Board of Directors Regular Meeting 2000 E. Horsetooth Rd, Fort … · 2016-08-04 · 2016 BKD Audit Report . Director Bergsten moved to accept the 201BKD Audit Report as presented

Board of Directors Regular Meeting 2000 E. Horsetooth Rd, Fort Collins, CO 80525

Thursday, April 27, 2017, 9:00 a.m. Call to Order

1) Consent Agenda Motion to Approve a. Minutes of the Regular Meeting of March 30, 2017

Public Comment Board Action Items

2) Revision to TARIFF—SCHEDULE 4: Resolution 05-17 Wholesale Transmission Service

3) Acceptance of 2016 Annual Report Motion to Accept

Management Presentations

4) HQ Campus 5) Demand Response update

Management Reports

6) Board Governance Process Document 7) Additional Wind Opportunity 8) Work Session Follow-up

Monthly Informational Reports

9) Legal & Governmental Affairs Report 10) March 2017 Operating Report 11) March 2017 Financial Report 12) General Management Report

Strategic Discussions Adjournment

Page 1

Page 2

Updated April 18, 2017

2017 BOARD MEETING PLANNING CALENDAR

May 25, 2017 Board Action Items


Management Reports

Monthly Informational

Reports Retirement Committee Meeting

Windy Gap Firming Project Funding: Second Amendment to the Fifth Interim Agreement

Synopsis of State Legislation of Interest

Board Governance Draft

Legal & Governmental Affairs Report

HQ Campus April 2017 Operating Report

System Community Solar Program – Program Decision

April 2017 Financial Report

Additional Wind Analysis

General Management Report

June 16-21 APPA National Conference; Orlando, FL

July 27, 2017 Board Action

Items Management Presentations

Management Reports


Reports Retirement

Committee Report

Mountain West Transmission Group

Wholesale Rate Strategic Discussion


IGA for joint compensation study

HQ campus Cyber security update

May and June 2017 Operating Report

Wind PPA Approval

Energy Efficiency Program

May and June 2017 Financial Report

Board Governance Draft


Windy Gap Storage Acquisition and Unit Sales

Page 3


August 31, 2017

Board Action Items


Management Reports


Reports Retirement Committee Meeting

Wholesale Rate Forecast

Demand Response Pilot


HQ Campus – design development milestone

July 2017 Operating Report

Energy Efficiency Programs Update

July 2017 Financial Report

Cyber security update


September 28, 2017

Board Action Items


Management Reports


Reports Retirement

Committee Report

2018 Proposed Annual Budget Work Session

2018 Draft Strategic Plan


Demand Response Pilot Update

Debt Financing August 2017 Operating Report

HQ Campus

Rawhide Rail Contract

August 2017 Financial Report

Clean Power Plan General Management Report

Page 4


October 26, 2017

Board Action Items


Management Reports


Reports 2017 BKD Audit

Plan Rawhide Rail Contract


Debt Financing Update

September 2017 Operating Report

2018 Proposed Rate Tariff(s)

September 2017 Financial Report

2018 Proposed Annual Budget (public hearing)


November, 2017

Retirement Committee Meeting

No Board of Directors Meeting

December 7, 2017

Board Action Items


Management Reports


Reports Retirement

Committee Report HQ Campus Legal &

Governmental Affairs Report

2018 Annual Budget Review and Adoption

2018 Annual Budget Review and Adoption

October 2017 Operating Report

2018 Strategic Plan (Approval)

October 2017 Financial Report

2018 Proposed Board of Directors Regular Meeting Schedule


Page 5

Page 6

2017 Board of Directors

Term Expiration

Town of Estes Park P.O. Box 1200, Estes Park, Colorado 80517

Mayor Todd Jirsa April 2020 Reuben Bergsten—Vice Chairman, Board of Directors December 2019

City of Fort Collins P.O. Box 580, Fort Collins, Colorado 80522

Mayor Wade Troxell April 2019 Mayor Pro Tem Gerry Horak December 2020

City of Longmont 350 Kimbark Street, Longmont, Colorado 80501

Mayor Dennis Coombs November 2017 Tom Roiniotis—Chairman, Board of Directors December 2018

City of Loveland 500 East Third Street, Suite 330, Loveland, Colorado 80537

Mayor Cecil Gutierrez—Secretary, Board of Directors November 2017 Steve Adams December 2017

Page 7

Page 8

2000 East Horsetooth Road • Fort Collins, Colorado 80525-5721 970-226-4000 • www.prpa.org

Vision, Mission, and Values Vision: As a respected leader and responsible energy partner, improve the quality of life for the citizens served by our owner communities. Mission: Provide safe, reliable, environmentally responsible, and competitively priced energy and services. Values: • Safety – Working safely and protecting the public, our employees, and the assets

we manage is non-negotiable.

• Integrity – Being ethical and holding ourselves accountable to conduct business in a fair, honest, open, compliant, and environmentally responsible manner is at the core of what we do.

• Customer Service – Providing quality service at a competitive price while being responsive to our owners’ needs creates added value and improves customer satisfaction.

• Respect – Encouraging constructive dialogue that promotes a culture of inclusiveness, recognizes our differences, and accepts varying viewpoints will lead us to optimal solutions for even the most difficult challenges.

• Operational Excellence – Engaging employees to strive for excellence and continuous improvement ensures that we provide reliable service while managing costs and creating a rewarding work environment.

• Innovation – Supporting the development of technologies to promote the efficient use of electricity, protect the environment, and create a diversified energy supply portfolio mitigates risk and creates opportunities.

• Sustainability – Maintaining financial integrity, minimizing our environmental impact, and supporting responsible economic development in our owner communities ensures the long-term viability of the organization and the communities we serve.

Page 9

Page 10

Regular Meeting Minutes of the Board of Directors 2000 E. Horsetooth Road, Fort Collins, CO 80525

Thursday, March 30, 2017 ATTENDANCE Board Members Representing Estes Park: Mayor Todd Jirsa and Reuben Bergsten Representing Fort Collins: Mayor Wade Troxell and Mayor Pro Tem Gerry Horak1 Representing Longmont: Mayor Dennis Coombs and Tom Roiniotis Representing Loveland: Mayor Cecil Gutierrez and Steve Adams Platte River Staff Jason Frisbie (General Manager/CEO) Joe Wilson (General Counsel) Dave Smalley (Deputy GM and Chief Financial Officer) Karin Hollohan (Chief Administrative Services Officer) Andy Butcher (Chief Operating Officer) John Bleem (Chief Communications and Marketing Officer-Interim) Angela Walsh (Executive Assistant) Shelley Nywall (Controller) Brad Decker (Strategic Planning Manager) Paul Davis (Customer Services Manager) Wade Hancock (Financial Planning Manager) Nancy James (Executive Administrative Assistant) Guests Tim McCollough (Fort Collins Utilities) Jodie Cates (BKD) Anna Thigpen (BKD) CALL TO ORDER Chairman Roiniotis called the meeting to order at 9:00 a.m. A quorum of Board members was present and the meeting, having been duly convened, was ready to proceed with business. ACTION ITEMS (1) Consent Agenda

a. Approval of the Regular Meeting Minutes of February 23, 2017

Director Jirsa moved to approve the Consent Agenda as presented. Director Coombs seconded, and the motion carried 7-0. 1 Arrived at 9:01am

Page 11

Regular Board Meeting Minutes: March 30, 2017

Page 2 of 6

(2) Retirement Committee Report (presenter: Steve Adams) Director Adams reported the Retirement Committee met on Thursday, February 23. The draft minutes for the meeting are provided in the Board packet starting on page 19. PUBLIC COMMENT None. (3) 2016 BKD Audits (presenter: Dave Smalley, Jodie Cates, Anna Thigpen) Dave Smalley, deputy GM and chief financial officer, introduced Jodie Cates and Anna Thigpen from BKD to provide an overview of the Financial Audit Report. Ms. Thigpen also highlighted items within the Post-Audit Letter to the Board. Both the report and the letter were provided to the Board as a separate handout and within the Board packet. A Director asked for clarification on the fly ash impoundments liability. Ms. Cates responded the impoundments are addressed under a different set of standards until implementation of new GASB standards.

a. 2016 BKD Audit Report

Director Bergsten moved to accept the 2016 BKD Audit Report as presented. Director Troxell seconded, and the motion carried 8-0.

b. 2016 Defined Benefit Plan Audit Engagement Letter

Director Coombs moved to approve the execution of the 2016 Defined Benefits Plan Audit Engagement Letter as presented. Director Bergsten seconded, and the motion carried 8-0.

(4) Dual Reporting - General Counsel (presenter: Joe Wilson)

Joe Wilson, general counsel, presented the explanatory memo highlighting the internal reorganization that widens the general counsel role to report to the general manager for compliance and governmental affairs. Mr. Wilson would continue to report to the Board on all legal matters. Director Adams moved to approve Resolution 03-17 setting out the responsibilities and reporting relationship of the General Counsel as presented. Director Coombs seconded, and the motion carried 8-0.

(5) Energy Efficiency Funding Policy (presenter: Paul Davis) Paul Davis, customer services manager, provided a summary of the Energy Efficiency Funding Policy presented at the February Board meeting. The February presentation focused on the policy that directs the general manager to in turn direct staff to develop guidelines aimed at creating an energy efficiency budget, setting cost effective goals, picking programs to achieve those goals, and evaluating each program. A Director complimented staff on bringing the program together for all four municipalities and providing benefits from the distribution level to end users. Director Jirsa moved to approve Resolution 04-17; the Energy Efficiency Funding Policy as presented. Director Bergsten seconded, and the motion carried 8-0.

Page 12


Page 3 of 6

Annual Review for General Manager/General Counsel (presenter: Jason Frisbie) (6) Executive Session – Personnel Matter

Director Bergsten moved that the Board go into executive session for the purposes of considering personnel matters related to the annual review of the performance of the general manager and the general counsel. The general counsel advised that an executive session is authorized in this instance pursuant to Colorado Revised Statutes, Section 24-6-402, subsection (4)(f); provided that, no formal action will be taken during the executive session. Director Jirsa seconded, and the motion carried 8-0. (7) Reconvene Regular Session The Chairman reconvened the Regular Board Meeting stating that the Board is very pleased with the performance of the general manager and the general counsel, and that the Board provided them appropriate feedback during the executive session. Director Gutierrez made a motion to give a three percent lump-sum bonus payment to the general counsel. Director Bergsten seconded. Motion carried 8-0. The Chairman explained to Mr. Frisbie that the entire Board was pleased with his performance, however, in light of an evaluation timeframe of only five months the Board has decided to address compensation at the next annual review. The Chairman assured Mr. Frisbie that the Board will take into consideration the seventeen-month timeframe between salary adjustments. MANAGEMENT PRESENTATIONS (8) HQ Campus (presenter: Karin Hollohan) Karin Hollohan, chief administrative services officer, provided a quick update on the current status of the project timeline, updated site plan, a reflection on public spaces and next steps for the HQ Campus project. Ms. Hollohan mentioned the project is on schedule through the design phase and staff expects to complete the schematic design phase by the end of April/beginning of May. The Board will preview the schematic design at the May Board meeting prior to moving into the design development phase. The Board will then see the design development phase in August prior to moving into the construction phase. Ms. Hollohan thanked the Board for their input regarding the Board room, training rooms, public and community spaces, and fitness space. Ms. Hollohan invited the Board to continue to provide further recommendations for the project. Ms. Hollohan noted that the materials represented in the current renderings are not the materials chosen, only those to illustrate the campus design at this time. Key takeaways from the presentation are that staff has finalized the site diagram, the layout of the buildings, the road configurations and access to the site, and work will continue to finalize the interior organization of the floor plan. The design team has begun looking at the building systems that will be included in the design development stage. An updated cost model will be provided to the Board in May when staff presents the updated schematic design with further cost updates provided in August. No Board approval was requested at this meeting.

Page 13


Page 4 of 6

Mayor Troxell extended his appreciation for allowing him to be involved with feedback. (9) System Community Solar Program Overview (presenter: Paul Davis) Paul Davis provided an overview of a four-community solar program including: municipal staff involvement status, a review of what staff has learned about community solar and what customer motivations and expectations are, a review of solar economics on Platte River’s system as well as effects on the wholesale system, and next steps. Mr. Davis also provided comparisons of solar cost vs. wholesale system value along with premiums for different sizes of facilities. A Director commented about peaking costs in energy and capacity, and that distributed energy resources might be used to improve the alignment between electric loads and available solar generation. Mr. Davis indicated that future presentations may address distributed energy resources like demand response. (More information on this topic is also provided in the follow-up items section of the April Board packet.) Discussion ensued regarding 100 percent renewable interest by large commercial customers, possible solutions and collaboration within the Platte River owner municipalities. Next steps on community solar include possibly working with Rocky Mountain Institute (RMI) who could provide assistance during the RFP process. Staff is working through the scope, schedule and process with RMI. A Director asked how much real estate is open at Rawhide Energy Station to add more solar. Staff responded that there’s plenty of land but the quality of land and how much to commit to solar is yet to be determined. The survey results should provide direction on desired location of community solar; whether it’s at Rawhide or distributed throughout the municipalities. A Director complimented staff for being subject matter experts and providing support and guidance to the city staffs. MANAGEMENT REPORTS (10) Rate Tariff Reference Document (presenter: Dave Smalley) Dave Smalley introduced the rate tariff reference document. Efforts on developing this document began in December of 2016 with a memorandum to the Board on rate policy and rate development. Mr. Smalley mentioned that a discussion on rates is scheduled for the Board work session following the Board meeting. The Board complimented staff for the document and appreciates having a reference document. A Director suggested adding a triple bottom line to understand the environmental and social impact costs to consider in future decisions. The Director also commented on the Tariff Schedule 8 service and distributed resources used as spinning reserves. Discussion among staff and Directors regarding the usage of spinning reserves ensued. MONTHLY INFORMATIONAL REPORTS (11) Legal & Governmental Affairs Report (presenter: Joe Wilson) Board Chairman Roiniotis asked the Board if there were any questions or comments regarding the February legal and governmental affairs report contained in the Board materials. Joe Wilson informed the Board that he would send out a brief update on the current status of the President’s Executive Order regarding the effort to rescind the Clean Power Plan through a new notice and comment process and the direction to request a stay on all pending litigation.

Page 14


Page 5 of 6

(12) February Operating Report

Board Chairman Roiniotis asked the Board if there were any questions or comments regarding the February operating report contained in the Board materials. No questions or comments were raised. (13) February Financial Report Board Chairman Roiniotis asked the Board if there were any questions or comments regarding the February financial report contained in the Board materials. No questions or comments were raised. (14) General Management Report (presenter: Jason Frisbie) Jason Frisbie, general manager/CEO, pointed out a couple of highlights from the management report. Mr. Frisbie complimented the Platte River Emergency Response Team (ERT) for their quick response and hard work on the Cattleman’s Fire that occurred on Saturday, March 4 near Rawhide. No Platte River structures were in danger. Platte River’s mutual aid partners were also involved in extinguishing the fire. Mr. Frisbie continued with highlights, noting that the 2016 Annual Report will be presented to the Board at the April meeting and staff will request acceptance of the report at that time. Platte River was offered an opportunity to team up with the Cities of Loveland and Fort Collins, as well as CSU, CU and the School of Mines to work together through Innosphere to apply for a $10,000 grant. More information is on page 178 of the Board packet. A Director inquired about further discussion offline on the Management Report item regarding the demand response piloting and real time information. The Director had further questions regarding the Mountain West Transmission Group (MWTG) section of the Management Report and asked if capacity markets were being considered to be a part of the market infrastructure, and if not, why not. Staff responded that the capacity markets are addressed in a confidential document and was a topic of discussion with the PUC. Staff will provide an informational, high level response to the Board regarding the consideration of capacity markets and the MWTG.

Roundtable and Strategic Discussion Topics The Board Chairman suggested skipping the roundtable and strategic discussions due to the Board work session scheduled to follow the meeting.

Page 15


Page 6 of 6

ADJOURNMENT With no further business, the meeting adjourned at 12:24 p.m. The next regular Board meeting is scheduled for Thursday, April 27, at 9:00 a.m. in the Platte River Power Authority Board Room, 2000 East Horsetooth Road, Fort Collins, Colorado.

AS WITNESS, I have executed my name as Assistant Secretary and have affixed the corporate seal of the Platte River Power Authority this day of , 2017.

Assistant Secretary

Page 16

Memorandum Date: April 19, 2017

To: Board of Directors

From: Jason Frisbie, General Manager/CEO Dave Smalley, Deputy General Manager and Chief Financial Officer Wade Hancock, Financial Planning Manager

Subject: Revision to Tariff—Schedule 4: Wholesale Transmission Service The Board of Directors is required by the AMENDED CONTRACTS FOR THE SUPPLY OF ELECTRIC POWER AND ENERGY (AMENDED CONTRACTS) between Platte River Power Authority (Platte River) and the Municipalities to review the rates for electric power and energy furnished thereunder at such intervals as it deems appropriate, but no less frequently than once each year. It has been the routine practice to review and modify Tariff—Schedule 4, the tariff under which Platte River offers transmission service to third parties, on an annual basis at the April Board meeting after the audited year-end financial results are available. This ensures that the rate reflects the most recent costs of operation and actual transmission usage.

The Tariff—Schedule 4 transmission rates are charged to other utilities (such as Xcel Energy and Tri-State) that use Platte River’s transmission system. Tariff—Schedule 4 is also charged to Platte River for merchant sales. The transmission rates are calculated using a methodology that the Federal Energy Regulatory Commission has prescribed for this purpose. The following proposed rates were calculated using the 2016 year-end financial and operational information.

The proposed Tariff—Schedule 4 Real Power Loss factor is changing from 1.82 percent to 1.78 percent.

The proposed Tariff—Schedule 4 charge for Reactive Supply and Voltage Control from Generation Sources Service is decreasing 6.4 percent from $46.50 to $43.51 per megawatt of Reserved Capacity per month. The rate decrease is the result of lower net Production Plant in Service and a lower rate of return due to a 0.2 percent decrease in transmission usage and a 5.0 percent decrease in the calculated cost recovery for reactive power and voltage control. Platte River charges this rate to network transmission customers.

The proposed Tariff—Schedule 4 charges for Long-Term and Short-Term Firm Point-to-Point Transmission Service and Non-Firm Point-to-Point Transmission Service are decreasing 0.1 percent from $5,680.29 to $5,675.69 per megawatt of Reserved Capacity per month.

The decrease is the result of a 0.9 percent increase in the transmission revenue requirement slightly more than offset by a 0.9 percent increase in transmission usage. Under Tariff—Schedule 4, Platte River continues to reserve the right to offer discounted transmission rates for specific transmission paths.

Page 17

MEMO – Revisions to TARIFF – SCHEDULE 4:

Wholesale Transmission Service April 2017 Page 2 of 2

If approved, this revised rate tariff will become effective on May 1, 2017.

Attached to this memorandum is a copy of the proposed tariff and resolution that authorizes amendment of the wholesale transmission service tariff.

Attachment

Page 18

Tariff—Schedule 4: Adopted: Wholesale Transmission Service Page 1 of 2 Effective:

TARIFF—SCHEDULE 4: WHOLESALE TRANSMISSION SERVICE Platte River Power Authority (Platte River) offers open access transmission service through this Open Access Transmission Tariff (OATT). The complete OATT is posted on Platte River’s Open Access Same-Time Information System (OASIS) web site. Any Eligible Customer (as defined in the OAT Tariff) may request transmission service from Platte River under the terms of the OAT Tariff. This OAT Tariff does not apply to any entity taking bundled service under Platte River’s TARIFF—SCHEDULE 1: FIRM RESALE POWER SERVICE; TARIFF—SCHEDULE 8: STANDBY SERVICE; OR TARIFF—SCHEDULE 9: LARGE USER SERVICE. In accordance with the OAT Tariff, Platte River reserves the right to offer a discounted transmission rate for transmission service posted on the OASIS for specific transmission paths. A summary of the charges within the OATT Schedules follows. The Real Power Loss factor is 1.78%. (1) Scheduling, System Control, and Dispatch Service

No charge in addition to that for Transmission Service (Items 7 and 8 below). (2) Reactive Supply and Voltage Control from Generation Sources Service

$43.51 per megawatt (MW) of Reserved Capacity per month. (3) Regulation and Frequency Response Service

Platte River is not a balancing authority and does not offer this service. Upon written request, Platte River will assist in arranging for the local balancing authority operator to provide this service; however, Platte River makes no representation that the local balancing authority operator can or will provide the service. (4) Energy Imbalance Service

Platte River is not a balancing authority and does not offer this service. Upon written request, Platte River will assist in arranging for the local balancing authority operator to provide this service; however, Platte River makes no representation that the local balancing authority operator can or will provide the service. (5) Operating Reserve—Spinning Reserve Service

Platte River is not a balancing authority and does not offer this service. Upon written request, Platte River will assist in arranging for the local balancing authority operator to provide this service; however, Platte River makes no representation that the local balancing authority operator can or will provide the service. (6) Operating Reserve—Supplemental Reserve Service

Platte River is not a balancing authority and does not offer this service. Upon written request, Platte River will assist in arranging for the local balancing authority operator to provide this service; however, Platte River makes no representation that the local balancing authority operator can or will provide the service.

Page 19


(7) Long-Term and Short-Term Firm Point-to-Point Transmission Service

The charges can be up to the following limits:

Yearly Delivery $68,108.29 per MW of Reserved Capacity per year Monthly Delivery $5,675.69 per MW of Reserved Capacity per month Weekly Delivery $1,309.77 per MW of Reserved Capacity per week Daily Delivery $261.95 per MW of Reserved Capacity per day Hourly Delivery $16.37 per MW of Reserved Capacity per hour

(8) Non-Firm Point-to-Point Transmission Service


Monthly Delivery $5,675.69 per MW of Reserved Capacity per month Weekly Delivery $1,309.77 per MW of Reserved Capacity per week Daily Delivery $261.95 per MW of Reserved Capacity per day Hourly Delivery $16.37 per MW of Reserved Capacity per hour

Transmission Revenue Requirement

The charge for Network Integration Transmission Service is calculated pursuant to the Federal Energy Regulatory Commission (FERC) Pro Forma Open Access Transmission Tariff Attachment H based on Platte River’s annual transmission revenue requirement of $37,060,620. This transmission revenue requirement is calculated in accordance with the FERC pro-forma Network Service Rate calculation requirement. Joint Dispatch Transmission Service

Joint Dispatch Transmission Service is applicable only to load serving entities in the PSCo Balancing Authority Area that are signatories to a Joint Dispatch Agreement (JDA) under which: (1) participating generating resources of the parties are dispatched as a pool on a least-cost basis respecting transmission limitations; and (2) the Joint Dispatch Transmission Service Customers’ respective transmission service providers have provided within their OATT a transmission service schedule for energy dispatched pursuant to the JDA at a rate equal to zero dollars on a non-firm, as-available basis with the lowest curtailment priority.

Hourly delivery: $0.00 per MW of Reserved Capacity per hour

Page 20


TARIFF—SCHEDULE 4: WHOLESALE TRANSMISSION SERVICE Platte River Power Authority (Platte River) offers open access transmission service through this Open Access Transmission Tariff (OATT). The complete OATT is posted on Platte River’s Open Access Same-Time Information System (OASIS) web site. Any Eligible Customer (as defined in the OAT Tariff) may request transmission service from Platte River under the terms of the OAT Tariff. This OAT Tariff does not apply to any entity taking bundled service under Platte River’s TARIFF—SCHEDULE 1: FIRM RESALE POWER SERVICE; TARIFF—SCHEDULE 8: STANDBY SERVICE; OR TARIFF—SCHEDULE 9: LARGE USER SERVICE. In accordance with the OAT Tariff, Platte River reserves the right to offer a discounted transmission rate for transmission service posted on the OASIS for specific transmission paths. A summary of the charges within the OATT Schedules follows. The Real Power Loss factor is 1.821.78%. (1) Scheduling, System Control, and Dispatch Service

No charge in addition to that for Transmission Service (Items 7 and 8 below). (2) Reactive Supply and Voltage Control from Generation Sources Service

$46.50 $43.51 per megawatt (MW) of Reserved Capacity per month. (3) Regulation and Frequency Response Service

Platte River is not a balancing authority and does not offer this service. Upon written request, Platte River will assist in arranging for the local balancing authority operator to provide this service; however, Platte River makes no representation that the local balancing authority operator can or will provide the service. (4) Energy Imbalance Service

Platte River is not a balancing authority and does not offer this service. Upon written request, Platte River will assist in arranging for the local balancing authority operator to provide this service; however, Platte River makes no representation that the local balancing authority operator can or will provide the service. (5) Operating Reserve—Spinning Reserve Service

Platte River is not a balancing authority and does not offer this service. Upon written request, Platte River will assist in arranging for the local balancing authority operator to provide this service; however, Platte River makes no representation that the local balancing authority operator can or will provide the service. (6) Operating Reserve—Supplemental Reserve Service

Platte River is not a balancing authority and does not offer this service. Upon written request, Platte River will assist in arranging for the local balancing authority operator to provide this service; however, Platte River makes no representation that the local balancing authority operator can or will provide the service.

