigate potential overloads), two technically feasible alternatives the

Company considered and modeled in developing the Project include:

x Upgrade all transmission lines shown to have potential overload issues in the study, including both overhead and underground transmission and equipment replacements at nine existing substations; and

x Rebuild an existing double-circuit 115 kV transmission network to 230 kV between the Smoky Hill Substation and Cherokee Substation, including approximately 30 miles of replacement transmission line.

17. The Study Report identifies the Project as the preferred transmission

alternative for network upgrades to accommodate the CEPP. Although the

Company considered energy storage systems alternatives to the transmission

infrastructure associated with the GDT Project and uprates, it does not believe there

are proven, commercially available energy storage system technologies that could

be effectively deployed as a feasible alternative to the GDP Project and uprates at

this time to address the overloading issues presented by the CEPP. The Project

meets the necessary performance and reliability criteria and can be implemented in

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the timeframe needed to accommodate the CEPP resources. Further, it will

minimize the land footprint and permitting requirements of the transmission facilities

by using existing transmission line ROW.

18. Ms. Rowe discusses project alternatives the Company considered and

eliminated from a siting and land rights perspective.

I. Prudent Avoidance Measures (Rule 3102(b)(IX) and (d))

19. Mr. Wrozek discusses prudent avoidance measures the Company

routinely incorporates into its transmission project construction and design, and

which it has incorporated into this Project. For this Project, however, the Company’s

design is sufficient to meet the noise and magnetic field thresholds that are deemed

reasonable by Commission rule. Therefore, the Company does not plan to apply

any additional prudent avoidance techniques to the Project design and construction.

J. Finding of Reasonableness for Noise and Magnetic Fields (Rules 3102(b)(X), 3102(c), 3206(e), and 3206(f))

20. The Company retained the consulting firm Tetra Tech to analyze

expected noise and magnetic field levels associated with the Project. With respect

to its noise analysis, Tetra Tech conducted a computer analysis consistent with Rule

3102(d). Tetra Tech’s analysis determined that the audible noise and magnetic

fields from the Project will fall within the deemed reasonable levels set forth in Rule

3206(e) and (f). The Company therefore requests that the audible noise and

magnetic field levels associated with the Project be deemed reasonable pursuant to

Rule 3206(e) and (f), requiring no further mitigation. Mr. Wrozek presents the Tetra

Tech report and discusses the projected noise and magnetic fields results in detail in

his Direct Testimony.

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K. Other Information Required by Rule 3206(g) and (h)

21. As Mr. Green testifies, consistent with Rule 3206(g), Public Service will

install and maintain service connections from transmission extensions consistent

with the conditions set forth in its electric tariff.

22. The GDT Project was identified in the Company’s 2020 Rule 3627

Report filed on February 3, 2020 in Proceeding No. 20M-0008E, and the Company’s

2019 Rule 3206 Report filed on April 30, 2019 in Proceeding No. 19M-0005E. The

GDT Project was not identified in the Company’s 2018 Rule 3627 Ten-Year Report

filed on February 1, 2018 in Proceeding No. 18M-0080E, as the Commission had not

yet approved the CEPP as part of the Company’s Phase II ERP.

23. The Company did not specifically identify the three transmission line

uprate projects in its last Rule 3206 Report as they are projects that would typically

be considered in the ordinary course of business and therefore were not specifically

identified until the Company conducted its Study Report.

24. Mr. Green discusses additional stakeholder engagement the Company

conducted through the Colorado Coordinated Planning Group process.

II. SITING, PERMITTING, AND OUTREACH

25. Section 40-5-101(3), C.R.S., vests local governments rather than the

Commission with authority over siting. Consistent with Colorado law, local

governments will review and approve the development of all utility facilities

associated with the Project through various local land use permitting processes.

While the Company is not seeking specific Commission approval of the siting in its

Application, to provide context, Company witness Ms. Rowe discusses the siting,

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permitting, and land rights activities associated with the Project in her Direct

Testimony.

26. As Ms. Rowe explains, the Project will be constructed in existing ROW

in six different municipalities. The Project involves rebuilding, reconductoring, and/or

re-energizing segments of existing transmission facilities in existing ROW and

therefore, there are no land acquisition costs expected. The Company does

anticipate incurring land use costs, including, for instance, costs for permitting and

outreach, legal and consultant support (e.g., environmental specialists, land

surveyors, title work, appraisers, etc.), minor easement modifications, and

construction-related payments.

27. To date, the Company has met with elected officials and the land use

planning staff of all six affected municipalities. Based on these meetings, the cities

of Sheridan, Greenwood Village, Centennial, Englewood, and Littleton have stated

that no land use permits are required for the Project. The Company anticipates

needing to obtain a land use permit from the City of Denver for the expansion of the

Denver Terminal Substation and possibly for short spans of the transmission line

that may require minor rerouting on Public Service property near the Arapahoe,

South, and Denver Terminal substations.

28. The Company anticipates that any necessary land use permits will be

acquired by Q3 2020. Additionally, required construction-related permits will be

obtained between the acquisition of any required land use permits and the

commencement of construction, which is expected to commence in July 2021.