Page 21


(7) Long-Term and Short-Term Firm Point-to-Point Transmission Service




(8) Non-Firm Point-to-Point Transmission Service

The charges can be up to the following limits: Monthly Delivery $5,675.69 per MW of Reserved Capacity per month Weekly Delivery $1,309.77 per MW of Reserved Capacity per week Daily Delivery $261.95 per MW of Reserved Capacity per day Hourly Delivery $16.37 per MW of Reserved Capacity per hour Monthly Delivery $5,680.29 per MW of Reserved Capacity per month Weekly Delivery $1,310.84 per MW of Reserved Capacity per week Daily Delivery $262.17 per MW of Reserved Capacity per day Hourly Delivery $16.39 per MW of Reserved Capacity per hour

Transmission Revenue Requirement

The charge for Network Integration Transmission Service is calculated pursuant to the Federal Energy Regulatory Commission (FERC) Pro Forma Open Access Transmission Tariff Attachment H based on Platte River’s annual transmission revenue requirement of $36,745,518$37,060,620. This transmission revenue requirement is calculated in accordance with the FERC pro-forma Network Service Rate calculation requirement. Joint Dispatch Transmission Service

Joint Dispatch Transmission Service is applicable only to load serving entities in the PSCo Balancing Authority Area that are signatories to a Joint Dispatch Agreement (JDA) under which: (1) participating generating resources of the parties are dispatched as a pool on a least-cost basis respecting transmission limitations; and (2) the Joint Dispatch Transmission Service Customers’ respective transmission service providers have provided within their OATT a transmission service schedule for energy dispatched pursuant to the JDA at a rate equal to zero dollars on a non-firm, as-available basis with the lowest curtailment priority.

Hourly delivery: $0.00 per MW of Reserved Capacity per hour

Page 22

Resolution No. __-17: TARIFF—SCHEDULE 4: WHOLESALE TRANSMISSION SERVICE Page 1 of 1

RESOLUTION NO. __-17

WHEREAS, Platte River Power Authority sets forth the terms and conditions for

transmission service through “TARIFF—SCHEDULE 4: WHOLESALE TRANSMISSION

SERVICE”; and

WHEREAS, because the wholesale transmission tariff offering is not associated with a

service taken by the Owner Municipalities, typically Tariff—Schedule 4 is not revised when the

Board conducts its annual review of the remaining tariffs, rather Platte River reviews the

transmission tariff offering annually during April using audited financial results for the prior year;

and

WHEREAS, Platte River’s staff recommends in a memorandum dated April 19, 2017,

that an amended “TARIFF—SCHEDULE 4: WHOLESALE TRANSMISSION SERVICE” be

adopted to reflect audited and updated year-end financial results and operational, maintenance,

and investment cost information.

NOW, THEREFORE, BE IT RESOLVED by the Board of Directors of the Platte River

Power Authority that an amended “TARIFF—SCHEDULE 4: WHOLESALE TRANSMISSION

SERVICE,” in substantially the form attached hereto is adopted to become effective as of May

1, 2017.

AS WITNESS, I have executed my name as Assistant Secretary and have affixed the corporate seal of the Platte River Power Authority this day of , 2017. Assistant Secretary

Page 23

Page 24



From: Jason Frisbie, General Manager/CEO John Bleem, Chief Communications and Marketing Officer – Interim Kari Lynch, Communications and Marketing Specialist

Subject: Acceptance of 2016 Annual Report The 2016 Annual Report will be presented at the April 27 Board meeting. A PDF version of the report is included in this Board packet and a bound copy of the document will be provided at the meeting. We will also produce a digital version of the report, which will be available on our web site at a later date. The independent auditors report and financial statements (produced by BKD) will be included in the PDF and bound versions. These will also be available as a link in the digital (web) version. The Board will be asked to accept the 2016 Annual Report at the Board meeting.

Page 25

Page 26

Powering Our Sustainable FUTURE

Annual Report 2016

Page 27

2 Annual Report 2016

Page 28

Table of Contents

Chairman and General Manager’s Letter

About Platte River

Vision, Mission, and Values

Our Communities

Board of Directors and Senior Management

Financial Results

Report of Management

Independent Auditor’s Report and Financial Statements

Resources and Planning

Water Policy

Rawhide Flats Solar

Platte River Completes Sale of Series JJ Bonds

Employee Engagement

Laporte Substation Expansion

Headquarters Campus Project

4

6

7

8

9

10

14

16

17

18

19

20

21

22

24

News

3Annual Report 2016

Page 29

From the Chairman of the Board and General Manager

The future of Platte River looks bright as we continue to build on a strong foundation of operational, financial, and environmental excellence. Sustaining our success will require enhanced collaboration with the municipalities we serve so that Platte River continues to be the foundation upon which these communities can build their energy and innovation future.

Since its inception, Platte River has provided a reliable and low-cost supply of electricity to its owners. In the past, a simple strategy accomplished this result. Projecting municipal load growth, Platte River constructed generation facilities with capacity to meet future loads and leveraged the output of these facilities in the wholesale market until the municipal loads developed. The future will require a wider range of strategies. Opportunities and challenges include diverse community values, reduced surplus sales prices, substantial shifts in natural gas availability and pricing, lower costs for renewable resources, technological advancements, regulatory uncertainty, and changes in western regional markets.

Our 2016 successes reflect the expertise and commitment of our dedicated employees. Platte River leadership actively encourages employee development and training. Employee engagement is crucial in transforming our plans into reality. We thank them for what they do every day.

Platte River has taken positive steps to address challenges and leverage opportunities. During the past decade we have diversified our resource portfolio to include natural gas-fired combustion turbines, wind deliveries from multiple sites,

and a new 30 MW solar facility. Coal generation and federal hydropower purchases round out the supply side of the current resource mix and provide essential baseload capacity. As new resources are added, we are also implementing a strategy to reduce supply from coal generation at the Craig Station. For 2016, carbon-free resources provided over 30 percent of the average electrical energy supply to the member municipalities. Our new renewable energy supply (wind and solar) has more than tripled since 2013.

Other highlights in the area of resource management include approval of Platte River’s first-ever comprehensive water policy, submission of our 2016 Integrated Resource Plan, approval of the Joint Dispatch Agreement by FERC, and expansion of the Laporte Substation, which will enhance resiliency of our transmission system.

Platte River’s financial position remained solid in 2016. All strategic financial plan targets were exceeded and net income came in just over $18 million. Our AA rating was confirmed and we issued $147 million in Series JJ Bonds to fund production and transmission capital projects and to refund a portion of outstanding debt. The refunding provided net present value savings of $13.7 million. We continue engaging our teams in continuous improvement for work planning and budgeting by better aligning scope, schedules, and available resources.

Platte River is among a group of seven regional utilities exploring potential participation with an existing regional transmission organization (RTO). Participation in a regional market may provide operational efficiencies through economies of


Page 30

Jason Frisbie Named New General Manager /CEO

scale and increased opportunities to bring more resources into our system, particularly wind and solar.

As we look to the future, “sustainability” is the brass ring that the electric industry is striving to grasp, but that term is often left to the eye of the beholder. Speaking as the leadership of Platte River, we consider the vital attributes of sustainability for our organization to be:

Resilience – our infrastructure, our human capital and the bonds we share with our owner municipalities must be capable of absorbing unexpected events;

Viability – our business model and financial position must continue to provide value to our owners;

Reliability – more than ever, electricity is an indispensable component of our everyday lives, and we must strive to make it available continuously.

These attributes demonstrate the soundness of the strategy to diversify our resource portfolio. A diverse mix of resources —both on the supply and demand side—answers a need associated with each of the attributes.

Activities planned for 2017 support the sustainability of the organization. A key aspect of maintaining a viable business model for our organization is responsiveness to evolving needs of each individual community—with an eye towards managing system cost and risk. Work continues to evaluate customized resource options for the owner municipalities, with focus on modeling system level resource additions (particularly increased renewable and integration sources). Board direction and collaboration with the municipalities’ staff continue to guide this important effort.

Platte River Power Authority remains a customer-focused, sustainable and innovative energy provider for our owner communities of Estes Park, Fort Collins, Longmont, and Loveland. We are committed to powering our sustainable future.

Our team is pleased to present Platte River’s 2016 Annual Report.

Sincerely,

Jason Frisbie Tom Roiniotis

Platte River Power Authority’s Board of Directors hired Jason Frisbie on August 6, 2016 as Platte River’s sixth General Manager. Mr. Frisbie has been with Platte River since 1982, serving in multiple roles related to power production, and was selected as Plant Manager for Rawhide Energy Station in 1999. In 2003 he became Division Manager of Power Production, with responsibility for all production and fuel management. Jason was named COO in 2010, overseeing all operations functions at Platte River.

5Annual Report 2016

Page 31

About Platte River

Platte River delivers safe, reliable, environmentally responsible, and competitively priced energy and services to its owner municipalities of Estes Park, Fort Collins, Longmont, and Loveland, Colorado for their utility customers.

Employees (Dec. 31, 2016):245

Headquarters:Fort Collins, Colorado

Began Operations:1973

Historical Peak Municipal Demand:659 MW on June 21, 2016

Governance:Platte River is governed by an eight-member board of directors comprised of each mayor and a person appointed by each municipality’s governing body.

Transmission System:Platte River has equipment in 26 substations, 258 miles of wholly owned and operated high-voltage lines, and 511 miles of high-voltage lines jointly owned with other utilities.

The Organization:Platte River is a political subdivision of the State of Colorado.


Page 32

Our Mission

Values

Our Vision

Provide safe, reliable, environmentally responsible, and competitively priced energy and services.

Customer ServiceWhat creates added value and improves customer satisfaction?

Providing quality service at a competitive price while being responsive to our owners’ needs.

SafetyWhat is non-negotiable?

Working safely to protect the public, our employees, and the assets we manage.

Operational ExcellenceHow do we provide reliable service while managing costs and creating a rewarding work environment?

By engaging employees to strive for excellence and continuous improvement.

RespectWhat leads us to optimal solutions for even the most difficult challenges?

Encouraging constructive dialogue that promotes a culture of inclusiveness, recognizes our differences, and accepts varying viewpoints.

IntegrityWhat is at the core of what we do?

Being ethical and holding ourselves accountable to conduct business in a fair, honest, open, compliant, and environmentally responsible manner.

InnovationHow do we mitigate risk and create opportunities?

By becoming an early adopter of technologies proven to improve electric efficiency, protect the environment, and create a diversified energy supply portfolio.

SustainabilityHow do we ensure long-term viability of the organization and the communities we serve?

By maintaining financial integrity, minimizing our environmental impact, and supporting responsible economic development in our owner communities.

As a respected leader and responsible energy partner, improve the quality of life for the citizens served by our owner communities.

7Annual Report 2016

Page 33

Our Communities Platte River Power Authority is a Colorado political subdivision established to provide wholesale electric generation and transmission to the municipal utilities of its owner communities – Estes Park, Fort Collins, Longmont, and Loveland.

Town of Estes ParkEstimated population*: 6,257

Utility: Estes Park Light & Power, established in 1945

City of LongmontEstimated population*: 93,933

Utility: Longmont Power & Communications, established in 1912

City of Fort CollinsEstimated population*: 161,000

Utility: Fort Collins Utilities, established in 1938

City of LovelandEstimated Population*: 74,427

Utility: Loveland Water and Power, established in 1925

8 Annual Report 2016 * Population data from U.S. Census and municipal staff

Page 34

9Annual Report 2016

Board of Directors

Senior Management Team

Platte River is governed by an eight-person board of directors uniquely designed to bring relevant expertise to the decision-making process. The board includes the mayor (or a designee of the mayor) from each of the owner municipalities. The other four directors are appointed to four-year staggered terms by the governing bodies of the owner municipalities.

Platte River operates under the direction of a general manager/CEO who serves at the pleasure of the board of directors. The general manager/CEO is the principal executive officer with full responsibility for planning, operations, and administrative affairs of Platte River. The senior management team also includes a deputy general manager/chief financial officer, a chief operating officer, a chief administrative services officer, a general counsel, a chief communications and marketing officer, and an executive administrative assistant to the general manager/CEO. Platte River’s senior management has substantial experience, with an average of 30 years of service in the utility industry.

Gerry HorakMayor Pro TemCity of Fort Collins

Cecil GutierrezMayorCity of Loveland

Dennis CoombsMayorCity of Longmont

Wade TroxellMayorCity of Fort Collins

Steve AdamsCity ManagerCity of Loveland

Reuben BergstenVice ChairmanDirector of UtilitiesTown of Estes Park

Pete HoelscherChief Communications & Marketing Officer

Joseph WilsonGeneral Counsel

Jason FrisbieGeneral Manager / Chief Executive Officer

Angela WalshExecutive Assistant to General Manager / Chief Executive Officer

Karin HollohanChief Administrative Services Officer

David SmalleyDeputy General Manager / Chief Financial Officer

Andy ButcherChief Operating Officer

Todd JirsaMayorTown of Estes Park

Tom RoiniotisChairman of the BoardGeneral Manager,Longmont Power & CommunicationsCity of Longmont

Page 35


Financial Results

Platte River’s financial position remains stable. Favorable results were reported in 2016. Net income of $18.0 million exceeded the budget and the strategic financial plan target. Revenues were lower primarily due to unfavorable surplus sales market conditions. However, lower revenues were offset by below-budget operating expenses and favorable financing expenses as a result of the 2016 debt financing. Debt service coverage – the ratio of total net revenues to debt payments and a source of confidence for holders of Platte River bonds – was 1.78 times, well above the 1.10 times required by bond covenants.

Financial Highlights

$ 199,433184,741(7,905)

$ 6,787

6393,201

713

$ 1,334,404$ 200,174

29 / 711.51x

Revenues / Expenses ($000) Operating Revenues Operating Expenses Nonoperating Revenues (Expenses), Net Income Before Contributions

Power Operations Demand-Municipalities (MW) Energy-Municipalities (GWh) Energy-Others

Selected Other Data Gross Utility Plant ($000) Long-Term Debt, Net ($000) Debt to Capitalization Ratio Total Revenue Bond Coverage

Year Ended December 31,2016 2015 2014

$ 205,293181,698(5,630)

$ 17,965

6593,216

722

$ 1,361,279$ 250,838

33 / 671.78x

$ 199,867174,985(8,276)

$ 16,606

6263,154

770

$ 1,304,828$ 223,552

31 / 691.71x

Page 36

11Annual Report 2016

Energy Market Statistics

Combined Retail Sales for Four Municipalities1

Number of Customers (average monthly) Residential Commercial & Industrial Other Total

Energy Sales (MWh) Residential Commercial & Industrial Other Total

Revenue ($000) Residential Commercial & Industrial Other Total

Residential Averages (annual) kWh per Customer Revenue per kWh (cents) Revenue per Customer

Wholesale Power Requirements

Peak Demand (kW) Estes Park Fort Collins Longmont Loveland Sum of Municipalities' Peaks

Demand - PRPA Coincident

Energy (MWh) Estes Park Fort Collins Longmont Loveland Sum of Municipalities' Energy

Sales to Others and Miscellaneous2

Energy-Total System

Year Ended December 31,2016 2015 2014

138,13417,682

290156,106

1,115,0151,995,654

12,1583,122,827

$ 110,313150,157

502$ 260,972

8,0729.89

$ 798.59

25,482306,659179,325163,228674,694

658,587

131,2751,541,509

812,037731,650

3,216,471

878,615

4,095,086

136,08818,097

292154,477

1,093,1461,988,855

12,5723,094,573

$ 106,191144,720

519$ 251,430

8,0339.71

$ 780.31

25,799292,093170,209160,904649,005

639,092

129,6341,516,550

801,097753,920

3,201,201

864,955

4,066,156

134,24217,617

290152,149

1,089,7631,962,804

12,3023,064,887

$ 103,299139,100

505$ 242,904

8,1189.48

$ 769.50

28,092281,610169,109157,857

636,668

625,517

129,3801,474,916

795,248754,733

3,154,277

879,949

4,034,226

1 Compiled from preliminary sales and other reports of the municipalities supplied with electric energy by Platte River.2 Includes energy imbalance and exchange agreement settlements.

Page 37


Energy Deliveries

Revenues, Expenses, and Income (In millions)

2014 2015 2016

To Municipalities To Others

Gig

awat

t-h

ou

rs (

GW

h)

4500

4000

3500

3000

2500

2000

1500

1000

500

0

3,154 3,201

770

3,924

713

3,914

3,216

722

3,938

Operating Expenses

2014 2015 2016

$200

$150

$100

$50

$0

Operating RevenuesNet Nonoperating Expenses

$ M

illi

on

s

$200 $199$205

Financial Results (continued)

Page 38


News

Page 39


Resources and Planning

Platte River Power Authority employs an adaptive strategy to cost-effectively maintain reliability, manage risks, and ensure regulatory compliance. During 2016, Platte River delivered its latest Integrated Resource Plan, initiated collaborative efforts to help satisfy individual resource needs of the owner municipalities, and began exploring potential participation in an existing Regional Transmission Organization. Platte River continues to evaluate future plans with an eye toward resource diversification.

One of the most significant events of 2016 involved the decision to decommission Craig Unit 1 by the end of 2025. This decision was jointly made by the five owners of the Yampa Project based on market conditions and regulatory uncertainty. During 2016, Platte River also participated in discussions with several other regional utilities to consider forming an organized wholesale power market, which could materialize in the next few years. Belonging to an organized market will also bring future operational and planning challenges for Platte River’s system, and these changes are being contemplated in current modeling efforts.

Page 40


Shown below is the Action Plan from the 2016 IRP, which helps shape near-term resource decisions for Platte River.

Prepare for business structures, products, and programs preferred by our owner municipalities

• Work with owner municipalities to develop customized future supply portfolios

• Continue expansion of cost-effective energy efficiency programs

• Continue development and implementation of a demand response pilot

• Participate with owner municipalities in the evaluation of distributed technologies such as community solar and combined heat-and-power applications

Continue to implement ways to maintain the high reliability of Platte River’s power system

• Look to secure affordable ways of balancing expected long-term growth in renewables generation using services from the regional balancing authority or future organized markets

• Manage unit outage risk through mutual support agreements, use of peaking resources, or other market opportunities for capacity

• Actively monitor regional markets to understand options for cost-effective reliability products

• Provide direction to influence the development of regional energy and ancillary services markets

Continue to diversify the portfolio to manage risk and limit CO2 emissions

• Exit ownership of Platte River’s share of Craig Unit 1

• Integrate 30 MW of new solar generation into the portfolio

• Evaluate the acquisition of additional renewables generation

Page 41


Water Policy

In December 2016, Platte River’s board of directors approved and adopted the first comprehensive Platte River Water Policy, which will provide direction to Platte River going forward in the management of water resources and assets. The board of directors and city staff members from Fort Collins, Loveland, Longmont, and the town of Estes Park all contributed to the document’s content and completion. Water is critical to the reliable operation of Rawhide Energy Station and may be necessary for the reliable operation of future generation resources. This policy will position Platte River to pursue activities that will:

• Increase reliability of water deliveries to meet contractual commitments and operational needs

• Actively manage water as an asset

• Maintain adequate water supplies for all existing and projected future operations

Page 42


Rawhide Flats Solar

In October 2016, Platte River further diversified its energy portfolio with the commissioning of a 30 MW solar generation facility at Rawhide Energy Station. The new solar facility, Rawhide Flats Solar, joins Platte River’s existing coal and natural gas facilities at the site, and will generate an expected 65,000 MWh annually—enough to supply the equivalent energy use of 8,000 average homes. Rawhide Flats Solar covers approximately 185 acres with over 117,000 solar photovoltaic panels mounted on a single-axis tracking system. The full energy output of the project is purchased from a third party under contract that runs through 2040.

Power For 8,000 Homes

185 Acres

117,000 Photovoltaic Panels

30 Megawatts

Page 43

Platte River Completes Sale of Series JJ Bonds

Platte River issued its Series JJ Bonds in April 2016 using $119 million of the proceeds to advance refund a portion of the outstanding Series HH Bonds. The true interest cost of the Series JJ Bonds is 2.20 percent, and the net present value savings for the refunded bonds exceeds $13.6 million. The remaining $60 million of the proceeds from the Series JJ Bonds will be used to reimburse and fund transmission and production capital projects. These bond proceeds will enable Platte River to initiate and complete projects that are essential in ensuring the high level of service reliability owner municipalities expect.

Platte River’s strong credit rating was a key to obtaining a low interest rate for the Series JJ Bonds. Prior to the sale, Standard and Poor’s Global Ratings and Fitch Ratings rated the bonds AA with a stable outlook. The agencies also affirmed Platte River’s AA ratings on all outstanding Power Revenue Bonds. Rationale behind the ratings included strong historical and projected debt service coverage, prudent risk management procedures, the creditworthiness of Platte River’s four owner municipalities, strength of the local economy, and a continued commitment of the board of directors to raise rates when necessary to sustain strong financial performance. The closing date of the transaction was April 26, 2016.


Page 44

Employee Engagement

Our most important resource is our employees. They work hard to provide reliable power to our owner municipalities 24 hours a day, 365 days a year. By continuing to invest in our employees we leverage diversity, grow internal talent, develop innovative skills, and maintain high standards. In 2016, Platte River:

Platte River strives to create a work environment that encourages employees to be engaged, to achieve outstanding performance, and identify opportunities for continuous improvement. We are committed to open, honest, and effective communication as a way to keep employees well-informed and positioned to meet the needs of the organization and the communities we serve.

• Conducted company-wide training events

• Provided leadership development opportunities

• Conducted a variety of safety trainings

• Offered multiple employee health and wellness events

• Encouraged and supported employee participation in several community events and volunteer opportunities

Community Involvement

Platte River believes it has a responsibility to participate in efforts that enhance the well-being of citizens in its communities. We are proud of our employees who volunteer and represent the organization. In 2016, employees raised over $36,000 for United Way of Larimer County. Employees also donated to and participated in a variety of community organizations including Boys & Girls Club of Larimer County, Project Self-Sufficiency, Arbor Day, Alexa’s Hugs, Loveland Passport to Water, Bike-To-Work Day, and science fair judging at local schools.

Image: Employee donated gifts to Boys & Girls Club families


Page 45

Laporte Substation Expansion

Before After

In 2016, Platte River completed a 230kV expansion and autotransformer addition project at Laporte Substation, located northwest of Fort Collins. Completion of this substation expansion increased Platte River’s power transmission capacity from Rawhide Energy Station by 41 percent. This increased power transmission capacity helps Platte River to provide a more reliable and robust power supply to our owner municipalities. Installation of a second 230/115kV autotransformer helps Platte River to minimize system exposure and risks during maintenance operations or contingency situations. Several equipment and protection upgrades were also completed during this project to increase system reliability and more effectively protect our assets. The oil containment plan for the existing autotransformer was improved and existing oil circuit breakers were replaced.

Projects like this one help Platte River achieve operational excellence by designing, constructing, operating, and maintaining safe, reliable, and environmentally-responsible transmission assets.


• Over 9,600 hours invested by Platte River

• Total of 10 departments involved

• Project took over 22 months to complete

• Over 18 miles of control cable installed

• Over 200 foundations installed

New 230 115kV Autotransformer

Page 46

Headquarters Campus Project

Late 1970’s

Current

Artistic Rendering

Platte River’s headquarters, located in Fort Collins, Colorado, was built in 1978. Since then, Platte River has experienced significant growth in staffing and the services provided to our owner municipalities, which exceeds the capacity and functionality of the existing facilities. As a result, the Headquarters Campus Project was initiated. After performing a detailed analysis of the existing site, facilities, and discussing possible alternatives with a specific focus on safety, efficiency, code compliance, useful life span, and functional requirements, direction was given to proceed towards a complete campus redevelopment. In October 2016, visioning and programming of the new Platte River Campus began. The new campus facilities will provide a modern up-to-date workplace with up-to-date technology and energy efficiency, allow for future growth, increase public interaction and education, as well as honor Platte River’s history.

• Selected Belford Watkins Group and Anderson Mason Dale as our design team partner

• Completed the programming process and began schematic design

In 2016, the Platte River Headquarters Campus Project:

Page 47

Platte River’s management is responsible for the preparation, integrity, and objectivity of the financial statements and related information included in this Annual Report. The financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America and, where required, reflect amounts based on the best estimates and judgments of management.

Platte River maintains a strong internal control structure designed to provide reasonable assurance that transactions are executed in accordance with management’s authorization, that financial statements are prepared in conformity with generally accepted accounting principles, and that assets are safeguarded.

Platte River’s internal auditor evaluates internal controls for adherence to policies and procedures on an ongoing basis, and reports findings and recommendations for possible improvements to management. In addition, the independent auditors consider elements of the internal control system in determining the nature and scope of their audit procedures in performing the annual audit of Platte River’s financial statements.

The board of directors, whose members are not employees of Platte River, periodically meet with the independent auditors and management to discuss the audit scope, audit results, and any recommendations to improve the internal control structure. The board of directors directly engages the independent auditors.


Report of Management

Jason FrisbieGeneral Manager / CEO

David SmalleyDeputy General Manager / CFO

Page 48


Independent Auditor’s Report

Page 49

Platte River Power Authority Independent Auditor’s Report and Financial Statements

December 31, 2016 and 2015

24 Independent Auditor’s Report 2016

Page 50

Platte River Power Authority

Financial Statements

Years Ended December 31, 2016 and 2015

Contents

....................................................................... tropeR s’rotiduA tnednepednI .................................26 Management’s Discussion and Analysis (Unaudited) ..................................................................28 Financial Statements Statements of Net Position .............................................................................................................40 Statements of Revenues, Expenses and Changes in Net Position .................................................42 Statements of Cash Flows ..............................................................................................................43 Notes to Financial Statements ........................................................................................................45 Required Supplementary Information (Unaudited) .......................................................................76 Other Information (Unaudited) ......................................................................................................78

25Independent Auditor’s Report 2016

Page 51

Independent Auditor’s Report

Board of Directors Platte River Power Authority Fort Collins, Colorado We have audited the accompanying financial statements of Platte River Power Authority (Platte River), as of and for the years ended December 31, 2016 and 2015, and the related notes to the financial statements, which collectively comprise Platte River’s basic financial statements as listed in the table of contents.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Page 52

Board of Directors Platte River Power Authority Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Platte River as of December 31, 2016 and 2015, and the changes in its financial position and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

Other Matters

Required Supplementary Information

Accounting principles generally accepted in the United States of America require that the management’s discussion and analysis and pension information as listed in the table of contents be presented to supplement the basic financial statements. Such information, although not part of the basic financial statements, is required by the Governmental Accounting Standards Board, who considers it to be an essential part of financial reporting for placing the basic financial statements in an appropriate operational, economic or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management’s responses to our inquiries, the basic financial statements and other knowledge we obtained during our audits of the basic financial statements. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.

Other Information

Our audits were conducted for the purpose of forming an opinion on the basic financial statements as a whole. The Other Information (Budgetary Comparison Schedule) listed in the table of contents is presented for purposes of additional analysis and is not a required part of the basic financial statements. Such information has not been subjected to the auditing procedures applied in the audit of the basic financial statements, and accordingly, we do not express an opinion or provide any assurance on it.

Denver, Colorado March 9, 2017


Page 53


Management’s Discussion and Analysis (Unaudited)


This discussion and analysis provides an overview of the financial performance of Platte River Power Authority (Platte River) for the fiscal years ended December 31, 2016 and December 31, 2015. The information presented should be read in conjunction with the basic financial statements and accompanying notes to the financial statements.

Platte River is a wholesale electricity generation and transmission provider that delivers safe, reliable, environmentally responsible and competitively priced energy and services to its four owner municipalities, Estes Park, Fort Collins, Longmont and Loveland.

Platte River’s power resources include generation from coal and natural gas units, allocations of federal hydropower from Western Area Power Administration (WAPA), wind and solar purchases, spot market purchases, and a forced outage exchange agreement.

Coal-fired generation includes Rawhide Unit 1 (280 MW), located 25 miles north of Fort Collins, and 18 percent ownership in Craig Units 1 and 2 (154 MW combined), located in northwest Colorado.

Gas-fired combustion turbines located at Rawhide Energy Station include five simple cycle combustion turbines, which includes four GE 7EAs (65 MW each) and a GE 7FA (128 MW). The combustion turbines are utilized to meet peak load demand, to provide reserves during outages of the coal-fired units, and to make short-term surplus sales.

Hydropower is received under two long-term contracts with WAPA. Colorado River Storage Project contract rate of delivery amounts are 106 MW in the summer and 136 MW in the winter. Actual capacity available varies by month. During the summer season, available capacity ranges from 51 MW to 60 MW. In the winter season, available capacity ranges from 72 MW to 85 MW. Loveland Area Projects capacity is 30 MW in the summer and 32 MW in the winter.

Wind generation includes 78 MW provided under long-term power purchase agreements. The agreements are for deliveries from Spring Canyon Wind Energy Center (60 MW) in Colorado, Silver Sage Windpower Project (12 MW) and Medicine Bow Wind Project (6 MW), both in Wyoming.

Solar generation includes 30 MW provided under a long-term power purchase agreement from the Rawhide Flats Solar facility located at Rawhide Energy Station. In addition, Platte River purchases solar capacity of approximately 4 MW and 0.5 MW from Fort Collins and Loveland, respectively.


Page 54


Management’s Discussion and Analysis (continued) (Unaudited)


Spot market purchases provide energy to satisfy loads, replacement power during outages, and reserve requirements.

Platte River has a forced outage exchange agreement with Tri-State Generation and Transmission, Inc. (Tri-State), whereby in the event that either Rawhide Unit 1 or Tri-State’s Craig Unit 3 is out of service the other utility will provide up to 100 MW of generation on a short-term basis.

Platte River operates as a utility enterprise and follows the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC). Platte River has implemented all applicable Governmental Accounting Standards Board (GASB) pronouncements. The accompanying financial statements are prepared on the accrual basis of accounting in conformity with accounting principles generally accepted in the United States of America.

Financial Summary

Platte River reported income before contributions of $18.0 million in 2016; approximately $11.2 million higher than 2015. The year ended with an increase in operating revenues of $5.9 million, a decrease in operating expenses of $3.0 million, and a decrease in nonoperating expenses, net, of $2.3 million.

Condensed Financial Statements

The following condensed statements of net position and condensed statements of revenues, expenses and changes in net position summarize Platte River’s financial position and changes in financial position for 2016, 2015, and 2014.


Page 55




Condensed Financial Statements (continued)

Condensed Statements of Net Position December 31, 2016 2015 2014 (In thousands)

stessA Electric utility plant $ 579,134 $ 574,453 $ 571,240 Special funds and investments 122,411 79,967 95,085 Other current and noncurrent assets 98,587 83,949 91,763

Total assets 800,132 738,369 758,088Deferred outflows of resources 24,150 6,174 1,908Liabilities Noncurrent liabilities 263,808 203,163 217,236 Current liabilities 38,836 41,098 39,072

Total liabilities 302,644 244,261 256,308Deferred inflows of resources 5,201 1,619 8,780Net position Net investment in capital assets 369,729 366,412 339,567 Restricted 25,616 21,421 24,559 Unrestricted 121,092 110,830 130,782

Total net position $ 516,437 $ 498,663 $ 494,908

Net Position

Total net position at December 31, 2016 was $516.4 million, an increase of $17.7 million over 2015. Total net position at December 31, 2015 was $498.7 million, an increase of $3.8 million over 2014. As a result of implementing GASB 68 in 2015, Platte River recognized the effect of a change in accounting principle in the amount of a $2.9 million decrease to net position as of January 1, 2015.


Page 56




Net Position (continued)

Electric utility plant increased $4.7 million during 2016, primarily the result of a $13.1 million increase in construction work in progress, an $11.3 million increase in plant and equipment in service, and a $2.5 million increase in land and land rights. Partially offsetting the overall increase was an increase in accumulated depreciation of $22.2 million. In 2015, electric utility plant increased $3.2 million, primarily the result of a $24.3 million increase in construction work in progress and a $5.3 million increase in plant and equipment in service. Accumulated depreciation also increased $26.4 million, which partially offset the overall increase.

Special funds and investments during 2016 increased $42.4 million from 2015. The increase in funds is primarily due to the Series JJ Bond financing that occurred in 2016 to fund capital expenditures.

In 2015 the funds decreased $15.1 million from 2014. The decrease is due to expenses associated with the Rawhide Unit 1 and the Craig Unit 2 scheduled maintenance outages and continued capital investments.

Current and other assets increased $14.6 million during 2016 due to increases in other long-term assets, regulatory assets, cash and cash equivalents, materials and supplies, and fuel inventory. The largest increase in other long-term assets is a result of recording estimated closure costs of impoundments at the Rawhide Energy Station that will be expensed over future periods. Regulatory assets increased from deferring additional pension expense that will also be amortized over future periods. The increase in cash equivalents is primarily due to the Series JJ Bond financing to fund capital expenses in 2016 and to reimburse capital expenses that occurred in 2015. However, there were also more liquid funds in anticipation of large payments in early 2017. Materials and supplies increased mainly for stocking parts necessary for the new digital control system installed in 2015. Craig Station fuel inventory levels have been higher than normal as a result of lower generation due to scheduled and unplanned maintenance outages and surplus sales market conditions. These increases were partially offset by decreases in other temporary investments and accounts receivable. In 2015, current and other assets decreased $7.8 million primarily due to a decrease in cash and cash equivalents. Cash decreased as a result of increased expenses related to the scheduled maintenance outages along with continued capital investments. Regulatory assets and other long-term assets also decreased. These decreases were partially offset by increases in fuel inventory, other temporary investments, accounts receivable, material and supplies and prepayments. Fuel inventory was the largest increase. The inventory balance at the Rawhide Energy Station was lower than normal at the beginning of 2015 but inventory was built back to normal levels over the course of the year. Craig Station inventory


Page 57





levels were higher than normal as a result of lower generation due to scheduled and unplanned maintenance outages and surplus sales market conditions.

Deferred outflows of resources increased $18.0 million in 2016. This amount includes 2016 pension contributions, differences between the pension plan’s expected and actual experience, changes in actuarial assumptions, and differences in actual and expected earnings of the pension investments that will be amortized over future periods. In addition, the Series JJ Bond financing that occurred in 2016 refinanced a partial amount of Series HH Bonds resulting in an unamortized deferred loss on debt refunding. In 2015, deferred outflows of resources increased $4.3 million due to implementing GASB 68. This amount includes 2015 pension contributions and differences in actual and expected earnings of the pension investments that will be amortized over future periods. Partially offsetting this increase is the amortization of the deferred losses on debt refunding.

Noncurrent liabilities increased $60.6 million in 2016 mainly due to increased long-term debt, net pension liability, and other liabilities. The Series JJ Bonds were issued in 2016 increasing long-term debt. The net pension liability increased as a result of below target market returns, and plan assumption changes. Other liabilities increased as a result of recording the estimated future closure costs for impoundments at the Rawhide Energy Station. These increases were partially offset by principal retirements of debt and decreases in the capitalized lease obligation, and the Trapper Mine Reclamation liability. The capitalized lease obligation was fulfilled as the final debt payment associated with the Windy Gap Project was made in 2016. The Trapper Mine Reclamation liability decreased as portions of the mine were reclaimed earlier than anticipated. Noncurrent liabilities decreased $14.1 million in 2015. The decrease was mainly the result of the principal retirements of debt and a decrease in the capitalized lease obligation. In 2015, the net pension liability of $6.7 million was recorded as required by GASB 68. Additional details about long-term debt can be found in Note 7 and the defined benefit pension liability in Note 11 to the financial statements.

Current liabilities reflect a $2.3 million decrease in 2016 due to decreases in accounts payable and the current portion of the capitalized lease obligation partially offset by increases in the current portion of long-term debt, accrued interest, and other liabilities. As mentioned previously, the capitalized lease obligation was relieved as the final debt payment associated with the Windy Gap Project was completed. In 2015, current liabilities reflected a $2.0 million increase due to increases in accounts payable and the current portion of the capitalized lease obligation partially offset by decreases in the current portion of long-term debt, accrued interest,


Page 58





and other liabilities. Accounts payable increased due to accrued but unpaid expenses for the Rawhide Unit 1 scheduled maintenance outage that occurred at the end of 2015.

Deferred inflows of resources increased $3.6 million in 2016 due to recording the accrual for the 2018 scheduled maintenance outage expenses for Rawhide Unit 1. Pension deferrals reflect a small decrease for the amortization of differences in the pension plan’s expected and actual experience and assumption changes. Deferred inflows of resources decreased $7.2 million in 2015 due to reversing the accrual for the 2015 scheduled maintenance outage expenses for Rawhide Unit 1. Additional pension deferrals to reflect differences in the pension plan’s expected and actual experience and assumption changes were recorded as a result of implementing GASB 68, which will be amortized over future periods.

*Information in this table regarding December 31, 2014 has not been restated for the prior year implementation of GASB 68.

Condensed Statements of Revenues, Expenses and Changes in Net Position Years Ended December 31, 2016 2015 2014* (In thousands)

Operating revenues $ 205,293 $ 199,433 $ 199,867Operating expenses 181,698 184,741 174,985Operating income 23,595 14,692 24,882Nonoperating expenses, net (5,630) (7,905) (8,276)Income before contributions 17,965 6,787 16,606Contributions of assets to

municipalities (191) (155) (155)Change in net position 17,774 6,632 16,451Beginning net position 498,663 492,031 478,457Ending net position $ 516,437 $ 498,663 $ 494,908


Page 59




Changes in Net Position

Net position increased $17.7 million in 2016, $13.9 million higher than 2015. There was an increase in operating revenues and a decrease in both operating expenses and nonoperating expenses, net. Net position increased $3.8 million in 2015, $12.6 million lower than 2014. An increase in operating expenses and a decrease in operating revenues more than offset a decrease in nonoperating expenses, net. The $2.9 million adjustment for a change in accounting principle with the implementation of GASB 68 also impacted the change in net position.

Operating revenues in 2016 increased $5.9 million from 2015.

Municipal sales revenue increased $9.2 million over 2015 primarily as the result of a 4.5% increase in wholesale rates. Municipal energy deliveries increased 0.5% and billing demand decreased 0.1% from 2015.

Surplus sales revenue (sales for resale and other) decreased $3.3 million in 2016 compared to 2015 resulting from lower short-term sales. Short-term sales decrease was a result of a lower average selling price and less energy sold. The surplus market conditions continued to be unfavorable this past year as a result of low natural gas prices, mild weather, and additional renewable resources on the market. Wheeling revenues increased 2.9% primarily as a result of an increase in customer loads.

Operating revenues in 2015 decreased $0.4 million from 2014.

Municipal sales revenue increased $6.2 million over 2014 as the result of a 2.5% increase in wholesale rates and an increase in municipal energy deliveries of 1.5%. Billing demand decreased 0.4% from 2014.

Surplus sales revenue (sales for resale and other) decreased $6.7 million in 2015 compared to 2014 resulting from lower contract and short-term sales. Contract sales decreased $0.9 million as the contract ended mid-year 2015. Short-term sales decreased $5.8 million with a lower average selling price and less energy sold. The surplus market conditions were unfavorable this past year as a result of low natural gas prices and mild weather. Wheeling revenues were relatively flat from 2014.


Page 60




Changes in Net Position (continued)

Operating expenses in 2016 decreased $3.0 million from 2015.

Purchased power costs for 2016 increased $0.7 million compared to 2015. Wind purchased power increased $1.5 million as a result of favorable wind conditions. Solar purchased power contracts began in the fall of 2016 increasing expense by $0.8 million. The increase in costs was partially offset by market purchases and other purchased power costs that were $1.3 million lower mainly due to the Rawhide Unit 1 and Craig Unit 2 scheduled maintenance outages in 2015. Purchased reserves also decreased $0.3 million due to self-providing reserves.

Fuel expense decreased $0.1 million from 2015. Fuel for the Craig units was $1.9 million below 2015 and Rawhide Unit 1 was $2.4 million above 2015. The Craig units’ generation was 14% less than 2015 primarily because the Craig units were held back due to the unfavorable surplus sales market. Rawhide Unit 1’s generation was 15% higher because of the 2015 planned outage. Natural gas for the combustion turbines decreased $0.6 million as the units were required less due to more favorable market prices.

Operations and maintenance expenses were $5.4 million less than 2015. Rawhide Unit 1 had a six-week scheduled maintenance outage in 2015 resulting in the majority of the decrease in 2016.

Administrative and general expenses increased $1.5 million over 2015 primarily due to increased demand side management program funding, and personnel expenses.

Operating expenses in 2015 increased $9.8 million over 2014.

Purchased power costs for 2015 increased $5.6 million compared to 2014. Wind purchased power contracts were in place for a full year in 2015 resulting in $4.8 million more in expense. Market purchases were $5.6 million higher for the Rawhide Unit 1 and Craig Unit 2 scheduled maintenance outages and to meet loads during peak periods but were offset by the $5.0 million replacement power outage accrual. Purchased reserves also increased $0.7 million due to reserves required for the additional wind on Platte River’s system. The increase in costs was partially offset by $0.3 million received from Tri-State under the forced outage exchange agreement and $0.2 million in other expenses.


Page 61




Changes in Net Position (continued)

Fuel expense decreased $3.5 million from 2014. The majority of the decrease relates to fuel for the Craig units and Rawhide Unit 1, $2.9 million and $1.5 million, respectively. The Craig units’ generation was 11.7% less than 2014 as Craig Unit 2 had a six-week scheduled maintenance outage. In addition, Craig units were held back due to the unfavorable surplus sales market. Rawhide Unit 1’s generation was 10.8% less than 2014 mainly due to a six-week scheduled maintenance outage. Natural gas for the combustion turbines increased $0.9 million to meet load requirements and sales.

Operations and maintenance expenses were $7.5 million more than 2014. Rawhide Unit 1 had a six-week scheduled maintenance outage creating the majority of the increase over 2014. The outage was one of the most extensive outages performed since 2005. Major activities included a complete inspection of the turbine and generator, and extensive inspections of the boiler, burners, and air heater system to address areas of concern identified in the 2014 minor outage. Craig Unit 2 also performed a six-week scheduled maintenance outage. This outage was necessary for the construction of the SCR project that is scheduled to go commercial in the spring of 2017. The overall outage expenses were offset by amounts previously accrued. The increase in 2015 is also partially due to an increase of $2.3 million in wheeling expenses, which were required for the transmission of the additional wind purchases.

Administrative and general expenses increased $1.5 million over 2014 mainly due to increased personnel expenses, demand side management program funding, professional services, and facilities planning and maintenance.

Depreciation expense decreased $1.4 million from 2014 as the original Rawhide Energy Station and Craig Station assets reached the end of their depreciable lives.

Nonoperating expenses, net, decreased $2.3 million in 2016 compared to 2015. The Series JJ Bond financing resulted in lower interest expense of $0.9 million, net of bond amortizations. Further, $1.1 million of interest expense was capitalized for projects in progress. Also contributing to lower net expenses was an increase in interest income of $0.3 million.

Nonoperating expenses, net, decreased $0.4 million in 2015 compared to 2014. The main contributor is lower interest expense of $1.0 million. Other income decreased $0.5 million as there was a one-time water lease of surplus effluent in 2014. Higher interest income of $0.1 million and a decrease in fair value of investments of $0.2 million were also recorded in 2015.


Page 62




Operating Revenues and Expenses (In millions)

$0$20$40$60$80

$100$120$140$160$180$200

Municipal Sales Surplus Sales and Other

2016

2015

2014

Operating Revenues

$0

$10

$20

$30

$40

$50

$60

$70

PurchasedPower

Fuel Operations &Maintenance

Administrative& General

Depreciation

2016

2015

2014

Operating Expenses


Page 63




Debt Ratings

Standards & Poor’s (S&P) and Fitch Ratings assigned ratings of AA to Platte River’s Series JJ Bonds issued in April 2016. The ratings on Platte River’s existing bonds remained unchanged.

hctiF P&S s’ydooM eussI dnoB

Power Revenue Bonds AA AA 2aA GG seireS AA AA 2aA HH seireS AA AA 2aA II seireS AA AA A/N JJ seireS

Budgetary Highlights

Platte River’s Board of Directors approved the 2016 Annual Budget with total revenues of $217.5 million, operating expenses of $169.9 million, debt service expenditures of $31.0 million and capital additions of $47.7 million. The following budgetary highlights are presented on a non-GAAP budgetary basis.

Total operating revenues of $205.3 million ended the year $10.5 million below budget. Municipal sales of $185.2 million were $0.4 million below budget due to below-budget variance in billing demand. Energy deliveries were just slightly below budget. Surplus sales and wheeling totaled $20.1 million and were $10.1 million below budget, negatively impacted by a weak surplus sales market. Low natural gas prices, mild weather, and additional renewable resources on the market impacted the average sales price, which excluding combustion turbine sales was 18% below budget. As a result of the market, approximately 29% less energy was sold as the Craig units were held back. Wheeling revenues were close to budget.

Operating expenses totaled $154.4 million and were $15.5 million below budget. Fuel expense was the largest variance, $8.6 million below budget, primarily due to 19.2% lower generation from the Craig units as a result of surplus sales market conditions and the extension of the scheduled outage of Craig Unit 1. Rawhide Unit 1’s generation was also 4.3% below budget mainly due to the screen maintenance outage. Lower coal prices than budget were experienced for both Rawhide Unit 1 and the Craig units. Above-budget natural gas expense partially offsets the below-budget coal expense. Natural gas expense was above budget due to operating the combustion turbines to meet load requirements and surplus sales.


Page 64




Budgetary Highlights (continued)

Production expenses ended the year $3.4 million below budget with lower-than-budgeted operations and maintenance costs for the Rawhide Unit 1, Craig units, the combustion turbines, and power operations. Water related expenses at the Rawhide Energy Station were less than planned primarily due to the final debt payment associated with the Windy Gap Project made in 2016. Further, personnel expenses were lower due to vacant positions and other operations and maintenance projects were canceled, delayed, or completed under budget. As mentioned previously, Craig Unit 1 underwent a scheduled maintenance outage that was completed successfully and under budget.

Administrative and general expenses were $1.5 million below budget mainly due to personnel expenses from vacant positions, planning expenses, consulting services, and a delay in the implementation of the demand response program.

Purchased power expenses were $1.0 million below budget. Energy was provided to Tri-State under the forced outage assistance agreement creating a credit to purchased power. There were also fewer reserve purchases mainly due to holding reserves on the generating units, taking advantage of lower cost options by purchasing reserves from other sources, and lower loads. These below-budget expenses were partially offset by above-budget supplemental purchases, which were required due to the scheduled maintenance outages. Market purchases were also made to take advantage of the favorable pricing. Lastly, favorable wind conditions resulted in higher generation from purchased power contracts for wind energy.

Transmission expenses were below budget $0.9 million from lower personnel expenses, joint facility expenses, substation projects, and wheeling expenses.

Debt service expenditures totaled $29.6 million, which were $1.4 million below budget due to favorable results from the Series JJ Bond financing and capitalizing more interest expense than budgeted. Capital additions of $38.4 million were $9.3 million below budget. This variance was due to construction schedule changes, scope changes, contract delays, internal resource constraints, canceled projects, and favorable pricing. Production additions, transmission additions and general additions were below budget $6.9 million, $2.3 million and $0.1 million, respectively. The majority of the variance will be carried over to the 2017 Annual Budget in order to complete the projects. (See Budgetary Comparison Schedule presented as Other Information as listed in the table of contents.)


Page 65


Statements of Net Position


December 31,

2016 2015

Assets

Electric utility plant, at original cost (Notes 3 and 4):Land and land rights 16,997$ 14,515$ Plant and equipment in service 1,287,246 1,275,987 Less: accumulated depreciation (782,145) (759,951)

Plant in service, net 522,098 530,551 Construction work in progress 57,036 43,902

Total electric utility plant 579,134 574,453 Special funds and investments (Note 5):

Restricted funds and investments 61,624 22,201 Dedicated funds and investments 60,787 57,766

Total special funds and investments 122,411 79,967 Current assets:

Cash and cash equivalents (Notes 3 and 5) 14,159 10,126 Other temporary investments (Note 5) 18,888 20,711 Accounts receivable—municipalities 15,410 14,503 Accounts receivable—other 6,457 7,501 Fuel inventory, at last-in, first-out cost 14,607 13,590 Materials and supplies inventory, at average cost 13,470 12,362 Prepayments and other assets 1,358 1,364

Total current assets 84,349 80,157 Noncurrent assets:

Regulatory assets (Note 9) 6,507 2,437 Other long-term assets 7,731 1,355

Total noncurrent assets 14,238 3,792

Total assets 800,132 738,369

Deferred Outflows of Resources

Deferred loss on debt refundings (Note 7) 9,916 1,033 Pension deferrals (Note 11) 14,234 5,141

Total deferred outflows of resources 24,150 6,174

See accompanying notes.