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III. COST RECOVERY

29. The Company plans to include the costs associated with the GDT

Project and three uprates in a future TCA filing for recovery through the TCA Rider.

The Company requests that the Commission grant a presumption of prudence

finding for the $50.1 million in costs associated with the GDT Project, in addition to

the $1.8 million in costs associated with the three transmission line uprate projects

(both components plus or minus 20 percent).

IV. ADDITIONAL INFORMATION REQUIRED BY RULE 3002(b) AND (c)

30. Name and Address of Applicant. Public Service is an operating public

utility subject to the jurisdiction of this Commission, engaged, inter alia, in the

transmission, distribution and purchase of electricity and gas in various areas in the

State of Colorado. The name and address of the Applicant is:

Public Service Company of Colorado 1800 Larimer Street, Suite 1400 Denver, CO 80202-5533 31. Name Under Which Applicant Provides Service in Colorado. All

operations conducted by the Company in Colorado are conducted under the name

of Public Service Company of Colorado, under the trade name of Xcel Energy.

32. Representatives to Whom Inquiries Concerning the Application Should

Be Made. Please send copies of all inquiries, notices, pleadings, correspondence,

and other documents regarding this filing to:

Thomas Green Consulting Engineer Xcel Energy Services Inc. 1800 Larimer Street, Suite 600 Denver, Colorado 80202 Tel: (303) 571-7223 Email: thomas.green@xcelenergy.com Sage Tauber Regulatory Policy Specialist Xcel Energy Services Inc. 1800 Larimer Street, Suite 1400 Denver, Colorado 80202 Tel: (303) 294-2847 Email: sage.tauber@xcelenergy.com

Christopher Irby, #35778 Assistant General Counsel Xcel Energy Services Inc. 1800 Larimer, Suite 1100 Denver, Colorado 80202-5533 Tel: 303-294-2504 Fax: 303-294-2988 Email: christopher.m.irby@xcelenergy.com Caitlin M. Shields, #41539 Wilkinson Barker Knauer, LLP 1755 Blake Street, Suite 470 Denver, Colorado 80202 Tel: (303) 626-2338 Email: cshields@wbklaw.com

33. Agreement to Comply with 4 CCR 723-3-3002(b)(lV) through (VI).

Public Service has read, and agrees to abide by, the provisions of subparagraphs

(b)(IV) through (VI) of Rule 3002.

34. Description of Existing Operations and General Colorado Service Area.

Public Service's existing operations and general service areas in Colorado are set

forth in the Company's tariffs on file with the Commission.

35. Location of Hearing. Public Service requests that this Application be

granted without hearing. However, if a hearing is held, Public Service requests that

it be held at the Commission’s offices in Denver, Colorado.

36. Acknowledgement. Public Service acknowledges that the Company

has read and agrees to abide by the provisions of 4 CCR 723-3-3002(b)(XI)(A)

through (C).

37. Statement Under Oath. Thomas Green, Consulting Engineer states

under penalty of perjury that the contents of this Application are true, accurate, and

correct to the best of his knowledge. His affidavit is attached to this Application.

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38. Information Required by Rule 3002(b)(IX) and (c). Pursuant to 3002(c)

of the Commission's Electric Rules, Public Service hereby incorporates by reference

the following information, which is on file with the Commission in Proceeding No.

06M-525EG:

a. A copy of Public Service's Amended Articles of Incorporation, which was

last filed on October 3, 2006;

b. The name, business address and title of each of Public Service's officers

and directors, which was last filed on March 28, 2019;

c. The names and addresses of affiliated companies that conduct business

with Public Service, which was last filed on March 28, 2019;

d. The name and address of Public Service's agent for service of process,

which was last filed on March 28, 2019; and

e. A copy of Public Service's most recent audited balance sheet, income

statement, and statement of retained earnings, and statement of cash

flows, which were last filed on March 28, 2019.

V. CONCLUSION

Wherefore, Public Service Company of Colorado respectfully requests that

the Commission grant this Application and (1) issue a CPCN for the Greenwood to

Denver Terminal 230 kV Transmission Project and three transmission line uprate

projects, (2) grant a presumption of prudence finding for the associated costs as

identified herein, and (3) find that the associated noise and magnetic field levels that

the Company estimates will result from operating the Project are reasonable by rule

and require no further mitigation.

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Dated this 21st day of February 2020.

Respectfully submitted,

By: /s/ Christopher Irby Christopher Irby, #35778 Assistant General Counsel Xcel Energy Services, Inc. 1800 Larimer Street, Suite 1100 Denver, Colorado 80202 Telephone: (303) 294-2504 Fax: (303) 294-2988 Email: christopher.m.irby@xcelenergy.com

and

Caitlin M. Shields, #41539 Wilkinson Barker Knauer LLP 1755 Blake Street, Suite 470 Denver, Colorado 80202 Telephone: (303) 626-2350 Fax: (303) 626-2351 Email: cshields@wbklaw.com ATTORNEYS FOR PUBLIC SERVICE COMPANY OF COLORADO