(In thousands)


Page 66


Statements of Net Position (continued)


December 31,2016 2015

Liabilities

Noncurrent liabilities (Notes 3 and 6):Long-term debt, net (Note 7) 227,288$ 183,559$ Capitalized lease obligation (Note 8) – 3,229 Net pension liability (Note 11) 20,508 6,693 Other liabilities and credits 16,012 9,682

Total noncurrent liabilities 263,808 203,163 Current liabilities:

Current maturities of long-term debt (Note 7) 23,550 16,615 Current portion of capitalized lease obligation (Note 8) – 3,063 Accounts payable 13,037 19,297 Accrued interest 849 780 Accrued liabilities and other 1,400 1,343

Total current liabilities 38,836 41,098

Total liabilities 302,644 244,261

Deferred Inflows of Resources

Regulatory credits (Note 9) 4,729 1,006 Pension deferrals (Note 11) 472 613

Total deferred inflows of resources 5,201 1,619

Net Position

Net investment in capital assets (Note 10) 369,729 366,412 Restricted 25,616 21,421 Unrestricted 121,092 110,830

Total net position 516,437$ 498,663$


(In thousands)


Page 67


Statements of Revenues, Expenses, and Changes in Net Position


2016 2015

Operating revenues (Note 3):Sales to municipalities 185,214$ 175,998$ Sales for resale and other 20,079 23,435

Total operating revenues 205,293 199,433 Operating expenses:

Purchased power 33,270 32,548 Fuel 46,361 46,446 Operations and maintenance 57,481 62,854 Administrative and general 17,366 15,906 Depreciation 27,220 26,987

Total operating expenses 181,698 184,741 Operating income 23,595 14,692

Nonoperating revenues (expenses) (Notes 5 and 7) :Interest income 1,084 745 Other income 846 900 Interest expense (8,523) (9,438) Allowance for funds used during construction 1,137 – Net decrease in fair value of investments (Note 5) (174) (112)

Total nonoperating revenues (expenses) (5,630) (7,905)

Income before contributions 17,965 6,787

Contributions of assets to municipalities (Note 13) (191) (155)

Change in net position 17,774 6,632 Net position at beginning of year 498,663 492,031 Net position at end of year 516,437$ 498,663$


Years Ended December 31,

(In thousands)


Page 68


Statements of Cash Flows


2016 2015

Cash flows from operating activitiesReceipts from customers 205,190$ 199,008$ Payments for operating goods and services (132,698) (136,175) Payments for employee services (32,985) (32,472) Net cash provided by operating activities 39,507 30,361

Cash flows from capital and related financing activitiesAdditions to electric utility plant (27,313) (27,747) Payments from accounts payable incurred for electric utility

plant additions (2,608) (962) Deposits into escrow for bond defeasance (119,164) – Proceeds from issuance of long-term debt 179,170 – Principal payments on long-term debt (16,615) (21,980) Interest payments on long-term debt (9,996) (9,874) Net cash provided by (used in) capital

and related financing activities 3,474 (60,563)

Cash flows from investing activitiesPurchases and sales of temporary and restricted investments, net (40,786) 14,505 Interest and other income, including realized gains and losses 1,838 1,589 Net cash (used in) provided by investing activities (38,948) 16,094

Increase (decrease) in cash and cash equivalents 4,033 (14,108) Balance at beginning of year in cash and cash equivalents 10,126 24,234

Balance at end of year in cash and cash equivalents 14,159$ 10,126$


(In thousands)



Page 69


Statements of Cash Flows (continued)


2016 2015

Reconciliation of operating income to net cash provided by operating activities

Operating income 23,595$ 14,692$ Adjustments to reconcile operating income to net cash provided

by operating activities:Depreciation 27,220 26,987 Changes in assets and liabilities which provided (used) cash:

Accounts receivable 138 (514) Fuel and materials and supplies inventories (2,126) (6,062) Prepayments and other assets (10,507) 582 Deferred outflows of resources (9,094) (1,236) Accounts payable (7,295) 5,965 Net pension liability 13,815 (89) Other liabilities 179 (2,803) Deferred inflows of resources 3,582 (7,161)

Net cash provided by operating activities 39,507$ 30,361$

Noncash capital and related financing activitiesAdditions of electric utility plant through incurrence of accounts

payable 3,643$ 2,608$ Amortization of bond premiums and deferred loss on refundings (1,696) (522) Amortization of regulatory asset (debt issuance costs) 153 173



(In thousands)


Page 70


Notes to Financial Statements


1. Organization

Platte River Power Authority (Platte River) was organized in accordance with Colorado law as a separate governmental entity by the four municipalities of Estes Park, Fort Collins, Longmont, and Loveland. Platte River contracted to supply the wholesale electric power and energy requirements of each of these municipalities (except for energy produced by each municipality’s hydro facilities in service at September 1974). These contracts currently extend through December 31, 2050. Each of the four member municipalities has a residual interest in Platte River’s assets and liabilities upon dissolution, which is proportional to the total revenue received from each municipality since Platte River was organized, less any contributions of assets previously distributed. Based upon electric revenues billed from inception through December 31, 2016, these residual interests are approximately as follows:

laudiseR tseretnI

City of Fort Collins 48% City of Longmont 26% City of Loveland 21% Town of Estes Park 5%

%001 Under Colorado law and the municipal contracts, Platte River’s Board of Directors has the exclusive authority to establish the electric rates to be charged to the member municipalities. Platte River must follow specified statutory procedures, including public notice and holding a hearing to receive public comments, before adopting an annual budget and implementing any changes in the electric rates.

2. Operations

Rawhide Energy Station

The Rawhide Energy Station consists of Rawhide Unit 1, a 280-megawatt (net) coal-fired generating facility, a cooling pond, coal-handling facilities, related transmission facilities, five simple-cycle gas-fired combustion turbines and a 30-megawatt solar facility. Natural gas Units A through D have a summer peaking capacity of 65 megawatts each and Unit F has a summer peaking capacity of 128 megawatts. The Rawhide Energy Station facilities, except for the solar facility, are wholly owned and operated by Platte River.


Page 71


Notes to Financial Statements (continued)

December 31, 2016 and 2015 2. Operations (continued)

Yampa Project

Platte River owns 18%, or 154 megawatts, of Craig Units 1 and 2 of the Yampa Project as a tenant-in-common with four other electric utilities. The current Yampa Project Participation Agreement took effect on April 15, 1992. The Yampa Project consists of 855 megawatts of coal-fired generation and associated transmission plant facilities located near the town of Craig in northwestern Colorado. Platte River’s share of the plant investment is included in plant in service, net, in the accompanying statements of net position. Platte River’s share of operating expenses of the Yampa Project is included in operating expenses in the accompanying statements of revenues, expenses and changes in net position. Separate financial statements for the Yampa Project are not available. In addition, Platte River and all but one of the other Yampa Project participants own Trapper Mining, Inc., which owns and operates the adjacent coal mine that supplies the majority of Craig Units 1 and 2 fuel needs.

3. Summary of Significant Accounting Policies

Reporting Entity

For financial reporting purposes, Platte River meets the criteria of an “other stand-alone government” and has no component units as defined in Governmental Accounting Standards Board (GASB) Statements No. 14, as amended, and 39, The Financial Reporting Entity and Determining Whether Certain Organizations Are Component Units—an amendment of GASB Statement No. 14. As a municipal utility and a separate governmental entity, Platte River is exempt from taxes on its property and income.


Page 72



December 31, 2016 and 2015 3. Summary of Significant Accounting Policies (continued)

Basis of Accounting

Platte River accounts for its financial operations as a “proprietary fund” and the accompanying financial statements have been prepared using the accrual method of accounting in conformity with accounting principles generally accepted in the United States of America. Platte River’s accounts are maintained in accordance with the Uniform System of Accounts as prescribed by the Federal Energy Regulatory Commission.

As a Board-regulated entity, Platte River is subject to the provisions of GASB Statement No. 62, Codification of Accounting and Financial Reporting Guidance Contained in Pre-November 30, 1989 FASB and AICPA Pronouncements, Regulated Operations, paragraphs 476–500, which requires the effects of the rate-making process to be recorded in the financial statements. Accordingly, certain expenses and revenues normally reflected in the statements of revenues, expenses and changes in net position as incurred are recognized when they are included in Platte River’s wholesale rates. Platte River has recorded various regulatory assets and credits to reflect the rate-making process (Note 9).

Budgetary Process

A formal budgetary process is required by Colorado State Local Government Law and is utilized as a management control tool. A proposed annual budget must be submitted to Platte River’s Board of Directors by October 15 of each year. Following public hearings, the budget is considered for adoption by the Board of Directors on or before December 31. Since Platte River operates as an enterprise, it is not subject to Colorado’s Taxpayers’ Bill of Rights (TABOR) provisions.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America as prescribed by GASB requires management to make estimates and assumptions that affect the reported amounts of assets, deferred outflows of resources, liabilities and deferred inflows of resources and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates.


Page 73




Electric Utility Plant and Depreciation

Electric utility plant is stated at the historical cost of construction. Construction costs include labor, materials, contracted services, and the allocation of indirect charges for engineering, supervision, transportation, and administrative expenses. The cost of additions to utility plant and replacement property units is capitalized. Repairs, maintenance, and minor replacement costs are charged to expense when incurred. When construction is debt-financed, an allowance for borrowed funds used during construction is included in the project cost.

Depreciation is recorded using the straight-line method over the estimated useful lives of the various classes of plant in service, which range from five to fifty years. Depreciation expense was approximately 2.1% of depreciable property for the years 2016 and 2015. The original cost of property replaced or retired, and removal costs less salvage, are charged to accumulated depreciation.

Cash and Cash Equivalents

For purposes of the statements of cash flows, Platte River considers all cash on deposit with financial institutions and highly liquid investments with an original maturity of less than three months, excluding special funds and investments, as cash and cash equivalents.

Closure and Postclosure Care Costs of Disposal Facility

Platte River accrues a liability of estimated future closure and postclosure care costs for its Rawhide Energy Station ash disposal facility. The liability is determined by multiplying the estimated closure and postclosure care costs in current dollars by the percentage of the disposal facility’s total estimated capacity used through the end of the year.

Closure Costs for Impoundments

Platte River is obligated under state laws and regulations to remove wastes from impoundments at the Rawhide Energy Station and confirm that any environmental impact has been addressed prior to closing them. During 2016, the State of Colorado notified Platte River of the need to report a liability for such removal and closure costs.


Page 74




Closure Costs for Impoundments (continued)

At December 31, 2016, Platte River accrued a liability of $7,557,000 for the estimated clean closure costs of these impoundments. A corresponding amount was recognized in other long-term assets. Beginning in 2017, Platte River will amortize these costs over 30 years, the estimated remaining useful life of the facility. Platte River is in compliance with the financial assurances required by the state.

Long-term Debt

The difference between the reacquisition price and the net carrying amount of refunded debt (deferred amount on refundings) in an advance refunding transaction is deferred and amortized as a component of interest expense using the bonds outstanding method over the shorter of the remaining life of the defeased debt or the life of the new debt. The deferred amount is reported as a deferred outflow of resources.

Energy Risk Management

Platte River has established a formal energy risk management program to manage its exposure to risks associated with wholesale energy and natural gas market price fluctuations. Under Board of Directors’ approved policies, Platte River may use various physical and financial instruments, such as physical forward contracts, futures, swaps, and option agreements. These transactions are hedges and any expense, gain or loss that is realized on these transactions is recorded as purchased power or fuel expense in the accompanying statements of revenues, expenses and changes in net position.

There were no natural gas swap contracts entered into during 2016 and no swap contracts were outstanding at December 31, 2016 and 2015. During 2015, Platte River entered into natural gas swap contracts to fix prices for the purpose of hedging against natural gas price fluctuations. The contracts were based on the Colorado Interstate Gas Co. (CIG) index published in Gas Daily. Swap contracts for 40,000 mmBtu at an average fixed price of $2.96 per mmBtu expired in July and August 2015. As a result of these hedging contracts, there was an increase in fuel expense of $15,000 for the year ended December 31, 2015. No cash was paid or received by Platte River when the contracts were initiated. Platte River is the fixed price payer. The natural gas swap contracts are considered normal purchase contracts because Platte River takes delivery of the natural gas. Thus, the contracts are not included in the scope of GASB Statement No. 53, Accounting and Financial Reporting for Derivative Instruments


Page 75




Operating Revenues and Expenses

Operating revenues and expenses consist of those revenues and costs directly related to the generation, purchase, and transmission of electricity. Operating revenues are billed and recorded at the end of each month for all electricity delivered. Revenues and expenses related to financing, investing, and other activities are considered to be nonoperating.

Defined Benefit Pension Plan

The Platte River Power Authority Defined Benefit Plan (the Plan) is a single-employer defined benefit pension plan. For purposes of measuring the net pension liability, deferred outflows of resources and deferred inflows of resources related to pensions, and pension expense, information about the fiduciary net position of the Plan and additions to/deductions from the Plan’s fiduciary net position have been determined on the same basis as they are reported by the Plan. For this purpose, benefit payments are recognized when due and payable in accordance with the benefit terms. Investments are reported at fair value.

Deferred Outflows of Resources

Deferred outflows consist of unamortized deferred losses on refunding of debt and pension-related deferrals.

Deferred Inflows of Resources

Deferred inflows consist of the estimated incremental expenses of scheduled major maintenance outages and pension-related deferrals.

Use of Restricted and Unrestricted Resources

The use of restricted and unrestricted resources will be based on the intended purposes as indicated in the bond resolutions.


Page 76




Recent Accounting Pronouncements

Platte River implemented GASB Statement No. 72, Fair Value Measurement and Application, in 2016. Because Platte River was already reporting investments at fair value, the primary effect of the implementation was additional note disclosures.

In 2015, Platte River implemented GASB Statement No. 68, Accounting and Financial Reporting for Pensions, an amendment of GASB Statement No. 27 and GASB Statement No. 71, Pension Transition for Contributions Made Subsequent to the Measurement Date—an amendment of GASB Statement No. 68. In implementing GASB 68 and 71, Platte River recognized the effect of a change in accounting principle in the amount of $6,782,000 for the net pension liability and $3,905,000 to deferred outflows of resources for the 2014 pension contribution made subsequent to the measurement date for a net adjustment to net position of $2,877,000 as of January 1, 2015. There was no impact to deferred inflows of resources for prior years.

4. Electric Utility Plant

Electric utility plant asset activity for the year ended December 31, 2016, was as follows:

December 31

2015

Increases

Decreases December 31

2016 (In thousands)

:stessa elbaicerpednoN Land and land rights $ 14,515 $ 2,482 $ – $ 16,997 Construction work in progress 43,902 38,404 (25,270) 57,036

)072,52( 688,04 714,85 74,033 :stessa elbaicerpeD

Production plant 893,311 12,448 (9,928) 895,831 Transmission plant 345,506 9,014 (607) 353,913 General plant 37,170 1,924 (1,592) 37,502

)721,21( 683,32 789,572,1 1,287,246 detalumucca sseL

depreciation (759,951) (27,220) 5,026 (782,145) Total electric utility plant $ 574,453 $ 37,052 $ (32,371) $ 579,134


Page 77




4. Electric Utility Plant (continued)

Electric utility plant asset activity for the year ended December 31, 2015, was as follows:

December 31

2014

Increases

Decreases December 31

2015 (In thousands)

:stessa elbaicerpednoN Land and land rights $ 14,515 $ – $ – $ 14,515 Construction work in progress 19,603 33,219 (8,920) 43,902

714,85 )029,8( 912,33 811,43 :stessa elbaicerpeD

Production plant 891,344 4,240 (2,273) 893,311 Transmission plant 343,649 3,019 (1,162) 345,506 General plant 35,717 2,032 (579) 37,170

789,572,1 )410,4( 192,9 017,072,1 detalumucca sseL

depreciation (733,588) (26,987) 624 (759,951) Total electric utility plant $ 571,240 $ 15,523 $ (12,310) $ 574,453

5. Cash and Investments

Investment of Platte River’s funds is administered in accordance with Colorado law and Platte River’s General Power Bond Resolution, Fiscal Resolution and Investment Policy. Accordingly, Platte River may only invest in obligations of the United States government and its agencies and other investments permitted under Colorado law. Platte River records its investments at their estimated fair market values. The unrealized holding gains and losses on these investments are included in net increase (decrease) in fair value of investments in the statements of revenues, expenses and changes in net position. The fair value of investments is presented on the statements of net position as special funds and investments, cash and cash equivalents, and other temporary investments. Special funds and investments are either internally dedicated by Board Resolution (dedicated funds and investments) or restricted as to use by Platte River’s General Power Bond Resolution (restricted funds and investments). The fair value of investments, exclusive of accrued interest of $233,000 and $140,000 as of December 31, 2016 and 2015, respectively, are shown in the following tables.


Page 78



December 31, 2016 and 2015 5. Cash and Investments (continued)

As of December 31, 2016, Platte River had the following cash and investments and related maturities:

Investment Maturities (in years) Cash and

Investment Type Fair

Value Less

Than 1

1 - 2

2 - 3

3 - 4 4 - 5 (In thousands) U.S. Treasuries $ 39,858 $ 24,002 $ 10,901 $ 4,955 $ – $ –U.S. Agencies:

– – 730,5289,1440,9360,61 BCFF – – 479,2684,4901,5965,21 BLHF – – –889,1–889,1 CMLHF – – 554,9––554,9 AMNF

Total securities 79,933 38,155 19,357 22,421 – – Certificates of deposit 8,133 8,133 – – – – Cash and money market funds 3,822 3,822 – – – –

tnemtsevni tnemnrevog lacoL – – ––733,36 733,36 sloop

Total cash and investments $155,225 $113,447 $ 19,357 $ 22,421 $ – $ – Statement of net position presentation of cash, cash equivalents and investments is as follows as of December 31, 2016:

riaF Value

Accrued Interest

Total

(In thousands)

Restricted funds and investments $ 61,569 $ 55 $ 61,624 Dedicated funds and investments 60,658 129 60,787 Cash and cash equivalents 14,158 1 14,159 Other temporary investments 18,840 48 18,888 Total cash and investments $ 155,225 $ 233 $ 155,458


Page 79




As of December 31, 2015, Platte River had the following cash and investments and related maturities:

Investment Maturities (in years) Cash and

Investment Type Fair

Value Less

Than 1

1 - 2

2 - 3

3 - 4 4 - 5 (In thousands) U.S. Treasuries $ 48,955 $ 21,004 $ 23,936 $ 4,015 $ – $ –U.S. Agencies:

– – 789,1020,9–700,11 BCFF – – 250,6690,5468,3210,51 BLHF – – ––890,11890,11 CMLHF – – ––000,3000,3 AMNF

Total securities 89,072 38,966 38,052 12,054 – – Certificates of deposit 11,099 3,012 8,087 – – – Cash and money market funds 9,873 9,873 – – – –

tnemtsevni tnemnrevog lacoL – – ––026 026 sloop

Total cash and investments $110,664 $ 52,471 $ 46,139 $ 12,054 $ – $ – Statement of net position presentation of cash, cash equivalents and investments is as follows as of December 31, 2015:

Fair Value

Accrued Interest

Total

(In thousands)

Restricted funds and investments $ 22,190 $ 11 $ 22,201 Dedicated funds and investments 57,665 101 57,766 Cash and cash equivalents 10,126 – 10,126 Other temporary investments 20,683 28 20,711 Total cash and investments $ 110,664 $ 140 $ 110,804


Page 80




Interest Rate Risk

As a means of limiting its exposure to fair value losses arising from rising interest rates, Platte River’s investment policy and Colorado state statutes limit the investment portfolio to maturities of five years or less. Platte River uses a laddered approach to investing funds based on projected cash flows. The assumed maturity date for callable securities is based on market conditions as of December 31, 2016. If the price of the security is at or above its call price, the security is assumed to be redeemed on its next call date.

Credit Risk

Platte River’s investment policy allows investments in local government investment pools and money market funds. As of December 31, 2016, Platte River maintained investments in funds managed by the local government investment pool Colorado Local Government Liquid Asset Trust (COLOTRUST), and the Colorado Statewide Investment Program (CSIP). Both of these funds are rated AAAm by Standard and Poor’s Ratings Services (S&P). Platte River’s investments in Federal Farm Credit Bank (FFCB), Federal Home Loan Bank (FHLB), Federal Home Loan Mortgage Corporation (FHLMC), and Federal National Mortgage Association (FNMA) were rated Aaa by Moody’s Investors Service and AA+ by S&P.

Concentration of Credit Risk

Platte River’s investment policy states that assets held in Platte River’s funds shall be diversified to eliminate the risk of loss resulting from over concentration of assets in a specific maturity, a specific issuer or a specific class of securities. As of December 31, 2016, more than 5% of Platte River’s investments were concentrated in FFCB, FHLB and FNMA. These investments are 10%, 8% and 6%, respectively, of Platte River’s total investments (including outside investment pools and certificates of deposit).


Page 81




Fair Value

Platte River categorizes its fair value measurements within the fair value hierarchy established by generally accepted accounting principles. The hierarchy is based on the valuation inputs used to measure the fair value of the asset. Level 1 inputs are quoted prices in active markets for identical assets; Level 2 inputs are prices determined using observable inputs other than Level 1 prices such as quoted prices for similar assets, quoted prices in markets that are not active, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets; Level 3 inputs are significant unobservable inputs.

Platte River has the following recurring fair value measurements as of December 31, 2016:

U.S Treasury securities of $39,858,000 are valued using quoted market prices (Level 1 inputs)

U.S. Agency securities of $40,075,000 and Local Government Investment Pools of $63,337,000 are valued using Level 2 inputs

Platte River had the following recurring fair value measurements as of December 31, 2015:

U.S. Treasury securities of $48,955,000 are valued using quoted market prices (Level 1 inputs)

U.S. Agency securities of $40,117,000 and Local Government Investment Pools of $620,000 are valued using Level 2 inputs


Page 82



December 31, 2016 and 2015 6. Noncurrent Liabilities

Noncurrent liability activity for the year ended December 31, 2016 was as follows:

December 31 2015

Additions

Reductions

December 31 2016

Due within one year

(In thousands)

Long-term debt, net $ 200,174 $ 179,170 $ (128,506) $ 250,838 $ 23,550Capitalized lease obligation 6,292 – (6,292) – –Net pension liability 6,693 13,815 – 20,508 –Reclamation liability 4,253 – (1,162) 3,091 –Disposal facility closure costs 192 3 – 195 –Impoundments closure costs – 7,557 – 7,557 –Compensated absences 4,442 514 (462) 4,494 353Lease advances 823 – (83) 740 83Yampa employee obligation 360 11 – 371 –Total noncurrent liabilities $ 223,229 $ 201,070 $ (136,505) $ 287,794 $ 23,986 Noncurrent liability activity for the year ended December 31, 2015 was as follows:

December 31 2014

Additions

Reductions

December 31 2015

Due within one year

(In thousands)

Long-term debt, net $ 223,552 $ – $ (23,378) $ 200,174 $ 16,615Capitalized lease obligation 9,067 – (2,775) 6,292 3,063Net pension liability – 6,693 – 6,693 –Reclamation liability 4,250 3 – 4,253 –Disposal facility closure costs 190 2 – 192 –Compensated absences 3,997 802 (357) 4,442 305Lease advances 906 – (83) 823 83Yampa employee obligation 353 7 – 360 –Total noncurrent liabilities $ 242,315 $ 7,507 $ (26,593) $ 223,229 $ 20,066


Page 83



December 31, 2016 and 2015 7. Long-term Debt

Long-term debt outstanding as of December 31, 2016 and 2015 consists of the following:

13 rebmeceD 5102 6102 etaR tseretnI

(In thousands) —sdnoB euneveR rewoP

:GG seireS —sdnoB laireS

Maturing 6/1/2018 4.50%–5.00% $ 30,520 $ 41,560 :HH seireS —sdnoB laireS

Maturing 6/1/2019 3.00%–5.00% 8,185 113,725 :II seireS —sdnoB laireS

Maturing 6/1/2037 4.00%–5.00% 31,955 37,430 :JJ seireS —sdnoB laireS

Maturing 6/1/2036 3.50%–5.00% 147,230 – 217,890 192,715

Unamortized bond premium 32,948 7,459 Total revenue bonds outstanding 250,838 200,174 Less: due within one year (23,550) (16,615) Total long-term debt, net $ 227,288 $ 183,559

___________

Fixed rate bond premium costs are amortized over the terms of the related bond issues.

Interest expense for the years ended December 31, 2016 and 2015 is comprised of the following:

5102 6102 (In thousands)

Interest $ 10,066 $ 9,787 Amortization of bond related costs (1,543) (349) Total interest expense $ 8,523 $ 9,438


Page 84



December 31, 2016 and 2015 7. Long-term Debt (continued)

Calendar year totals for monthly bond service funding requirements per bond resolution for all bonds outstanding, which may differ from actual semi-annual debt service requirements by year, are shown in the table below:

Year ending December 31 Principal Interest Total (In thousands)

Deposits in 2016 for 2017 payment $ 13,738 $ 904 $ 14,642

009,72 285,9 813,81 7102338,02 927,8 401,21 8102054,81 921,8 123,01 9102422,81 026,7 406,01 0202622,81 690,7 031,11 1202301,19 157,62 253,46 6202–2202831,95 573,21 367,64 1302–7202439,33 796,4 732,92 6302–2302983,1 66 323,1 7302938,303 $ 949,58 $ 098,712 $

In April 2016, Platte River issued $147,230,000 Series JJ Power Revenue Bonds at a true interest cost of 2.2%. The bonds were sold at a $31,940,000 premium, providing total bond proceeds of $179,170,000. Proceeds of $60,208,000 will be used to fund capital projects and pay issuance costs and $118,962,000 will be used to advance refund a portion of the outstanding Series HH Bonds. The refunding resulted in an economic gain (net present value savings) of $13,652,000.

The proceeds from the Series JJ Bonds along with the proceeds and available cash from prior year’s refunded bonds have been placed in an irrevocable trust to provide for all future debt service payments on the refunded bonds. Accordingly, the trust account assets and the liability for the defeased bonds are not included in Platte River’s financial statements. As of December 31, 2016, $105,440,000 of the defeased Series HH Bonds and $16,975,000 of the defeased Series I Bonds remains outstanding.


Page 85




Bond Service Coverage

Power revenue bonds are secured by a pledge of the revenues of Platte River after deducting operating expenses, as defined in the General Power Bond Resolution. The power revenue bonds issued by Platte River may be subject to early call provisions. Principal and interest payments are met from net revenues earned from wholesale electric rates charged to the municipalities and others, and from interest earnings.

Under the General Power Bond Resolution, Platte River is required to charge wholesale electric energy rates to the municipalities that are reasonably expected to yield net revenues for the forthcoming 12-month period that are at least equal to 1.10 times total power bond service requirements. Under the General Power Bond Resolution, Platte River has established a Rate Stabilization Reserve Account. Deposits to this account are a reduction to current net revenues for purposes of computing bond service coverage. Future withdrawals will increase net revenues for purposes of computing bond service coverage and could assist Platte River, at such time, in meeting its wholesale rate covenant. The balances in the Rate Stabilization Reserve Account at December 31, 2016 and 2015 were $20,166,000 and $20,216,000, respectively, excluding accrued interest. The Rate Stabilization Reserve Account is included in dedicated funds and investments in the statements of net position.


Page 86




The following table is a calculation of the power revenue bond coverage ratios for the years ended December 31, 2016 and 2015:


:seunever teN Operating revenues $ 205,293 $ 199,433 Operating expenses, excluding depreciation 154,478 157,754 Net operating revenues 50,815 41,679 Plus interest and other income(1) 1,921 1,672 Net revenues before rate stabilization 52,736 43,351 Rate stabilization: Deposits – – Withdrawals – – Total net revenues $ 52,736 $ 43,351 Bond service:

Power revenue bonds $ 30,726 $ 28,637 Allowance for funds used during construction (1,137) – Net revenue bond service $ 29,589 $ 28,637 Power revenue bond coverage ratio 1.78 1.51 ___________

(1) Excludes unrealized holding gains and losses on investments.


Page 87




Arbitrage Rebate

Under U.S. Treasury Department regulations, all governmental tax-exempt debt issued after August 31, 1986, is subject to arbitrage rebate requirements. Interest income on bond proceeds that exceeds the cost of borrowing is payable to the federal government on every fifth anniversary of each bond issue. No arbitrage liability was outstanding as of December 31, 2016 and 2015.

Deferred Outflows of Resources Related to Debt

As of December 31, 2016 and 2015, deferred outflows related to debt consisted of the unamortized deferred loss on debt refundings of $9,916,000 and $1,033,000, respectively.

8. Capitalized Lease Obligation

Under an agreement with the Municipal Subdistrict of the Northern Colorado Water Conservancy District, Platte River is entitled to an allocation of one-third of the available water from the Windy Gap Project, a water diversion facility completed May 1, 1985. Under the agreement, Platte River is obligated to pay each year one-third of the debt service and approximately one-third of the actual operating and maintenance costs of the Windy Gap Project. These payments, which totaled $4,918,000 and $4,605,000 in 2016 and 2015, respectively, have been included in operations and maintenance expenses in the accompanying statements of revenues, expenses and changes in net position, as allowed under GASB 62, paragraphs 476–500.

In April 2016, the Municipal Subdistrict defeased all outstanding maturities of the Series H Water Revenue Bonds with Subdistrict project reserve funds. As a result of the defeasance, Platte River wrote off its remaining share of the principal amounts of the defeased bonds in the amount of $3,229,000. As of December 31, 2016, the capitalized lease of $41,590,000 for Platte River’s water allotment has been fully amortized.


Page 88



December 31, 2016 and 2015 9. Regulatory Assets and Deferred Inflows of Resources Related to Regulatory Credits

Additional Pension Expense

Platte River funds its defined benefit pension plan (Note 11) based on cost estimates developed on an actuarial basis. In addition to the base contribution, Platte River has an additional funding charge if the market value of the assets is less than 100% of the actuarial present value of accumulated plan benefits. Effective January 1, 2010, the Board of Directors approved a policy under GASB 62, paragraphs 476–500, that provides for the expense recognition of any additional pension funding charge to be spread over a ten-year period. Each subsequent year’s additional funding charge, if any, will be added to the regulatory prepaid asset and amortized over an additional ten-year period. There was no additional pension funding charge for 2016 and 2015. The regulatory prepaid asset for additional pension expense was $1,542,000 and $1,985,000 as of December 31, 2016 and 2015, respectively. The current portion of these amounts, $443,000 as of December 31, 2016 and 2015, is included as a component of prepayments and other assets in the statements of net position.

Debt Issuance Costs

Under GASB 65, debt issuance costs are required to be expensed in the period incurred rather than amortized over the life of the related debt. In order to provide recovery for debt issuance costs through rates, the Board of Directors approved the use of GASB 62, paragraphs 476–500, to recognize debt issuance costs as a regulatory asset and to amortize these costs over the life of the associated debt. Unamortized debt issuance costs included in regulatory assets were $828,000 and $895,000 as of December 31, 2016 and 2015, respectively.

Accrued Maintenance Outage Costs

As allowed under GASB 62, paragraphs 476–500, an accrual for the estimated incremental expenses of future scheduled major maintenance outages is recorded each year. Prior to the major maintenance outage at Rawhide Unit 1 in the fall of 2015, a portion of the estimated maintenance expenses was accrued. After the 2015 outage was completed, a portion of the estimated maintenance and replacement power costs for the next major maintenance outage, planned for the fall of 2018, was accrued. During 2016, the accrual estimate was expanded to include 100% of the total estimated outage costs. As of December 31, 2016 and 2015, $4,089,000 and $295,000, respectively, was accrued as a deferred inflow of resources for the 2018 scheduled maintenance outage planned for Rawhide Unit 1.


Page 89



December 31, 2016 and 2015 9. Regulatory Assets and Deferred Inflows of Resources Related to Regulatory Credits (continued)

Pension Contribution Expense Recognition

Effective for the year ending December 31, 2015, Platte River’s Board of Directors approved recording pension contributions as pension expense under GASB 62, paragraphs 476–500, since the pension contribution amount is known at the time of budget preparation and rate setting. Any difference between pension contribution and pension expense, as calculated by the actuary under GASB 68, will be amortized over a ten-year period beginning the following year. The amortization amount will be included in pension expense along with the pension contribution for each year calculated. At December 31, 2016, a regulatory asset of $4,580,000 was recorded as a result of the difference between the 2016 contribution amount of $2,912,000 and pension expense of $7,492,000 as calculated under GASB 68. The regulatory credit for unamortized pension expense was $640,000 and $711,000, respectively, as of December 31, 2016 and 2015 and was accrued as a deferred inflow of resources.

10. Net Investment in Capital Assets

Net investment in capital assets is comprised of the following as of December 31, 2016 and 2015:


Electric utility plant Unspent Series JJ bond proceeds Deferred loss on debt refundings Long-term debt, net Capitalized lease obligation Accounts payable incurred for capital assets

$ 579,134 35,160 9,916 (250,838) –

(3,643)

$ 574,453 –

1,033 (200,174) (6,292) (2,608)

$ 369,729 $ 366,412


Page 90



December 31, 2016 and 2015 11. Defined Benefit Pension Plan

Plan Description

The Platte River Power Authority Defined Benefit Plan (the Plan) is a single-employer, defined benefit pension plan administered by Platte River with managerial responsibilities for investment decisions residing with the Plan’s Retirement Committee. The Plan provides retirement and disability benefits, annual cost-of-living adjustments, and death benefits to Plan participants and beneficiaries. All regular Platte River employees hired prior to September 1, 2010 are covered by the Plan. The Plan is closed to new employees hired on or after that date. Benefit provisions of the Plan are determined and authorized by the Board of Directors of Platte River. Platte River issues a publicly available financial report for the Plan that can be obtained at www.prpa.org.

Benefits Provided

The Plan provides for 100% vesting after five years of service to all eligible employees. Retirement benefits are based upon years of service rendered and the final average compensation earned by the participant in accordance with the Plan’s provisions. The Plan provides for normal retirement at age 65. Participants who are at least age 55 and have 10 years or more of credited service may choose early retirement with a reduced benefit. A special early retirement benefit is available at age 62, with unreduced benefits, if certain years of service and age requirements are met as defined by the Plan document.

Benefits paid by the Plan are adjusted annually by the change in the consumer price index, subject to a maximum increase of 6% for employees who retired prior to December 6, 1991. Those employees who retired on or after December 6, 1991, receive two-thirds of the change in the consumer price index, up to a maximum of 4.0%.

At December 31, 2015, the measurement date, the participants in the Plan are:

fo rebmuN stnapicitraP

Retirees and beneficiaries currently receiving benefits 128 Terminated vested employees not yet receiving benefits 53

551 stnapicitrap nalp evitcA 633 stnapicitrap latoT


Page 91



December 31, 2016 and 2015 11. Defined Benefit Pension Plan (continued)

Contributions

All contributions to the Plan are authorized by the Board of Directors and made by Platte River. The Plan’s funding policy is intended to fund current service costs as they accrue, plus an additional funding charge if the market value of the assets is less than 100% of the actuarial present value of accumulated plan benefits. Platte River’s contributions to the Plan for the years ended December 31, 2016 and 2015 of $2,912,000 and $3,302,000, respectively, equaled the actuarially determined requirements.

Net Pension Liability

The net pension liability of $20,508,000 reported as of December 31, 2016 was measured as of December 31, 2015, and the net pension liability of $6,693,000 reported as of December 31, 2015 was measured as of December 31, 2014. The total pension liability used to calculate the net pension liability at the December 31, 2015 and 2014 measurement dates was determined by actuarial valuations as of January 1, 2016 and 2015, respectively.

The actuarial valuations for the December 31, 2015 and December 31, 2014 measurement dates used the following actuarial assumptions.

2015 2014

,5102 ni %0.3 %0.3 sesaercni yralaS +6102 ni %5.4

Investment rate of return 7.5% 8.0% %0.2 %5.1 gnivil fo tsoC

Mortality rates for the measurement period ended December 31, 2015 were based on the RP-2014 table for males and females combined with the MP-2014 projection scale. For the measurement period ended December 31, 2014, mortality rates were based on the RP-2000 mortality table for males and females without projection and without collar or amount adjustments.


Page 92




The long-term expected rate of return on Plan investments was based on a building-block method in which best-estimate ranges of expected future real rates of return (expected returns, net of pension plan investment expense and inflation) are developed for each major asset class. These ranges are combined to produce the long-term expected rate of return by weighting the expected future real rates of return by the target asset allocation percentage and by adding expected inflation. The estimates for each major asset class that is included in the Plan’s target asset allocation as of December 31, 2015 are summarized in the following table:

mret-gnoL laeR detcepxE tegraT

Asset Class Allocation Rate of Return %05.7 %00.81 pac egraL – seitiuqe citsemoD

Domestic equities – Mid/small cap 7.00% 8.00% %57.8 %00.01 seitiuqe lanoitanretnI %05.01 %00.4 seitiuqe tekram gnigremE %52.2 %00.8 emocni dexif eroC %57.3 %00.3 dleiy hgiH %52.5 %00.9 snaol etaroproc etar gnitaolF %52.5 %00.6 seitidommoC %57.7 %00.51 etatse laeR %05.6 %00.51 egdeh detalerroc wol diuqiL %52.7 %00.5 spihsrentrap detimil retsaM

The discount rate used to measure the total pension liability was 7.5% and 8.0% for the years ended December 31, 2015 and 2014, respectively. To determine the projection of cash flows, the following assumptions were made: employer contributions are made throughout the year and, on average, at mid-year; benefit payments are assumed to be made uniformly throughout the year and, on average, at mid-year; annuity payments are payable monthly at the beginning of the month and lump sum payments are payable on the date of decrement. Based on those assumptions, the Plan’s fiduciary net position was projected to be available to make all projected future benefit payments of current Plan members. Therefore, the long-term expected rate of return on Plan investments was applied to all periods of projected benefit payments to determine the total pension liability.


Page 93




Changes in the net pension liability for the year ended December 31, 2016, were as follows:

Total Pension Liability

(a)

Plan Fiduciary Net Position

(b)

Net Pension Liability (a) – (b)

(In thousands)

Balances at December 31, 2015 $ 98,124 $ 91,431 $ 6,693 :raey eht rof segnahC 938,1 – 938,1 tsoc ecivreS 566,7 – 566,7 tseretnI

Changes of benefit terms 2,397 – 2,397 Differences between expected and actual experience 931 – 931 Employer contributions – 3,302 (3,302)

426 )426( – emocni tnemtsevni teN – )236,4( )236,4( stnemyap tifeneB

Changes of assumptions 3,661 – 3,661 518,31 )459,1( 168,11 segnahc teN

Balances at December 31, 2016 $ 109,985 $ 89,477 $ 20,508

The changes of assumptions were due to updating the mortality table from the RP-2000 to the RP-2014 table combined with the modified MP-2014 projection scale, reducing the cost of living assumption from 2.0% to 1.5%, reducing the Plan stated interest rate assumption from 8.0% to 7.5%, and reducing the salary increase assumption from 4.5% to 3.0%.


Page 94




Changes in the net pension liability for the year ended December 31, 2015, were as follows:

Total Pension Liability

(a)

Plan Fiduciary Net Position

(b)

Net Pension Liability (a) – (b)

(In thousands)

Balances at December 31, 2014 $ 93,937 $ 87,155 $ 6,782 :raey eht rof segnahC 588,1 – 588,1 tsoc ecivreS 343,7 – 343,7 tseretnI

Differences between expected and actual experience (180) – (180) Employer contributions – 3,905 (3,905)

)856,4( 856,4 – emocni tnemtsevni teN – )782,4( )782,4( stnemyap tifeneB

Change of assumptions (574) – (574) )98( 672,4 781,4 segnahc teN

Balances at December 31, 2015 $ 98,124 $ 91,431 $ 6,693 The change of assumptions was due to a revision of the salary increase assumption from 4.5% to 3.0% due to employer experience.


Page 95




The net pension liability (asset) of Platte River at December 31, 2016 and 2015, calculated using the current discount rate, as well as what the net pension liability would be if it were calculated using a discount rate that is 1-percentage-point lower or 1-percentage-point higher than the current rate:

5102 6102

Discount Rate


Discount Rate


(Dollars in thousands)

1% Decrease 6.5% $ 31,083 7.0% $ 15,650 Current discount rate 7.5% 20,508 8.0% 6,693 1% Increase 8.5% 11,413 9.0% (1,099)

Pension Expense

The Board of Directors approved policies under GASB 62, paragraphs 476–500, that allow Platte River to recognize pension expense when recovered through rates rather than recording the amount calculated under GASB 68. For the year ended December 31, 2016, Platte River recognized pension expense of $3,284,000. Pension expense for 2016 consists of the $2,912,000 employer contribution plus $443,000 amortization of the additional funding charge and ($71,000) amortization of the difference between the 2015 contribution and pension expense as calculated by GASB 68. For the year ended December 31, 2015, Platte River recognized pension expense of $3,745,000. Pension expense for 2015 consists of the $3,302,000 employer contribution plus $443,000 amortization of the additional pension funding charge. Additional details about regulatory accounting for pension expense can be found in Note 9.


Page 96




Deferred Outflows of Resources and Deferred Inflows of Resources Related to Pensions

At December 31, 2016, Platte River reported deferred outflows of resources and deferred inflows of resources related to pensions from the following sources:

swolfnI derrefeD swolftuO derrefeD secruoseR fo secruoseR fo

(In thousands)

Differences between expected and actual 211 $ 737 $ ecneirepxe 063 898,2 snoitpmussa fo segnahC

Net difference between projected and actual earnings on pension plan investments 7,687 –

eht ot tneuqesbus snoitubirtnoC – 219,2 etad tnemerusaem 274 $ 432,41 $ latoT

At December 31, 2015, Platte River reported deferred outflows of resources and deferred inflows of resources related to pensions from the following sources:

swolfnI derrefeD swolftuO derrefeD secruoseR fo secruoseR fo

(In thousands)

Differences between expected and actual 641 $ – $ ecneirepxe 764 – snoitpmussa fo segnahC

Net difference between projected and actual earnings on pension plan investments 1,839 –

eht ot tneuqesbus snoitubirtnoC – 203,3 etad tnemerusaem 316 $ 141,5 $ latoT


Page 97




Contributions of $2,912,000 made subsequent to the measurement date and reported as deferred outflows of resources, as of December 31, 2016, will be recognized as a reduction of the net pension liability in the year ended December 31, 2017. The $3,302,000 reported as deferred outflows of resources resulting from contributions subsequent to the measurement date, as of December 31, 2015, was recognized as a reduction of the net pension liability in the year ended December 31, 2016. Other amounts reported as deferred outflows of resources and deferred inflows of resources related to pensions as of December 31, 2016 will be recognized in pension expense as follows:

Year ending December 31 (In thousands)

358,2 7102 258,2 8102 258,2 9102 392,2 0202

12. Defined Contribution Pension Plan

Effective September 1, 2010, the Board of Directors established the Platte River Power Authority Defined Contribution Plan (in accordance with the Internal Revenue Code Section 401(a)) for all regular employees hired on or after that date. As of December 31, 2016, there were 102 plan participants. The plan’s assets are held in an external trust account. The General Manager of Platte River is the Plan Administrator and benefit provisions and contribution requirements are authorized and may be amended by the Board of Directors.

Platte River contributed the required contribution of 5% of earnings for plan participants with fewer than five years of service and 7% for those with five or more years of service. Platte River will also contribute to the 401(a) an amount equal to 50% of the participant’s contributions to a separate 457(b) plan, taking into account only such participant contributions up to 6% of the participant’s earnings. For the years ended December 31, 2016 and 2015, contributions to the 401(a) plan by Platte River, which were recognized as expenses, were $662,000 and $459,000, respectively. The employer contributions to the 401(a) plan vest 100% after three years. The plan’s records are kept on the accrual basis.


Page 98



December 31, 2016 and 2015 13. Contribution of Fiber Optic Network to Municipalities

During 1998, Platte River constructed a fiber optic network between and around the four municipalities to which it provides electric service. The surplus capacity in the network built around the City of Longmont was contributed to the City of Longmont in 1998 and was recorded as a return of capital. Platte River retained ownership of the remaining fiber optic network, and in 1999, began leasing surplus portions of the dark fiber for the benefit of each of the remaining three municipalities to independent telecommunication service providers. The contributions of the fiber assets to the municipalities of $191,000 and $155,000 for the years ended December 31, 2016 and 2015, respectively, is considered a return of capital on the original asset. As of December 31, 2016 and 2015, lease advances of $740,000 and $823,000, respectively, have been recorded as a liability in the statements of net position. The municipalities’ portion of the lease payments received is flowed through to the municipalities, net of Platte River’s costs.

14. Insurance Programs

Platte River has purchased insurance policies to cover the risk of loss related to various general liability and property loss exposures. The amount of insurance settlements has not exceeded insurance coverage in the past three years. Platte River also provides a self-insured medical and dental plan to its employees. Medical stop-loss insurance has been purchased, which covers losses in excess of $175,000 per person per incident. A liability was recorded for estimated medical and dental claims that have been incurred but not reported of $446,000 at December 31, 2016 and $499,000 at December 31, 2015. A third party administrator is used to account for the health insurance claims and provides the estimated medical claims liability based on prior claims payment experience. The medical claims liability is included as a component of accounts payable in the statements of net position.

Changes in the balance of the medical claims liability during 2016 and 2015 were as follows:


Medical claims liability, beginning of year $ 499 $ 505 Current year claims and changes in estimates 3,155 2,934 Claim payments (3,208) (2,940)Medical claims liability, end of year $ 446 $ 499


Page 99



December 31, 2016 and 2015 15. Commitments

Platte River has two long-term purchase power contracts with the Western Area Power Administration. The contract with the Colorado River Storage Project continues through September 30, 2024. In March 2015, the Loveland Area Projects contract was extended through June 30, 2054. The federal hydroelectric power received in 2016 provided approximately 19% of the resources needed by Platte River to serve the loads of the four owner municipal systems. The contract rates and the amount of energy available are subject to change. During 2016, Platte River purchased $17,928,000 under these contracts.

Platte River and three of the other four participants in the Yampa Project own Trapper Mine, the primary source of coal for the Yampa Project. The contract provides for delivery of specified amounts of coal to each Yampa owner through 2020. Supplemental coal will be supplied through the year 2017 under a contract with ColoWyo Coal Company. These contracts are subject to price adjustments. During 2016, coal purchases totaled $12,607,000 from Trapper Mine and $5,044,000 from ColoWyo Coal Company.

The Rawhide Energy Station’s coal purchase and transportation agreements are under multiple-year contracts. Base prices for these contracts are subject to future price adjustments. During 2016, Platte River paid $28,518,000 for coal delivered under these agreements.

Platte River has committed to purchase Renewable Energy Certificates (RECs) for the years 2017 through 2024 with future payments of $4,300,000. During 2016, Platte River purchased $550,000 under these REC agreements. In addition, Platte River has entered into agreements to purchase renewable wind energy output of 12 megawatts from Silver Sage Windpower Project through 2027, 60 megawatts from Spring Canyon Expansion Wind Energy Center through 2039, and approximately 6 megawatts from Medicine Bow Wind Project through 2033. During 2016, Platte River purchased $9,925,000 under these renewable wind energy agreements. In October 2016, a 30 megawatt solar photovoltaic power plant, located at the Rawhide Energy Station, began commercial operation. Platte River executed an agreement with Bison Solar LLC, the owner of the facility, to purchase all the output through 2041. During 2016, Platte River purchased $604,000 under this agreement.


Page 100



December 31, 2016 and 2015 15. Commitments (continued)

Platte River and the other Yampa Project participants, in order to comply with recent environmental regulations, have agreed to upgrade the NOx emissions control equipment at Craig Unit 2 beginning in 2012. Platte River’s share of the capital costs of these upgrades, expected to be completed in 2017, is estimated to be approximately $32,921,000 of which $26,107,000 has been expended through December 31, 2016. 16. Risks and Contingencies

The owners of the Craig Station power plant, acting through Tri-State as operating agent, reached an agreement with the Colorado Department of Public Health and Environment, U.S. Environmental Protection Agency, WildEarth Guardians and the National Parks Conservation Association to revise the Colorado Visibility and Regional Haze State Implementation Plan. Under this agreement, Craig Station Unit 1 will have more stringent limits on annual emissions beginning in 2020 and will be retired by December 31, 2025. As of December 31, 2016 the decommissioning and closure costs have not been determined In the ordinary course of business, Platte River may be impacted by various legal matters and is subject to legislative, administrative, and regulatory requirements relative to environmental issues. Although the outcomes of such matters are not possible to predict, management is aware of no pending legal matters or environmental regulations for which the outcome is likely to have a material adverse effect upon Platte River’s operations, financial position or changes in financial position in the near term. Platte River obtains the majority of its power from coal generating facilities. Changes in environmental regulations could affect the cost of generation for these facilities or could require significant capital expenditures. The impacts of the recently issued Clean Power Plan are being analyzed by Platte River in order to prepare for potential CO2 related expenses. Such costs could materially affect the rates Platte River charges its customers.


Page 101


Required Supplementary Information

Schedule of Changes in Net Pension Liability and Related Ratios – GASB 68 Last 3 Calendar Years

4102 5102 6102 (In thousands) Total pension liability

949,1 $ 588,1 $ 938,1 $ tsoc ecivreS 500,7 343,7 566,7 tseretnI )531( – 793,2 smret tifeneb fo segnahC

Differences between expected and actual experience 931 (180) 86 )627( )475( 166,3 snoitpmussa fo segnahC )688,3( )782,4()236,4( stnemyap tifeneB 392,4 781,4 168,11 ytilibail noisnep latot ni egnahc teN 446,98 739,39 421,89 gninnigeb—ytilibail noisnep latoT

Total pension liability—ending (a) $ 109,985 $ 98,124 $ 93,937

Plan fiduciary net position 445,4 $ 509,3 $ 203,3 $ reyolpme – snoitubirtnoC 110,21 856,4)426( emocni tnemtsevni teN )688,3( )782,4()236,4( stnemyap tifeneB

Net change in plan fidu 966,21 672,4)459,1( noitisop yraic Plan fiduciary net position—beginning 91,431 87,155 74,486 Plan fiduciary net position—ending (b) $ 89,477 $ 91,431 $ 87,155

Net pension liability—ending (a) – (b) $ 20,508 $ 6,693 $ 6,782 Plan fiduciary net position as a percentage of the total

pension liability

81.35% 93.18% 92.78%

Estimated covered employee payroll $ 17,305 $ 17,951 $ 18,614

detamitse fo egatnecrep a sa ytilibail noisnep teN %34.63 %92.73 %15.811 lloryap eeyolpme derevoc

Note to Schedule

Historical information is not available for the years 2007 through 2013; additional years will be displayed as they become available until 10 years of historical data are presented.


Page 102

Plat

te R

iver

Pow

er A

utho

rity

Re

quire

d Su

pple

men

tary

Info

rmat

ion

Sc

hedu

le o

f Em

ploy

er C

ontri

butio

ns –

GA

SB 6

8 La

st 10

Cal

enda

r Yea

rs

7002

8002 9002

0102 1102

2102 3102

4102 5102

6102

(I

n th

ousa

nds)

Act

uaria

lly d

eter

min

ed c

ontri

butio

n $

2

,912

$

3,3

02$

3

,905

$

4,5

44$

3

,561

$

4

,390

$

7,7

36$

2

,867

$

2,6

73$

2

,737

Co

ntrib

utio

n in

rela

tion

to th

e

ac

tuar

ially

det

erm

ined

con

tribu

tion

2,91

23,

302

3,90

54,

544

3,56

14,

390

7,73

62,

866

2,67

32,

737

Cont

ribut

ion

defic

ienc

y (e

xces

s)

$

–$

–

$

–$

–

$

–$

–

$

–$

1

$

–$

–

Estim

ated

cov

ered

em

ploy

ee p

ayro

ll $

16,

874

$ 1

7,30

5$

17,

951

$ 1

8,61

4$

18,

766

$ 1

8,72

8$

17,

714

$ 1

8,52

1$

16,

320

$ 1

5,29

0 Co

ntrib

utio

ns a

s a p

erce

ntag

e of

es

timat

ed c

over

ed e

mpl

oyee

pay

roll

17.2

6%19

.08%

21.7

5%24

.41%

18.9

8%23

.44%

43.6

7%15

.47%

16.3

8%17

.90%

N

otes

to S

ched

ule

V

alua

tion

date

:

Act

uaria

lly d

eter

min

ed c

ontri

butio

n ra

tes a

re c

alcu

late

d as

of J

anua

ry 1

, tw

o ye

ars p

rior t

o th

e en

d of

the

cale

ndar

yea

r in

whi

ch c

ontri

butio

ns a

re re

porte

d.

M

etho

ds a

nd a

ssum

ptio

ns u

sed

to d

eter

min

e co

ntrib

utio

n ra

tes:

A

ctua

rial c

ost m

etho

d

Fr

ozen

initi

al li

abili

ty, e

ntry

age

nor

mal

A

mor

tizat

ion

met

hod

5-ye

ar, l

evel

dol

lar,

open

per

iod

Ass

et v

alua

tion

met

hod

4-ye

ar sm

ooth

ed m

arke

t

S

alar

y in

crea

ses

3.

2%, a

vera

ge

Cos

t of l

ivin

g ad

justm

ents

For p

artic

ipan

ts in

pay

stat

us p

rior t

o 1/

1/92

– 3

.00%

, for

all

othe

r par

ticip

ants

– 2.

00%

In

vestm

ent r

ate

of re

turn

7.

5% fo

r 201

6; 8

.0%

for 2

015

– 20

07


Page 103


Other Information

Budgetary Comparison Schedule (Unaudited)

Year Ended December 31, 2016

duB get Actual Variance (In thousands) Revenues Operating :seunever Municip 895,581$ selas la $ 185,214 $ (384) Short-term surp 002,03 selas sul 20,079 (10,121)Total operating 897,512 seunever 205,293 (10,505)

Nonoperating revenues: Interest income(1) 1,027 1,075 48

456 emocni rehtO 846 192Total nonoperating 186,1 seunever 1,921 240

974,712$ seunever latoT $ 207,214 $ (10,265)

Expenditures Operating expenses(2): Purchased power 362,43$ $ 33,270 $ 993 Fuel exp 789,45 esne 46,361 8,626 Production exp 810,84 sesne 44,632 3,386 Transmission exp 637,31 sesne 12,798 938 Administrative and g 019,81 larene 17,366 1,544Total operating exp 419,961 sesne 154,427 15,487

Debt service expenditures(3): Interest exp 435,01 esne 10,066 468 Princip 917,02 la 20,660 59

Allowance for funds used during construction (263) (1,137) 874Total debt service expenditures 30,990 29,589 1,401

Capital additions: Production 318,62 19,963 6,850

033,51 noissimsnarT 13,031 2,299215,5 lareneG 5,390 122

Total cap 556,74 snoitidda lati 38,384 9,271

Total exp 955,842$ serutidne $ 222,400 $ 26,159 Revenues less expenditures $ (31,080) $ (15,186) $ 15,894

__________

(1) Interest income excludes unrealized investment holding gains and losses. (2) Operating expenses do not include depreciation and other nonappropriated expenses. (3) Debt service expenditures represent monthly principal and interest funding.


Page 104

Page 105

Page 106



From: Jason Frisbie, General Manager/CEO Karin Hollohan, Chief Administrative Services Officer

Subject: HQ Campus During the April meeting, the design team will present an overview of the schematic design process to date. They will also share high level results from the initial meeting with the City of Fort Collins planning department. No decisions from the Board are required at the April meeting. In May, we plan to review the final schematic design report, an updated cost model, and the project communications plan for external stakeholders. The May meeting is one of the two remaining milestone check in points with the Board prior to beginning construction, to ensure you remain comfortable with the progress and direction of the Headquarters Campus project.

Page 107

Page 108



From: Jason Frisbie, General Manager/CEO Andy Butcher, Chief Operating Officer Paul Davis, Customer Services Manager

Subject: Demand Response Update Demand response (DR) programs are programs aimed at affecting when customers use electricity in an effort to improve system reliability or reduce system costs. Each municipality currently operates one or more DR programs aimed at reducing its wholesale coincident demand costs. Platte River, Longmont, and Fort Collins staffs have been working to implement a DR pilot program. Loveland and Estes Park opted not to participate in the pilot, but are interested in the results of the pilot and may participate in future versions of the program. A project charter was signed during the fall of 2015. The goal of the DR pilot is to explore how the participating municipalities’ DR could be operated by Platte River to provide maximum benefits to the overall system (integrated wholesale and retail levels). The pilot is intended to identify improved methods for allocating system DR benefits to the municipalities in proportion to the verifiable and reliable DR resource provided. Staff will give a presentation on the current status of the DR pilot and discuss next steps during the April Board meeting.

Page 109

Page 110



From: Jason Frisbie, General Manager/CEO Joe Wilson, General Counsel

Subject: Board Governance Process Document This memo and the attached White Paper are intended as a first step in a process that the Board may choose to initiate. As discussed generally before, staff suggests that the organization may benefit from formalized procedural guidance for the conduct of meetings and also may wish to either adopt, discard or re-examine some of informal practices that have grown up over the history of the organization. In this context, the purpose of the White Paper is to briefly relate the history and current status of some issues that have been raised by Board members in the recent past.

Each of the member municipalities and a number of other political subdivisions in Northern Colorado have adopted specific procedures for the conduct of meetings of their governing bodies. In anticipation that the Board may believe formal procedures are appropriate, staff reviewed the procedural guidance adopted by the member municipalities and other political subdivisions. If the Board so directs, at the May Board meeting staff will present an outline of general procedures the Board can review and discuss.

This outline will largely be based on the procedures found in member municipality processes, and will formalize the parliamentary procedure the Board currently follows, including the incorporation of some or all of Robert’s Rules of Order. The document resulting from Board direction can also provide guidance on any of the issues noted in the White Paper, as well as for any other “gaps” noted by the Board.

Attachment

Page 111

Page 112

Board Meeting Process Whitepaper

April 19, 2017

As the Board is aware, before assuming its current status as a political subdivision Platte River Power Authority existed as a Colorado non-profit corporation. Both Articles of Incorporation and Bylaws existed for the non-profit corporation, and these touched on some issues associated with the conduct of meetings – but not in the detail compared, for example, with the procedural guidance developed by the member municipalities.

When Platte River was formed as a political subdivision the Articles of Incorporation and Bylaws of the non-profit corporation provided much of the basis for the initial Organic Contract adopted in 1975, and some of that language still exists in the present Organic Contract. However if the Board chooses to adopt more detailed procedures for the conduct of meetings there are reasons why it may make sense to create these as a separate procedures document adopted through resolution rather than re-opening the Organic Contract. First, under the enabling statute, C.R.S. § 29-1-204, the Board has broad authority “to adopt, by resolution, regulations

respecting the exercise of its powers…” and need not modify the Organic Contract to create such procedures. Second, in addition to being unnecessary, modifying the Organic Contract is cumbersome and impedes the flexibility of the Board to revise procedures if practice dictates the need for change.

In addition to the potential need for a more formalized process document, recent Board conversations have raised a few issues for which there is either incomplete guidance in the Organic Contract or a history of informal practice. The list below attempts to capture existing process or identify gaps. The list is not meant to be an endorsement of current practice, but rather is an attempt to tee up some issues for future discussion. The Board may or may not want to incorporate guidance on these issues in any future process document.

Term limits for Chair – The Organic Contract makes provision for the election of officers to serve a term of one year. Presently there are no limits on the number of one-year terms that the Chair or Vice Chair may serve. Some have served less than one term, but some have served for extended periods - Ralph Mullinix served as Chair from 1999 to 2010.1

Inclusion of elected officials as Chair/Vice Chair – The Organic Contract was amended in 1976 to expand the Board from four to eight members, specifically including the mayors (or their council member designee) as members. The Organic Contract doesn’t contain any requirement that an elected official serve as Chair/Vice Chair. No mayor has served as Chair, but five elected officials have served as Vice Chair:

o J. D. Bilderback, Loveland city council, 1978 – 1981; o William Swenson, Longmont mayor, 1982 – 1985; o Barbara Rutstein, Fort Collins city council, 1986 – 1987; o Doug Hutchinson, Fort Collins mayor, 2007 – 2010; o Bill Pinkham, Estes Park mayor, 2011 – 2015).

1 See attached spreadsheet for a history of Chair/Vice Chair tenure and representation.

Page 113

The Chair has always been a utility director, although Richard Widmer from Estes Park held the title Assistant Town Administrator.

Rotation of Chair – The Organic Contract doesn’t require rotation of the Chair among the municipalities. As follows is the rotation beginning in 1971:

o Fort Collins, 1971 – 1977; o Longmont, 1978 – 1982 o Estes Park, 1982 – 1985 o Loveland, 1986 o Estes Park, 1986 – 1990 o Fort Collins, 1991 – 1993 o Longmont, 1993 – 1995 o Estes Park, 1996 – 1998 o Loveland, 1999 – 2010 o Fort Collins, 2011 o Longmont, 2011 – 2017

Since 1991 the rotation has been Fort Collins, Longmont, Estes Park then Loveland, but that rotation is not established in any formal sense and did not apply during prior years. In rough numbers, a representative from Fort Collins has served as Chair 10 years, Longmont 14 years, Loveland 12 years and Estes Park 10 years.

Leadership Team – There is no formal provision for a Leadership Team. Some municipalities have made provision for a Leadership Team composed of the Mayor and Mayor Pro Tem to meet with staff on agenda development and for coordination with council members between meetings.

Trapper Mine representation – The Organic Contract doesn’t provide guidance, but

since at least the tenure of Ralph Mullinix as Chair, the Chair and General Manager have served on the Board of the Trapper Mine.

Change in management – Prior to 2010 the Organic Contract provided that in the absence of a General Manager the Chair would serve as General Manager. This guidance was not followed in practice; in periods during which there was no General Manager prior to 2010 an interim was appointed. The 2010 Organic Contract formalized this stating that “When and while a vacancy exists in the office of General Manger, the

Board of Directors shall appoint a qualified interim General Manager….” In the most recent change in management there was no interim appointment because there was no vacancy period. Beyond these provisions there is no direction on the mechanics of replacement - how the Board makes a decision, what level of public process is required, and whether and how a search for candidates will be conducted. Prior to the most recent appointment the recruitment of the General Manager involved the retention of a national search firm.

Conflicts involved in multiple board representation – Serving on the Board involves fiduciary responsibilities. At least half of the Board – the mayors – will also have a fiduciary relationship with their member municipality. Although state statutes define certain ethical standards regarding conflicts of interest, there is no real statutory guidance in regards to conflicting fiduciary responsibilities. During the discussion concerning potential conflicts associated with the acquisition of additional Windy Gap

Page 114

storage the issue of conflicts inherent in multiple board memberships was discussed. The guidance contained in the Fort Collins code was brought before the Board and may be a good starting point if the Board believes that guidance is necessary.

Annual Meeting – The Organic Contract requires that an Annual Meeting be held within the first 120 days each year. the Annual Meeting must be held in Fort Collins. Recently the Annual Meetings have been limited to just the functions required in the Organic Contract – election of officers, reports on the previous year, and other business that may come before the meeting including the appointment of the Retirement Committee. During the early years of the organization the Annual Meeting was much more involved and included guest speakers and invitations to member councils.

Contract Approvals – During the early years of Platte River before the advent of a fully developed professional staff all contracts were approved by the Board. Over time most contracts are now approved by management and reported to the Board. The exceptions are intergovernmental agreements, most typically agreements with member municipalities, which by statute must be brought before the Board.

As noted in the cover memo this list is meant to contain some of the issues that the Board may want to consider if it moves forward with a process to formalize a procedures document. The list is not exhaustive, and the Board may see gaps that it may want to add to the discussion. Such input on possible gaps may be provided at the upcoming meeting or later as this iterative process develops.

Page 115

Page 116

Year Chairman Position Vice-Chairman Postion

July 7, 1971 Stanley R. CaseFC - Director of Electric

UtilitiesDon Hataway LV - City Manager

Jan. 17, 1972 Stanley R. CaseFC - Director of Electric




Stanley R. CaseFC - Director of Electric


June 17, 1975 Stanley R. CaseFC - Director of Electric



UtilitiesJerry Trotter LGMT - Director of Utilities

Feb. 18, 1977 Stanley R. CaseFC - Director of Electric

UtilitiesJerry Trotter LGMT - Director of Utilities

April 20, 1978 Jerry Trotter LGMT - Director of Utilities J.D. Bilderback LV - Councilmember



April 30, 1981 Jerry TrotterLGMT - Former Director of

Utilities? (Per 1981 Annual J.D. Bilderback LV - Councilmember

Jan. 21, 1982 Jerry TrotterLGMT - Former Director of

Utilities? (Not in the 1982 Robert L. Dekker

EP - Light and Power

Director

April 29, 1982 Robert L. DekkerEP - Light and Power

DirectorWilliam G. Swenson LGMT - Mayor







April 24, 1986 Dieter P. Wirtzfeld LV - Electric Superintendent Barbara S. Rutstein FC - Councilmember

Oct. 24, 1986 Robert L. DekkerEP - Light and Power

DirectorBarbara S. Rutstein FC - Councilmember

Feb. 26, 1987 Robert L. DekkerEP - Light and Power

DirectorBarbara S. Rutstein FC - Councilmember

May 7, 1987 Robert L. DekkerEP - Light and Power

DirectorRichard H. Shannon FC - Utilities Director





March 22, 1990 Robert L. DekkerEP - Light and Power


May 2, 1991 Richard H. Shannon FC - Utilities Director Brian H. MoeckLV - Director of Power and

Light

April 30, 1992 Richard H. Shannon FC - Utilities Director Jeffrey A. GouldLGMT - Director of Electric

Department

April 29, 1993 Richard H. Shannon FC - Utilities Director Jeffrey A. GouldLGMT - Director of Electric

Department

July 29, 1993 Jeffrey A. GouldLGMT - Director of Electric

DepartmentBrian H. Moeck

LV - Director of Power and

Light

Feb. 3, 1994 Jeffrey A. GouldLGMT - Director of Electric

DepartmentRichard Widmer

EP - Assistant Town

Administrator

April 28, 1994 Jeffrey A. GouldLGMT - Director of Electric


EP - Assistant Town

Administrator


Chairman / Vice-Chairman

Page 1 of 2

Page 117

Year Chairman Position Vice-Chairman Postion

April 27, 1995 Jeffrey A. GouldLGMT - Director of Electric


EP - Assistant Town

Administrator

April 25, 1996 Richard WidmerEP - Assistant Town

AdministratorRalph Mullinix

LV - Water and Power

Director

Feb. 28, 1997 Richard WidmerEP - Assistant Town



Director




Director




Director

April 22, 1999 Ralph MullinixLV - Water and Power

DirectorMichael B. Smith

FC - General Manager, FC

Utilities

Feb. 24, 2000 Ralph MullinixLV - Water and Power



Utilities




Utilities




Utilities




Utilities




Utilities




Utilities




Utilities




Utilities

July 26, 2007 Ralph MullinixLV - Water and Power

DirectorDoug Hutchinson FC - Mayor







Feb. 24, 2011 Brian JanonisFC - Utilities Executive

DirectorTom Roiniotis

LGMT - General Mgr, Lgmt

Power & Communications

Sept. 29, 2011 Tom RoiniotisLGMT - General Mgr, Lgmt

Power & CommunicationsBill Pinkham EP - Mayor

Feb. 23, 2012 Tom RoiniotisLGMT - General Mgr, Lgmt









Power & CommunicationsReuben Bergsten EP - Utility Director


Power & CommunicationsReuben Bergsten EP - Utility Director

Page 2 of 2

Page 118



From: Jason Frisbie, General Manager/CEO Andy Butcher, Chief Operating Officer Brad Decker, Strategic Planning Manager

Subject: Additional Wind Opportunity Included in this month’s Board packet is a briefing document prepared by Platte River staff on the near-term contract price expectations for wind generation. The briefing document presents some of the key drivers that can affect wind pricing in the near-term. The information in this report can help inform the Board of Directors and their communities of potential opportunities in the timing of wind resource acquisitions—at both the Platte River and community levels. Attachment

Page 119

Page 120

1

Whitepaper to Platte River Board of Directors Report on Wind PPA Price Trends Presented for the April 2017 Board Meeting Overview

The utility-scale wind market has been remarkably dynamic, since the year 2000, with installed capacity growing at an average annual rate in excess of 20 percent in the USA. During this period, a variety of drivers have caused wind prices to change significantly. The market appears to be at a historically low point, relative to past offers and contract prices, and future prices are expected to rise. Platte River believes that it would be practical to take advantage of the current wind market by

adding a manageable amount of low-cost wind, before prices begin to rise. Wind Pricing Platte River expects near-term wind pricing to rise, primarily due to the expiration of the Federal Production Tax Credit (PTC). Exhibit 1 depicts the PTC-driven expectations for future prices relative to historical contract rates and current indicative quotes for wind power. This section also discusses other impacts that affect near-term expectations for the price of wind power. Exhibit 1 – Projections for Wind Contract Pricing

$80

$70

$60

$50

$40

$30

$20

$10

1998 2009 2014 2016 2017 2020

Recent

Quotes

Impact of PTC

Expiration

Prices

nearly

double

Approximate price trend

from historical Platte

River contracts

$/M

Wh

Page 121

2

Production Tax Credits (PTC) - For the past 25 years, the Federal government has periodically provided wind suppliers with a financial incentive through the PTC. The PTC provides a tax credit to project owners for every MW generated during the first 10 years of the life of the project. The PTC is currently set at approximately $22/MWh but is set to fully expire, according to the schedule in Exhibit 2. Exhibit 2 – Schedule for Expiration of Federal Wind Production Tax Credit

Year Eligible

Share of PTC

Reduction in

PTC (Potential Price Impact, $/MWh)

2016 100% $0 2017 80% $4.38 2018 60% $8.77 2019 40% $13.15 2020 0% $21.92

The PTC has expired several times, with subsequent renewals, resulting in periodic boom-and-bust cycles within the wind industry. Industry analysts feel that the most recent PTC extension is designed to be the last extension and that no further PTC benefits are expected. Developers that purchased “safe-harbored” wind equipment prior to 2017 can still take advantage of the full PTC, if the equipment is installed and commercially operational by the end of 2019. The planned expiration of the PTC represents a significant, well-known impact that will affect wind prices in the near future; nearly doubling prices by 2020 in the absence of offsetting impacts. To encourage demand, wind project developers may deploy price mitigation strategies such as assuming lower returns on capital or modifying finance structures to soften the impact of the PTC expiration. Manufacturing Efficiency - Manufacturers have improved their production efficiency and are expected to continue to bring down the cost of their equipment which would translate into lower prices for off-takers. Industry analysts feel that wind generation equipment is nearing technological maturity so new gains are likely to be incremental rather than disruptive. Platte River’s planning

consultant, Pace Global, expects the annual cost reductions related to manufacturing efficiency to be in the 1.0 percent range (adjusted for inflation), as shown in Exhibit 3. Although costs are expected to decrease by approximately 12 percent by 2025, the impact of the PTC expiration could result in wind costs rising by nearly 100 percent.

Page 122

3

Exhibit 3 – Change in Construction Costs for On-Shore Wind vs. 2016 Costs (Real $2016)

Clean Power Plan - Upward price pressures may occur, due to the uncertainty regarding the EPA’s Clean Power Plan (CPP). The wind industry expected to incur significant growth under the CPP, but the plan’s delay will likely slow the wind industry down, at least temporarily. In the near-term, price impacts could be moderated somewhat as developers seek to shed projects and inventory that was built up in anticipation of increased CPP-related sales. There is a finite stock of this existing inventory so the price mitigation may be short-lived. In the long-term, if the shift from carbon mitigation is permanent, industry consolidation may result in fewer firms and reduced competition which would indicate potentially higher prices. Corporate Tax Rates - Additional upward price pressure on wind projects may arise from decreased corporate tax rates and, since project profitability relies on the ability to finance projects through tax equity, developers are wary of this. Although highly uncertain, there is eagerness from the current presidential administration to enact corporate tax cuts which could reduce the efficacy of tax-equity financing.

Platte River’s Situation Assessment

Platte River has been an active participant in the wind market for 20 years and currently has 78 MW of wind resources in its portfolio. Platte River has taken a measured approach to adding wind over time and has incrementally added wind to its portfolio to take advantage of prices, performance, and location. Exhibit 1 plots historical wind additions and pricing data which shows projections for future price trends. As the chart demonstrates, Platte River faces a unique opportunity in 2017. Decades of wind price decreases are likely to end, with the expiration of the PTC, and wind will instead become more expensive. While there is no statutory need to further deepen Platte River’s renewable portfolio, in our most recent Integrated Resource Plan, Platte River committed to monitoring the market to take advantage of favorable pricing which appears to be the current condition.

-15%

-10%

-5%

0%

2017 2018 2019 2020 2021 2022 2023 2024 2025

Page 123

4

Initial estimates, based on Platte River’s production cost models, indicate that first-year rate impacts for 50 MW of additional wind are approximately 1.3 percent to 2.2 percent. Overall lifetime impacts range from -0.2 percent to 0.7 percent. Indeterminate transmission costs are the primary source of uncertainty in these estimates. Staff will prepare project-specific rate impacts and provide details at the May Board meeting. Other Considerations

In October 2016, Platte River presented information to the Board on the operational impacts of wind. Since the system currently manages a long energy position with limited market depth (typically 75-100 MW are sold per hour), adding more wind energy could have an impact on the operation of existing resources. As seen in Exhibit 5, higher penetrations of wind may crowd out coal generation which would result in lost surplus sales from a unit that incurs fixed costs regardless of operation. These impacts are dependent on market conditions and represent a risk that should be balanced against the potential benefits of additional wind. These impacts are implicitly modeled in Platte River’s production cost

analysis processes.

Exhibit 5 – Operational Impacts to Platte River’s Existing Resources

Page 124

5

Conclusions

Current wind projects offer pricing that is at historical minimums and lower than current expectations for near-term future prices. Platte River is confident that it can accommodate an additional share of wind under the operational and rate impacts that are currently expected. Stakeholder desire to maintain a diverse portfolio, uncertainty around future carbon pricing, and expected future price increases underscore the benefits of taking advantage of current market prices. Platte River routinely interacts with developers to assess the potential for adding renewable resources and has several current indicative offers with favorable pricing. If the Board agrees to pursue an additional wind investment, Platte River can directly engage a third-party, as was done with the second Spring Canyon purchase in 2014. Platte River management and staff recommend that a manageable increment of wind resources (25-

75 MW) be pursued for contract by the end of 2017, with the expectation of energy delivery by the

end of 2019. Staff will be prepared to present a detailed analysis, including potential rate impacts

and future market impacts, to support their recommendation at the May Board meeting.

Page 125

Page 126

Memorandum

0BDate: April 19, 2017

1BTo: Board of Directors

2BFrom: Jason Frisbie, General Manager/CEO

3BSubject: March Board Work Session Follow-Up

High level summaries for each of the four strategic issues discussed at the March 30, 2017 Board work session are provided below. Rates Staff will continue to emphasize cost recovery, simplicity, and stability as guiding principles in wholesale rate design. Additionally, Platte River will consider enhancing system benefits through appropriate rate structures. Next steps include developing a proposed rate setting policy for the Board’s future consideration. Once a policy is established, we can refine scope, schedule and staff resources required to analyze future rate design options, which may be brought to the Board over the longer term. Distributed Energy Work on developing a detailed Distributed Energy Resource (DER) strategy will continue. This can move forward primarily through collaborative efforts of the newly created DER subcommittee of the Joint Technical Advisory Committee. This DER subcommittee was formed in late 2016, with staff participating from each of the four municipal utilities and Platte River. Paul Davis is currently serving as chair of the subcommittee (Paul is Manager of Customer Services at Platte River). Consolidated Services vs. G&T From inception through the 1990’s, Platte River was strictly focused on generation and transmission services to the owner municipalities. Over the last two decades, a number of additional Platte River services have evolved, driven by economies of scale and other benefits associated with leverage and collaboration. These include a joint Customer Information System, energy efficiency services through the Efficiency Works brand, and distribution system maintenance (among others). Additional services are being evaluated at this time, including Demand Response and Community Solar. Going forward, we plan to continue evaluating new service opportunities on a case-by-case basis and will bring specific recommendations to the Board for consideration. Long-Range Planning The 2016 Integrated Resource Plan (IRP) suggests a path forward for developing our future electric resource portfolio to ensure reliability, manage risks, and meet regulatory compliance. The IRP includes the following action items:

1. Pursue a strategy to exit Platte River’s share of Craig Unit 1(complete)

Page 127

MEMO – March Board Work Session Follow-Up

April 2017 Page 2 of 2

2. Integrate 30 MW of new solar generation into the portfolio (complete) 3. Evaluate the acquisition of additional renewable generation (ongoing) 4. Work with member communities to develop customized future supply portfolios (currently in

phase 1) 5. Continue expansion of cost-effective energy efficiency programs per Board policy (ongoing) 6. Continue development and implementation of a demand response pilot (ongoing) 7. Participate with member-owners in the development of distributed technologies (ongoing)

Board discussion seemed to endorse continued focus on these items (approved as part of the IRP in May 2016). In addition, the Board generally supported our current approach of including potential for future climate policy in resource portfolio modeling.

Page 128

Memorandum

Date: April 19, 2017


From: Joseph B. Wilson, General Counsel

Subject: PLATTE RIVER LEGAL AND GOVERNMENTAL AFFAIRS REPORT – APRIL 2017 BOARD MEETING

The following legal issues and governmental/legislative matters were addressed during the reporting period; bold-faced type is used to highlight recent or significant developments. LEGAL ISSUES: CURRENT OR THREATENED LITIGATION El Paso Electric Co. vs. Federal Energy Regulatory Commission (FERC) — Over the last four years Platte River has been engaged in a regional transmission planning process under the auspices of WestConnect, a planning organization formed by the utility participants. The WestConnect footprint covers a vast area generally corresponding with boundaries of the states of Arizona, Colorado, Nevada, New Mexico, Utah, and Wyoming. The planning effort was implemented in response to FERC Order 1000 issued in 2011. Order 1000 requires FERC-jurisdictional utilities to create regional transmission planning organizations with authority to plan transmission expansions and allocate costs to the beneficiaries of the new transmission projects. Unlike the Eastern Interconnection (generally all areas of the United States east of Colorado excluding most of Texas), the Western Interconnection contains a much larger population of non-jurisdictional utilities – of which Platte River is one. In the WestConnect footprint the breakdown of the transmission-owning utilities include ten non-jurisdictional utilities and eleven jurisdictional entities. This heavy presence of non-jurisdictionals accounts for the slower market development in the western United States. Non-jurisdictionals are concerned about the mandatory cost allocation provisions of Order 1000. To address this concern, WestConnect developed a transmission planning and development format that included two classes of participants, jurisdictional transmission owners were grouped into one class and non-jurisdictionals were allowed to enroll as “Coordinating Transmission Owners” (CTOs). CTOs could opt-out of cost allocation, although incentives were provided for their participation in future developments. FERC approved this planning/development format. El Paso Electric Co. and a number of other jurisdictional utilities challenged the FERC decisions approving the WestConnect process. These utilities argued that FERC approval violated the mandate that FERC approve only rates that were “just and reasonable” and, that absent a strong correlation with cost causation, rates would necessarily be unjust and unreasonable. On August 8, the Fifth Circuit Court of Appeals agreed with El Paso and remanded the case to the FERC. The non-jurisdictional participants in WestConnect collectively filed a joint petition requesting the Fifth Circuit reconsider its August 8 order. Reconsideration was denied and the matter will be re-litigated before the FERC.

Page 129

Legal and Governmental Affairs Report April 2017 Page 2 of 5

The proceedings on remand before the FERC were recently complicated by the resignation of Chairman Norman Bay. His resignation leaves the FERC without a quorum, which state of affairs may exist for some period of time. This may not present a significant issue for Platte River because if the Mountain West Transmission Group moves forward with the creation of an RTO regional planning functions for the RTO footprint will likely be assumed by the RTO, which may lead to withdrawal from WestConnect. If this occurs, the results of the remand may be irrelevant to Platte River and the issue of cost allocation will be decided through the RTO. ONGOING AND CURRENT MATTERS OF SIGNIFICANCE Renewed Interest in Oil and Gas Development — Recently Platte River was again approached about leasing the mineral rights it holds under the Rawhide property. The entity making the request is Montana Oil Properties Inc. Their business plan seems to involve redeveloping areas that were unsuccessfully developed previously. They are focusing on the area previously drilled by Marathon. Our 5,000 surface acres is within a larger 20,000 plus acre target area of interest, which does not appear at present to include the Fort Collins properties north of Rawhide. A law firm has been selected to assist in reviewing the proposed oil and gas lease agreement. The firm represents landowners and mineral owners exclusively (not oil and gas producers), and has extensive experience negotiating oil and gas leases in Colorado. Platte River’s primary concern is the protection of its infrastructure. Accordingly, non-standard terms and conditions must be incorporated into any lease agreement to address these concerns. Grand Lake Clarity NEPA Process — Platte River is a coordinating agency in the Grand Lake Clarity National Environmental Policy Act (NEPA) process initiated by the Bureau of Reclamation. This proceeding could affect Platte River as both a participant in the Windy Gap Project and as a power customer of the Western Area Power Administration. The kick-off meeting occurred on February 10 in Golden, CO. At present the matter will proceed as an Environmental Assessment (EA), but may convert to an Environmental Impact Statement (EIS). A “visioning process” yielded a number of capital projects that address the clarity issue, but the range of alternatives will be expanded to analyze operational modifications that could improve clarity. The draft “purpose and need” statement developed by BOR was discussed during a March 31 conference call. A revised draft will be circulated. Environmental Protection Agency Clean Power Plan — On February 9, 2016, the Supreme Court stayed the Clean Power Plan (CPP) rule pending full judicial review. It is unlikely that such review will be complete until 2017 or possibly 2018. This creates significant uncertainty about future compliance planning efforts. Initially Governor Hickenlooper announced that the state planning process would continue during the stay, but subsequent to the November election state planning efforts have effectively ceased. President Trump issued an Executive Order on March 28, 2017 that directed the Administrator of the EPA to take actions to rescind the CPP. The Administrator was further authorized to notify the Attorney General to delay further litigation concerning the CPP while the efforts to rescind the rule are underway. The Attorney General filed a motion to suspend the litigation on March 29, which effort is being opposed by supporters of the CPP rule through responsive filings. Operations at Glen Canyon Dam — The Bureau of Reclamation and National Park Service are jointly preparing an Environmental Impact Statement (“EIS”) to evaluate operations at Glen Canyon Dam over the next twenty (20) years. In this instance the EIS process is referred to as the Long-Term Experimental and Management Plan, or LTEMP. Glen Canyon is the largest hydropower facility in the family of the

Page 130


Colorado River Storage Project (“CRSP”) hydropower units, which also includes the Aspinall Units on the Gunnison River and Flaming Gorge on the Green River. The outcome of the LTEMP process is important to Platte River because the selected alternative could reduce operational flexibility and reduce available hydropower for purchase. The EIS addresses a number of factors related to water releases from Glen Canyon and flow levels down river through Grand Canyon National Park, including hydropower, endangered fish recovery, recreation, and sediment transport. In accordance with the National Environmental Policy Act, Reclamation and the Park Service have developed seven alternatives that are being evaluated in the EIS. The alternatives range from a “No Action” alternative to implementation of “steady flows.” The Final EIS was released on October 7. The Record of Decision (ROD) was published on December 15, 2016. The chosen alternative included a number of improvements proposed by the Colorado River Energy Consumers Association (CREDA), including limits on “high flow experiments” to only the fall months and increased ramping rates. With the results of the November election, CREDA members will be deciding whether further efforts to alter the LTEMP outcome are worth pursuing. Coal Combustion Residuals (“CCR”) Rule Implementation — As described in the management report, legal counsel is supporting staff in their evaluation of compliance issues relating to the Federal CCR Rule. The State has recently discontinued its effort to adopt CCR regulations. At least for now, the State has taken the position that they have sufficient authority to ensure environmental protection under their existing programs. On January 17, 2017 Platte River staff met with the Colorado Department of Public Health and Environment (CDPHE) in Denver. During this meeting, the existing operational plan for the monofill was discussed along with the need for a revised plan. As a result of the meeting, Platte River staff has taken steps toward bringing the plan up to current standards. These steps include increased groundwater monitoring and an evaluation of the existing topsoil cover. Windy Gap Firming Project — The Windy Gap Firming Project (WGFP) continues to obtain necessary state and federal approvals. The last major outstanding permit is the Section 404 permit issued by the U.S. Army Corps of Engineers. This permit is expected to be issued in early 2017. Also in early 2017, Northern Water will submit a water court application to amend the existing Windy Gap water court decrees. Specifically, Northern Water will be seeking to incorporate the terms of a 2012 IGA entered into with several West Slope entities. The 2012 IGA provides for the construction of Chimney Hollow Reservoir and the storage of up to 90,000 acre-feet of water provided Northern Water complies with specified mitigation measures. Northern Water is the holder of the Windy Gap Water Rights and will therefore be the lead applicant on the water court application. Nevertheless, questions may arise throughout the legal proceeding on which Northern Water may request the input or consent of the governing bodies of the Windy Gap participants. As discussed in the Management Report, Legal is supporting Finance on a request for a Private Letter Ruling from the Internal Revenue Service. CONTRACTUAL MATTERS Power Production Outage Contracts — The Deputy General Counsel is assisting staff in negotiating contracts for equipment to be supplied and services to be performed during the Fall 2018 plant outage. Negotiations

Page 131


with Siemens Energy, Inc. (“Siemens”) for the purchase of a new generator rotor have been successful. A purchase order has been sent to Siemens. There is a twenty-four (24) month lead-time related to this purchase. In addition, an Alliance Agreement has been executed with Siemens which will allow Platte River to obtain preferred pricing during the next ten (10) year period. A mechanical contractor repair and maintenance services agreement has also been executed with Siemens. Outage projects including a stator rewind will be performed under this services agreement. GOVERNMENTAL AFFAIRS: Colorado General Assembly — As a result of the November elections the make-up of the Colorado General Assembly remains functionally identical to the make-up during the 2016 session – the Democratic Party controls the Colorado House and the Republican Party controls the Colorado Senate. The session commenced on January 11 and will adjourn no later than May 10. As of the date of the April Board meeting there will only be 13 more days in the session. A number of bills were identified for tracking, most of which have died:

SB17-042 – Repeal of Existing Restrictions on the Ability of a Local Government to Provide Certain Electronic Communications Services – This bill repeals the restrictions established by Senate Bill 52, which require voter approval for local governments to offer certain telecommunications services. Postponed indefinitely by the Business, Labor and Technology Committee on February 13.

SB17-089 – Concerning the Rights of Consumers of Electricity to Install Electricity Storage Systems on their Property – Required a PUC rulemaking during 2017 on storage systems. Bill contained a jurisdictional issue for municipal utilities through a requirement that such utilities “substantially comply” with the PUC rule. The sponsor agreed to amend this provision, but the bill was killed in the Business, Labor and Technology Committee on February 8. Both Public Service Co. and Black Hills Energy opposed the bill.

SB17-105 – Concerning Consumer’s Right to Know their Electric Utility Charges – This bill only applies to investor-owned utilities. It requires IOUs to file a new bill format with their next rate proceeding. The bill contains a long list of information that must be included on utility bills.

SB17-145 – Concerning Modification to the Electric Utility Resource Acquisition Process – Requires regulated utilities to file a distribution resources plan with the PUC, inclusive of maps and locational cost information. The PUC is required to review and approve such plans by December 1, 2018. Postponed indefinitely on February 15.

HB17-1193 – Concerning the Installation of Small Wireless Service Infrastructure – Much of this bill involves issues associated with local government permitting of attachments and the joint use of infrastructure. Passed out of the House quickly and presently before the Senate. CAMU issue alert was passed on to legislative contacts and municipal attorneys.

HB17-1225 – Concerning Interim Legislative Review of Participation in a Regional Transmission Organization – Establishes a vehicle for a legislative discussion of the pros and cons of an RTO. This review will occur as an interim matter.

Page 132


At present there is no bill challenging the Regional Haze SIP that authorizes the decommissioning of Craig Unit 1. Given the time remaining in the session, it doesn’t appear that there will be any legislative impediments to moving the SIP approval process to the EPA. Xcel Energy has drafted a number of bills that may still be introduced. The bills deal with economic incentive rate approval before the PUC, bonding authority to further generation plant decommissionings and a right of first refusal for transmission development. All of these will be a lift this late in the session and will require late bill status approval from leadership. The only one that directly concerns Platte River is a proposal that would provide incumbent utilities a right of first refusal for the construction of new transmission facilities approved by the FERC through an RTO planning process. Counsel worked with Xcel to revise the draft language to avoid any unintended jurisdictional consequences. United States Congress — The 115th Congress remains in control of the Republican Party. Much of the early activity involves the confirmation process for the new administration’s cabinet choices and Supreme Court nomination. The “lame duck” session – that portion of the 114th Congress’ proceedings that occurred after the November elections – failed to resolve the issues with the energy legislation, which stalled in conference. According to reports the Senate sponsors, Cantwell and Murkowski, are not enthusiastic about trying to run a new bill. Issues of concern in the new Congress will involve the continuation of tax-exempt financing, an issue that will likely be on the table during any comprehensive tax reform effort.

Page 133

Page 134

EXECUTIVE SUMMARY

Category March Variance YTD Variance

Municipal Demand (2.2%) n (1.7%) u

Municipal Energy (2.5%) n (2.6%) n

Baseload Generation (16.9%) n (5.7%) n

Wind Generation 8.8% l (1.5%) u

Solar Generation (18.5%) n (15.2%) n

Surplus Sales Volume (26.1%) n (1.2%) u

Surplus Sales Price (19.9%) n (13.8%) n

Dispatch Cost 4.1% n (2.1%) l

Variance Key: Favorable: l >2% | Near budget: u +/- 2% | Unfavorable: n <-2%

March 2017

Operating Report

Municipal demand and energy came in below budget for March, as temperatures remained above normal across the Northern Colorado region. All baseload generation experienced either planned or forced outages. Rawhide Unit 1 had a planned minor outage and one brief forced outage to repair a high pressure blowdown line. Craig 1 experienced three brief forced outages for various reasons including a steam leak. Craig 2 came off-line on March 23 for its planned major spring outage and Craig 3 had a brief forced outage which resulted in the delivery of shaft share.

Surplus sales volume for March was below budget for a variety of reasons. One factor contributing to this included lower than anticipated loads resulting in decreased demand for surplus energy throughout the region. Also, despite multiple spring outages across the Western Interconnect, utilities were generally surplus capacity. Lastly, renewable generation performed very well contributing to the excess generation in the region which also lowers the demand for surplus sales. Purchased power volume came in above budget, primarily to support replacement energy for baseload generation outages, but with the reduced market we were able to purchase energy at costs well below budget. Overall dispatch resources were above budget, primarily as a result of below budget generation and above budget costs on Rawhide, as well as the costs of running the combustion turbines for testing.

March 2017 Operating Report Page 1

Page 135

OPERATIONAL OVERVIEW

2017 Goal

0 0 l 1 n

System Disturbances. There was no loss of interconnected utility or city load during the month of March.

Peak Day Obligation. Peak demand for the month was 441 megawatts which occurred on March 6, 2017, at hour 19:00 and was 10 megawatts below budget. Platte River’s obligations at

the time of peak totaled 553 megawatts.

March Actual YTD Total

Forecast Demand451

0

50

100

150

200

250

300

350

400

450

500

550

600

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

MW

Hour

Peak Day Obligation: March 6, 2017

Hydro Wind Solar Rawhide Craig CTs Purchases

Total Obligation553

Municipal Obligation

441


Page 136

POWER GENERATION - RAWHIDE

Rawhide was taken off-line on March 9 for its planned spring outage which was extended by two days. Shortly after the unit was back on-line, it was determined that there was erosion to a blowdown line and that the unit had to come back off-line for a brief forced outage. With the combination of outages and a reduced sales market, equivalent availability and capacity factors both came in below budget. Year to date equivalent availability and capacity factors are both below budget.

Rawhide emission levels were below compliance limits for the month of March.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

March YTD

Equivalent Availability Factor

Budget Actual

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

March YTD

Net Capacity Factor

Budget Actual

0.00

0.01

0.02

0.03

0.04

0.05

0.06

0.07

0.08

0.09

0.10

March YTD

SO2 (lb/MBtu)

Limit Actual

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

March YTD

NOx (lb/MBtu)

Limit Actual

0.000

0.002

0.004

0.006

0.008

0.010

0.012

0.014

March YTD

Hg (lb/GWh)

Limit Actual


Page 137

POWER GENERATION - CRAIG

Craig 1 experienced three brief forced outages and Craig 2 came off-line on March 23 for its planned major spring outage. Craig 1 is currently curtailed due to the electrical cross-tie configuration needed while Craig 2 is off for its planned outage. As a result of these outages, holding spinning reserves on the units, and the reduced sales market, budgeted equivalent availability and capacity factors came in below budget. Year to date equivalent availability is slightly above budget while capacity factor is below budget.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

March YTD

Equivalent Availability Factor

Budget Actual

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

March YTD

Net Capacity Factor

Budget Actual


Page 138

POWER GENERATION - CTs

Peaking units ran in March in order to complete the required annual compliance testing and tuning. These tests were conducted during the Rawhide minor outage so that generation could serve load which reduced purchased power needs. All testing was successfully completed. Year to date generation is above budget while average natural gas pricing is well below budget.

0

500

1,000

1,500

2,000

2,500

3,000

3,500

March YTD

MWh CT Generation

Budget Actual

$3.20

$3.25

$3.30

$3.35

$3.40

$3.45

$3.50

$3.55

$3.60

$3.65

$3.70

$3.75

March YTD

$/Mbtu Natural Gas Pricing

Budget Actual


Page 139

POWER GENERATION - RENEWABLES

Wind generation was above budget for the month of March while solar generation was below budget. Hydro allocations were received as budgeted. Year to date, wind is slightly below budget and solar is below budget.

-

10

20

30

40

50

60

70

80

90

March YTD

MWh (000s)

Wind Generation

Budget Actual

-

2

4

6

8

10

12

14

March YTD

MWh (000s)

Solar Generation

Budget Actual


Page 140

MARKET SALES

Surplus sales volume and revenue were significantly below budget. Several factors continue to contribute to the decline in the surplus sales market: 1) lower than forecasted loads, 2) excess wind generation on the system which at times drove down pricing below our baseload generation costs, and 3) resources unavailable due to unplanned outages. Sales numbers also include Joint Dispatch transactions. Surplus sales volume and pricing are below budget for the year.

MARKET PURCHASES

Market volume purchases were well above budget due to unplanned outages on baseload resources throughout the month. However, costs were offset by purchasing this energy below budget. Joint Dispatch transactions are included in these numbers. While year to date volume is significantly above budget, the average pricing of this purchased power is significantly below budget by $6/MWh.

Average Price

Purchases

$0

$5

$10

$15

$20

$25

$30

March Budget

March Actual

$/MWh

$0

$5

$10

$15

$20

$25

$30

YTD Budget

YTD Actual

$/MWh Average Sales Price

-

50

100

150

200

250

March Budget

March Actual

MWh (000s)

-

50

100

150

200

250

YTD Budget

YTD Actual

MWh (000s)

Sales Volume

n Budget n Actual n JDA n Budget n Actual

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

March Budget

March Actual

MWh

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

YTD Budget

YTD Actual

MWh

Energy Purchases

$0

$5

$10

$15

$20

$25

$30

$35

$40

March Budget

March Actual

$/MWh

$0

$5

$10

$15

$20

$25

$30

$35

$40

YTD Budget

YTD Actual

$/MWh

Average Purchase Price

n Budget n Actual n JDA n Budget n Actual


Page 141

DISPATCH COST

Blended dispatch costs were above budget in March as a result of above budget baseload generation costs on Rawhide, wind, Rawhide solar and the combustion turbines as shown in the chart below. Year to date dispatch costs remain below budget.

Solar Unit CostFort Collins Solar Unit CostLoveland Solar Unit CostCT Unit CostTotal Resources Unit Cost

March

$0

$10

$20

$30

$40

$50

$60

$/M

Wh

Resource Cost

Budget Actual Blended Actual

$0

$10

$20

$30

$40

$50

$60

$/M

Wh

YTD Resource Cost

Budget Actual Blended Actual

Blended Budget: $36.66 | Blended Actual: $38.18

YTD Blended Budget: $31.41 | YTD Blended Actual: $30.74


Page 142

POWER DELIVERY

Major System Operations Projects Benefitting the Municipalities:

Estimated Finish

Date

Percent

Complete Description

08/2017 50% Foothills Substation

03/2018 38% Boyd Substation

EVENTS OF SIGNIFICANCE

•

•

•

•

•

•

•

• Completed a process revision to streamline the monthly Board Operating Report.

Completed the installation and transition to Platte River’s own WECC operations network

circuit for ICCP communication.

Location

Loveland

Loveland

Completed the long haul fiber swap agreement with Level 3.

Installed a dedicated network connection to Peak RC to support real time contingency analysis.

Due to the reduced sales market, we were able to purchase replacement power for the Rawhide spring outage at an average cost of $3.50/MWh below budget.

Rawhide was on-line for 139 continuous days leading up to the scheduled March outage.

In March, the Power Delivery division prepared a whitepaper on the Richard Lake Substation outage and associated Reliability Improvement Plan.

Attended the annual software users group for AuroraXMP, resource-planning software.


Page 143

Page 144

PLATTE RIVER POWER AUTHORITY – Financial Highlights Year-to-Date March 2017

Platte River reported favorable results year to date. Net income of $0.6 million was favorable by $1.8 million compared to budget due to below-budget expenses, partially offset by below-budget revenues. Details of the financial results are described below.

At this time, based on below-budget year-to-date trends for municipal and surplus sales, partially offset by savings from fuel, the estimated year-end net income could vary between $8.7 million and $11.9 million. The range is based on the assumption for operations and maintenance expenses, where the low end assumes no variance and the high end assumes a 5% favorable variance.

Below is a summary of key financial variances year to date:

Below-Budget Operating Expenses: Overall operating expenses were 8.9% below budget mainly due to the items listed below.

o Fuel expenses were below budget as a result of below-budget generation from the Craig units and Rawhide Unit 1, mainly due to the soft surplus sales market, the extension of the Rawhide Unit 1 minor outage, and lower coal prices.

o Operations and maintenance expenses were below budget mainly due to timing of expenses for personnel expenses, Yampa operating expenses, the Northwest Substation water line repair project, fiber inventory audit, and fiber lease analysis. Wheeling expenses were also below budget due to requiring less transmission than planned for WAPA’s Craig-to-Ault transmission line outage as sales were made directly from the Craig Station.

o Administrative and general expenses were below budget primarily due to timing of expenses for demand side management program expenses, software maintenance, contracted services for planning, and personnel expenses.

Below-Budget Capital Additions: Capital additions were below budget $5.7 million mainly due to timing of expenses and cancelled projects. See page 9 for details of significant projects.

Below-Budget Municipal Sales Revenues: Municipal sales were below budget $1.6 million or 3.5%. Energy delivered and billing demand were 2.6% and 1.7% below budget, respectively, driven by mild weather.

Below-Budget Surplus Sales Revenues: As a result of the soft surplus sales market, surplus sales revenues were $0.9 million below budget. The average price was 13.8% and volumes were 1.2% below budget, representing $0.8 million and $0.1 million of the variance, respectively.

Key Financial Results Annual($ Millions) Budget Actual Budget Actual Budget

Net Income/(Loss) (2.7)$ (2.2)$ 0.5$ 18.5% (1.2)$ 0.6$ 1.8$ 150.0% 11.8$

Debt Coverage .08x .25x .17x 212.5% .91x 1.11x .20x 22.0% 1.65x

Total Revenues 16.0$ 15.3$ (0.7)$ (4.4%) 52.7$ 50.3$ (2.4)$ (4.6%) 216.9$

Municipal Sales Revenue 14.3 14.0 (0.3) (2.1%) 45.1 43.5 (1.6) (3.5%) 191.9

Surplus Sales and Other Revenue 1.7 1.3 (0.4) (23.5%) 7.6 6.8 (0.8) (10.5%) 25.0

Total Operating Expenses 15.7$ 14.6$ 1.1$ 7.0% 45.1$ 41.1$ 4.0$ 8.9% 171.8$

Purchased Power 3.4 3.7 (0.3) (8.8%) 9.8 9.7 0.1 1.0% 35.4

Fuel Expense 3.5 3.0 0.5 14.3% 12.3 11.3 1.0 8.1% 48.8

Operations and Maintenance 6.6 6.3 0.3 4.5% 17.4 15.7 1.7 9.8% 65.6

Administrative and General 2.2 1.6 0.6 27.3% 5.6 4.4 1.2 21.4% 22.0

Capital Additions 3.3$ 1.4$ 1.9$ 57.6% 15.7$ 10.0$ 5.7$ 36.3% 52.3$

March Favorable(Unfavorable)

Year to Date Favorable(Unfavorable)

>2% Favorable | 2% to -2% At or Near Budget | <-2% Unfavorable

Page 1 of 11

Page 145

PLATTE RIVER POWER AUTHORITY

March 2017Non-GAAP Budgetary Basis (In Thousands)

FavorableBudget Actual (Unfavorable)

Revenues

Operating revenuesMunicipal sales 14,253$ 13,978$ (275)$

Short-term surplus sales and wheeling 1,567 1,124 (443)

Total operating revenues 15,820 15,102 (718)

Other revenuesInterest income(1)

104 128 24

Other income 44 21 (23)

Total other revenues 148 149 1

Total revenues 15,968$ 15,251$ (717)$

Expenditures

Operating expensesPurchased power 3,433$ 3,732$ (299)$

Fuel expense 3,541 2,973 568

Production expenses 4,963 5,088 (125)

Transmission expenses 1,611 1,165 446

Administrative and general 2,190 1,611 579

Total operating expenses 15,738 14,569 1,169

Debt expenseInterest expense 849 849 -

Principal 1,962 1,962 -

Allowance for funds used during construction (47) (66) 19

Total debt expense 2,764 2,745 19

Capital additionsProduction 1,152 791 361

Transmission 1,438 292 1,146

General 759 354 405

Total capital additions 3,349 1,437 1,912

Total expenditures 21,851$ 18,751$ 3,100$

Revenues less expenditures (5,883)$ (3,500)$ 2,383$

(1) Excludes unrealized investment gains and losses.

SCHEDULE OF REVENUES AND EXPENDITURES, BUDGET TO ACTUAL

Month of March

Page 2 of 11

Page 146

PLATTE RIVER POWER AUTHORITYSCHEDULE OF REVENUES AND EXPENDITURES, BUDGET TO ACTUALMarch 2017 - YEAR TO DATENon-GAAP Budgetary Basis (In Thousands)

Favorable AnnualBudget Actual (Unfavorable) Budget

Revenues

Operating revenuesMunicipal sales 45,116$ 43,542$ (1,574)$ 191,943$

Short-term surplus sales and wheeling 7,023 6,185 (838) 23,306

Total operating revenues 52,139 49,727 (2,412) 215,249

Other revenuesInterest income(1)

306 358 52 1,208

Other income 237 248 11 498

Total other revenues 543 606 63 1,706

Total revenues 52,682$ 50,333$ (2,349)$ 216,955$

Expenditures

Operating expensesPurchased power 9,836$ 9,715$ 121$ 35,431$

Fuel expense 12,329 11,346 983 48,800

Production expenses 12,658 11,926 732 49,402

Transmission expenses 4,761 3,775 986 16,187

Administrative and general 5,566 4,349 1,217 22,036

Total operating expenses 45,150 41,111 4,039 171,856

Debt expenseInterest expense 2,546 2,546 - 9,582

Principal 5,887 5,887 - 18,318

Allowance for funds used during construction (122) (290) 168 (560)

Total debt expense 8,311 8,143 168 27,340

Capital additionsProduction 9,955 7,569 2,386 27,479

Transmission 3,355 1,797 1,558 12,520

General 2,391 610 1,781 12,311

Total capital additions 15,701 9,976 5,725 52,310

Total expenditures 69,162$ 59,230$ 9,932$ 251,506$

Contingency reserved to board - - - 20,000

Total expenditures 69,162$ 59,230$ 9,932$ 271,506$

Revenues less expenditures (16,480)$ (8,897)$ 7,583$ (54,551)$

(1) Excludes unrealized investment gains and losses.

March Year to Date

Page 3 of 11

Page 147

PLATTE RIVER POWER AUTHORITYSTATEMENTS OF NET POSITIONUnaudited (In Thousands)

2017 2016Assets

Electric plant, at original costLand and land rights 16,997$ 14,515$ Plant and equipment in service 1,287,194 1,277,052 Less: accumulated depreciation and amortization (788,972) (765,772)

Plant in service, net 515,219 525,795 Construction work in progress 67,023 48,790

Total electric plant 582,242 574,585

Special funds and investmentsRestricted funds and investments 60,898 28,764 Dedicated funds and investments 66,230 46,468

Total special funds and investments 127,128 75,232

Current assetsCash and cash equivalents 12,093 16,844 Other temporary investments 20,844 15,796 Accounts receivable - municipalities 13,963 13,863 Accounts receivable - other 3,313 4,961 Fuel inventory, at last-in, first-out cost 13,537 15,864 Materials and supplies inventory, at average cost 13,425 13,068 Prepayments and other assets 3,540 5,540

Total current assets 80,715 85,936

Noncurrent assetsRegulatory assets 6,749 2,291 Other long-term assets 7,494 1,091

Total noncurrent assets 14,243 3,382

Total assets 804,328 739,135

Deferred Outflows of ResourcesDeferred loss on debt refundings 9,546 878

Pension deferrals 14,235 5,141

Total deferred outflows of resources 23,781 6,019

Liabilities

Noncurrent liabilitiesLong-term debt, net 226,358 183,277 Capitalized lease obligation - 3,228 Net pension liability 20,508 6,693 Other liabilities and credits 15,971 9,634

Total noncurrent liabilities 262,837 202,832

Current liabilitiesCurrent maturities of long-term debt 23,550 16,615 Current portion of capitalized lease obligation - 3,064 Accounts payable 13,266 17,059 Accrued interest 3,394 3,117 Accrued liabilities and other 1,704 1,540

Total current liabilities 41,914 41,395

Total liabilities 304,751 244,227

Deferred Inflows of ResourcesRegulatory credits 5,893 1,931 Pension deferrals 472 613

Total deferred inflows of resources 6,365 2,544

Net PositionNet investment in capital assets 366,478 367,588 Restricted 31,522 25,647 Unrestricted 118,993 105,148

Total net position 516,993$ 498,383$

March 31

Page 4 of 11

Page 148

PLATTE RIVER POWER AUTHORITYSTATEMENTS OF REVENUES, EXPENSES, AND CHANGES IN NET POSITIONUnaudited (In Thousands)

Twelve Months EndedMonth of March 31

March 2017 2016

Operating revenuesSales to municipalities 13,978$ 186,346$ 177,286$ Sales for resale and other 1,124 22,293 19,304

Total operating revenues 15,102 208,639 196,590

Operating expensesPurchased power 3,732 33,300 33,446 Fuel 2,973 47,515 44,167 Operations and maintenance 6,303 59,364 62,577 Administrative and general 1,554 17,194 16,269 Depreciation 2,289 27,306 27,039

Total operating expenses 16,851 184,679 183,498

Operating (loss) income (1,749) 23,960 13,092

Nonoperating revenues (expenses)Interest income 128 1,252 758 Other income 21 779 922 Interest expense (849) (10,274) (9,526) Allowance for funds used during construction 66 1,428 - Amortization of bond financing costs 177 1,981 354 Net decrease in fair value of investments (38) (325) (72)

Total nonoperating revenues (expenses) (495) (5,159) (7,564)

Income before contributions (2,244) 18,801 5,528

Contribution of assets to municipalities - (191) (155)

Change in net position (2,244) 18,610 5,373

Net position at beginning of period, as previously reported 519,237 498,383 495,887 Adjustment for change in accounting principle - - (2,877)

Net position at beginning of period, adjusted 519,237 498,383 493,010

Net position at end of period 516,993$ 516,993$ 498,383$

Page 5 of 11

Page 149

PLATTE RIVER POWER AUTHORITYSTATEMENTS OF CASH FLOWSUnaudited (In Thousands)


March 2017 2016

Cash flows from operating activitiesReceipts from customers 16,385$ 210,208$ 196,846$ Payments for operating goods and services (11,112) (125,392) (139,926) Payments for employee services (3,034) (33,599) (33,241)

Net cash provided by operating activities 2,239 51,217 23,679

Cash flows from capital and related financing activitiesAdditions to electric utility plant 13 (32,342) (32,991) Payments from accounts payable incurred for electric utility plant additions (1,258) (1,692) (551) Deposits into escrow for bond defeasance - (119,164) - Proceeds from issuance of long-term debt - 179,170 - Principal payments on long-term debt - (16,615) (21,980) Interest payments on long-term debt - (9,996) (9,874)

Net cash used in capital and related financing activities (1,245) (639) (65,396)

Cash flows from investing activitiesPurchases and sales of temporary and restricted investments, net (2,908) (57,272) 32,001 Interest and other income, including realized gains and losses 145 1,943 1,616

Net cash (used in)/provided by investing activities (2,763) (55,329) 33,617

Decrease in cash and cash equivalents (1,769) (4,751) (8,100)

Balance at beginning of period in cash and cash equivalents 13,862 16,844 24,944

Balance at end of period in cash and cash equivalents 12,093$ 12,093$ 16,844$

Reconciliation of net operating income to net cash(used in)/provided by operating activities

Operating income (1,749)$ 23,960$ 13,092$ Adjustments to reconcile operating income to

net cash provided by operating activities:

Depreciation 2,289 27,306 27,039 Changes in assets and liabilities which provided/(used) cash:

Accounts receivable 1,090 1,548 160

Fuel and materials and supplies inventories (106) 1,970 (6,836)

Prepayments and other assets (1,183) (8,923) 2,388

Deferred outflows of resources - (9,094) (5,141)

Accounts payable 1,438 (3,486) (200)

Net pension liability - 13,815 3,816

Other liabilities 168 300 (2,344) Deferred inflows of resources 292 3,821 (8,295)

Net cash provided by operating activities 2,239$ 51,217$ 23,679$

Page 6 of 11

Page 150

PLATTE RIVER POWER AUTHORITYSCHEDULE OF NET REVENUES FOR DEBT SERVICEUnaudited (In Thousands)


March 2017 2016Net revenues

Operating revenues 15,102$ 208,639$ 196,590$

Operations and maintenance expenses,excluding depreciation and amortization 14,562 157,373 156,459

Net operating revenues 540 51,266 40,131

Plus interest income on bond accountsand other income 149 2,034 1,691

Net revenues before rate stabilization 689 53,300 41,822

Rate stabilization Deposits - - - Withdrawals - - -

Total net revenues 689$ 53,300$ 41,822$

Bond service

Power revenue bonds 2,811$ 32,668$ 27,035$ Allowance for funds used during construction (66) (1,428) -

Net revenue bond service 2,745$ 31,240$ 27,035$

Coverage

Power revenue bond coverage ratio 0.25 1.71 1.55

Page 7 of 11

Page 151

Platte River Power AuthorityOperating Expense Variances Exceeding $100,000 - Month of March 2017

DescriptionFavorable

(Unfavorable)CoalCoal was below budget due to generation and price for the Craig units and Rawhide Unit 1.Generation was below budget for the Craig units due to the soft surplus sales market andunplanned outages. The coal prices for the Craig units were also below budget. Generation forRawhide Unit 1 was below budget as a result of Rawhide Unit 1's scheduled maintenanceoutage being extended. Rawhide Unit 1's coal price was below budget mainly as a result oftransportation prices. 632,964$

Energy Efficiency - Rebates/IncentivesExpenses were below budget due to the unpredictability of the completion of customers' energyefficiency projects. 321,543$

Yampa Operating ExpensesYampa operating expenses billed by Tri-State were less than anticipated. 239,877$

Medical and DentalClaims were lower than anticipated. Timing of medical expenses is difficult to predict and largeclaims can cause swings in this expense. 177,803$

Contracted ServicesContracted services were below budget mainly due to a delay for the Northwest Substationwater line repair, which was partially offset by above-budget expenses for Rawhide Unit 1'sschedule maintenance outage. 172,312$

SalariesSalaries were below budget as a result of several vacant positions, partially offset by overtimedue to the extension of Rawhide Unit 1's scheduled maintenance outage. 167,992$

O&M Materials and SuppliesO&M materials and supplies were above budget due to the timing of expenses for the aircompressor 101 rebuild and the baghouse compartment bags. Rawhide Unit 1's scheduledmaintenance outage also contributed to the above-budget variance. Lastly, the rotary car dumpermodifications for the new aluminum railcars and the electrostatic fluid cleaning project on RawhideUnit 1's electro hydraulic control system were not anticipated. (247,588)$

Purchased PowerPurchased power was above budget due to supplemental purchases made for the extension ofRawhide Unit 1's scheduled maintenance outage and unit issues on Craig Unit 1. In addition,wind generation was above budget. Partially offsetting the above-budget variance was below-budget solar generation and providing energy to Tri-State under the Forced Outage AssistanceAgreement for Craig Unit 3's forced outage. (299,281)$

Page 8 of 11

Page 152

Platte River Power AuthorityCapital Addition Variances - Year-end Estimates as of March 2017

Project ($ in Thousands) Budget EstimateFavorable

(Unfavorable)

POWER PRODUCTIONBottom Ash and Reclaim Pond - CCR Compliance - This out-of-budgetproject is required to be compliant with the Coal Combustion Residual rule.This project was originally planned for 2018, however, a portion of theproject will begin in 2017. -$ 2,095$ (2,095)$

Fiber Upgrade - Rawhide Gas Yard - This out-of-budget project wasrequested to re-design the Rawhide gas yard fiber to allow for more fiberflexibility and usability. The project was discussed at the December boardmeeting. -$ 260$ (260)$

Controls Upgrade - Baghouse - This out-of-budget project was requestedto replace the solenoid valves wiring scheme to reduce the chance ofbypassing the baghouse and ensuring reliability. -$ 150$ (150)$

Coal Dust Pneumatic Conveying System - This project will be abovebudget due to the need for a fire protection system, which was not includedin the original budget. 1,628$ 1,751$ (123)$

Rotary Car Dumper Conversion to Variable Frequency Drives - Themajority of this project has been delayed to 2018 due to the reallocation ofengineering resources to other capital projects. The below-budget fundswill be requested to be carried over into 2018. 563$ 50$ 513$

Soldier Canyon 10 Inch Water Line CR 19 & 70 Roundabout Reroute -This project has been cancelled for the 2017 budget year due to thereallocation of engineering resources to other capital projects. 1,146$ -$ 1,146$

FUELS AND WATERWindy Gap Firming Project - This project will be above budget due to anincrease in Platte River's participation level from 12,000 acre feet to 14,136acre feet. 1,643$ 2,098$ (455)$

YAMPAYampa Work Orders - These projects will be below budget due to recentestimates received from Tri-State. 10,876$ 10,735$ 140$

At this time, capital expenditures are expected to be $2.9 million below budget at the end of the year; however, anestimate of $5.1 million is expected to be requested to be carried over into 2018. Thus far in 2017, several additionalrequests for funds have occurred and changes have been made to the schedule and scope of projects. A transfer ofcontingency funds may be required to cover these projects. Based on project costs at this point, staff estimates acontingency transfer of approximately $2.2 million. However, further changes to capital projections are anticipated andstaff will continue to monitor spending estimates to determine the appropriate amount needed. Project managers arecontinuously improving work planning and budgeting by better aligning scope, schedules, and available resources. Theprojects listed below are projected to end the year with a budget variance of more than $100,000. In addition, theamounts below are costs for 2017 and may not represent the total cost of the project.

Page 9 of 11

Page 153

Platte River Power AuthorityCapital Addition Variances - Year-end Estimates as of March 2017

Project ($ in Thousands) Budget EstimateFavorable

(Unfavorable)

POWER DELIVERYFiber Optic Route to Estes Park - This project will be below budget due tothe timing of the installation of distribution poles shifting to 2018 based onrecent schedule information from the City of Loveland. The below-budgetfunds will be requested to be carried over into 2018. 5,430$ 3,230$ 2,200$

Circuit Switcher (T1) Addition, Breaker Replacement, Relay Upgrade -Harmony Substation - This project will be below budget due to thereallocation of resources to other capital projects. The below-budget fundswill be requested to be carried over into 2018. 410$ 15$ 395$

SONET Communication System Replacement - This project will be belowbudget due to internal resource constraints causing a delay in the project.The below-budget funds will be requested to be carried over into 2018. 387$ 80$ 307$

Oil Breaker (164) Replacement - Terry Street Substation - This projectwill be below budget due to the reallocation of resources to other capitalprojects. 138$ -$ 138$

SONET Software Upgrade - This project has been cancelled for the 2017budget year due to internal resource constraints. The below-budget fundswill be requested to be carried over into 2018. 113$ -$ 113$

CORPORATE SERVICESLow Impact Security - Substation Control Building Access Control - Thisproject will be below budget due to a schedule change as the result ofadditional CIP compliance requirements. The below-budget funds will berequested to be carried over into 2018. 1,021$ 400$ 621$

Low Impact Security - Substations (Owned) - This project will be belowbudget due to a schedule change as the result of additional CIPcompliance requirements. The below-budget funds will be requested to becarried over into 2018. 1,269$ 900$ 369$

Low Impact Security - Rawhide - This project will be below budget due tointernal resource constraints. The below-budget funds will be requested tobe carried over into 2018. 494$ 260$ 234$

Page 10 of 11

Page 154

PLATTE RIVER POWER AUTHORITYMONTHLY STATISTICSMarch 2017

Favorable FavorableBudget Actual (Unfavorable) Budget Actual (Unfavorable)

Resources (MWh)Net generation

Rawhide Unit 1 129,059 108,304 (20,755) 2,253,834 2,209,409 (44,425) Craig Units 1 and 2 76,535 62,483 (14,052) 977,066 892,361 (84,705) Combustion turbines 1,277 3,019 1,742 10,457 41,550 31,093

PurchasesWAPA LAP 8,764 8,764 - 109,536 109,536 - WAPA CRSP 48,817 48,817 - 502,467 502,467 - Wind 26,263 28,573 2,310 294,045 294,670 625 Solar - Rawhide Flats 5,571 4,539 (1,032) 29,544 22,025 (7,519) Solar - Fort Collins program 660 365 (295) 1,595 5,851 4,256 Solar - Loveland program 92 63 (29) 208 169 (39) Other purchases 18,672 33,786 15,114 41,275 72,097 30,822 Joint dispatch agreement purchases - 2,422 2,422 - 12,455 12,455 Forced outage exchange 3,700 200 (3,500) 7,400 12,700 5,300

Interchange - 103 103 - (7,031) (7,031) Total receipts 319,410 301,438 (17,972) 4,227,427 4,168,259 (59,168)

Deliveries (MWh)Municipal sales

Estes Park 10,980 10,880 (100) 132,062 130,675 (1,387) Fort Collins 121,535 120,319 (1,216) 1,520,013 1,534,663 14,650 Longmont 63,729 63,200 (529) 816,158 809,782 (6,376) Loveland 59,943 55,264 (4,679) 757,016 723,658 (33,358)

Total municipal sales 256,187 249,663 (6,524) 3,225,249 3,198,778 (26,471)

Solar - Fort Collins program 660 365 (295) 1,595 5,851 4,256 Solar - Loveland program 92 63 (29) 208 169 (39)

Surplus salesShort-term surplus sales 52,879 28,363 (24,516) 923,666 795,654 (128,012) Joint dispatch agreement sales - 10,689 10,689 - 23,452 23,452

Total surplus sales 52,879 39,052 (13,827) 923,666 819,106 (104,560)

Forced outage exchange 3,700 3,900 200 7,400 63,189 55,789 Losses and other 5,892 8,395 2,503 69,309 81,166 11,857

Total deliveries 319,410 301,438 (17,972) 4,227,427 4,168,259 (59,168)

Favorable FavorableBudget Actual (Unfavorable) Budget Actual (Unfavorable)

Coincidental demand (kW)Estes Park 20,224 21,121 897 221,150 218,005 (3,145) Fort Collins 214,182 210,899 (3,283) 2,854,261 2,865,367 11,106 Longmont 110,342 108,964 (1,378) 1,594,291 1,567,684 (26,607) Loveland 106,141 99,825 (6,316) 1,484,991 1,423,965 (61,026)

Total coincidental demand 450,889 440,809 (10,080) 6,154,693 6,075,021 (79,672)

Noncoincidental demand (kW)Estes Park 21,499 243,534 Fort Collins 210,899 2,870,331 Longmont 108,964 1,574,950 Loveland 99,825 1,431,222

441,187 6,120,037

March 12 Months Rolling

March 12 Months Rolling

Page 11 of 11

Page 155

Page 156

April 2017 General Management Report CORPORATE SERVICES

Safety. We completed the March outage with no employee injuries, and only one minor contractor first aid. Outage activities were supported through the completion of 32 hot work permits, 15 confined space permits, 48 non-permit checklists, 107 air checks for the open confined spaces, and 34 contractor safety orientations with 121 contractors processed through for outage related project work. 2015 2016 2017 (As of 4/4/2017)

Recordable Incident Rate 2.19 3.15 0.00 Lost Time Case Rate 0.44 0.90 0.00 DART (Days away restricted)

0.87 1.90 0.00

The Safety team provided First Aid training for headquarters employees, and annual occupational health testing has begun. Human Resources. Human Resources (HR) and the Chief Operating Officer successfully completed a search for the Vice President of Power Supply Position. Pat Connors will start in this position April 24. Recruiting and interviewing also continued for the open Chief Communications, Strategy and Marketing Officer position. The second core skills supervisory course will soon wrap up, with a third session to be concluded before June. To date, 18 employees have completed this leadership series. New sessions will start this summer. At the request of the Finance Department, HR staff developed a spreadsheet projecting Defined Contribution Plan costs for upcoming years. The process considers current employee demographics and projects future staffing and compensation levels to estimate Platte River’s contribution costs for the Defined Contribution Plan, with a goal of improving the forecasting accuracy of plan funding. HR also gathered, prepared, and submitted data for preparation of the 2017-2018 Affirmative Action Plan. Facilities. As spring arrives, Rawhide facilities is starting some of the weather dependent activities such as asphalt repairs, lower dam road gate replacement, and spring grounds maintenance. Headquarters facilities staff is wrapping up space reconfigurations for staff members coming on board before the new campus is constructed. In order to address parking shortages, employee parking is being reconfigured to use the recently acquired north parking lot, which will then allow us to expand visitor parking along the east side of the campus. ENVIRONMENTAL SERVICES & COMPLIANCE

Compliance. In March, compliance staff received notice that the two issues of non-compliance self-reported in January would be granted Compliance Exceptions. As previously reported, the non-compliance involved a task completed beyond the timeframe required by North American Electric Reliability Corporation (NERC) Reliability Standards MOD-026 and MOD-027. The task required that test reports be reviewed for technical accuracy within a 90 day period with identified issues communicated to appropriate personnel. The test reports were delivered to Platte River on August 22, 2016, but weren’t reviewed until December 26. As such, the review occurred 36 days outside of the 90-day window required within both standards. Evidence was provided to Western Electricity Coordinating Council (WECC) showing proper mitigation, which consisted of the completed test results. To avoid a recurrence we have implemented additional internal controls to track the compliance dates on

Page 157

Platte River Power Authority 2 March 2017 Management Report

numerous calendars. There will be no sanctions or penalties associated with the non-compliance, and this self-report will not become a part of Platte River’s permanent compliance history. FINANCE

Post-Closure Reclamation Liability Filing. Platte River is required to file a solid waste facilities closure estimate and proof of financial assurance annual report with the State of Colorado within ninety days of year-end. The report estimates the current closure and post closure care costs for the Rawhide ash disposal facility and the post closure costs of nine other impoundments on-site and shows Platte River’s ability to pay the future costs. The report, filed in March, estimated closure costs to be $7,851,191. Certificate of Non-Default Filing. As required by Platte River’s General Power Bond Resolution (No. 5-87), a Certificate of Non-Default, along with a schedule of insurance and audited financial statements were filed on March 23 with Platte River’s trustee, Wells Fargo Bank. Continuing Disclosure. Pursuant to the Continuing Disclosure Certificates executed by Platte River when it issued its Series GG, HH, II, and JJ bonds, Platte River’s audited financial report for December 31, 2016, was filed with the Municipal Securities Rulemaking Board (MSRB) through the Electronic Municipal Market Access (EMMA) Dataport. Financial Audit Report Filed with State. An electronic copy of BKD’s audited financial report for December 31, 2016, was filed with Colorado’s Office of the State Auditor as required by the Local Government Audit Law. 2017 Budget Update. At this time, capital expenditures are expected to be $2.9 million below budget at the end of the year; however, an estimate of $5.1 million is expected to be requested to be carried over into 2018. Thus far in 2017, several additional requests for funds have occurred and changes have been made to the schedule and scope of projects. A transfer of contingency funds may be required to cover these projects. Based on project costs at this point, staff estimates a contingency transfer of approximately $2.2 million. However, further changes to capital projections are anticipated and staff will continue to monitor spending estimates to determine the appropriate amount needed. Project managers are continuously improving work planning and budgeting by better aligning scope, schedules, and available resources. 2017 Budget Document Correction. To ensure transparency with the board, we are informing you about an error we discovered regarding the cash projections reported in the 2017 Annual Budget document in the table on page 7. At the time the budget document was prepared, the cash projections shown were overstated. However, after updating our forecasts with actual 2016 year-end results and factoring in estimates for proceeds from the sale of the Windy Gap water units, the projection shown in the budget document is reasonable (slightly understated). Going forward, we will be modifying our processes to better formalize our financial modeling updates and review processes to ensure projections are reasonable and accurate. 2018 Budget Preparation. Platte River’s 2018 budget process has begun. We continually look for ways to improve the existing process and to improve work planning and budgeting by better aligning scope, schedules, and available resources. Meetings were held with staff to review forms, outline processes, and answer questions as a way to facilitate departmental budget preparation. Below is a condensed schedule to show the overall budget process.

Page 158


March to May Kickoff meetings and preparation of budget details by department June Data compilation and reporting July Senior management and GM/CEO budget review August Refine budget and document preparation September Budget work session with Board October First public hearing and Board review of budget modifications November Prepare final budget document December Final budget review with Board and request adoption

COMMUNICATIONS & MARKETING

Annual Report. Platte River’s 2016 Annual Report will be presented to the Board at this meeting. The Board packet includes a PDF (printable) version. A web version and bound hard copies will also be available. Separate financial statements will also be available. Community. Platte River staff participated in the following events: Fort Collins Sustainability Group meetings, Colorado Science & Engineering Fair, Environmental Leadership Summit and Project Self Sufficiency Luncheon. Support was also provided for the Regional Issues Summit and Northern Colorado Prospers Talent Development (both Fort Collins Chamber of Commerce activities). Four tours were conducted, for Roosevelt High School STEM, Heritage Christian Academy, Leadership Loveland and Larimer County Conservation Corps.

OPERATIONS

Windy Gap Firming Project Update. The Windy Gap Firming Project is progressing well. The Windy Gap Participants’ Committee meetings have been focused on financing and project design discussions. Finalization of the pooled financing configuration is targeted for fall 2017. The plan is to have all funds prepared and available by the fall of 2018 (debt issuance for the pooled financing participants, as well as funds from participants using cash and/or independent financing). Platte River is continuing its internal analysis of financing options, although individual financing still looks to be the best choice for Platte River. Work is continuing on the Section 404 permit (wetlands mitigation) from the U.S. Army Corps of Engineers. Review is underway and it is anticipated that the 404 Permit will be issued by early to mid-summer. In addition, Northern Water continues to move forward on the water court application process and has prepared a draft application which is expected to be filed within the next month. The engineering design phase of the Firming Project has reached a milestone this month. MWH Americas, Inc (MWH), which has recently merged with Stantec, is heading the project and has reported that they have completed the “Project Definition” phase and that they are now ready to begin the “Intermediate Design” phase. The Project Definition phase involved site analysis, geotechnical investigations and a review of alternatives for major project components such as type of dam, spillway design and location, inlet/outlet works, conveyance connection and other associated facilities. The result of this phase was to identify the preferred alternatives for those various project components. An independent Project Review Board was formed to conduct a review of MWH’s work and proposal of preferred alternatives. The Project Review Board consists of four consultants with extensive experience in the dam design field and two members from the State Engineer’s Office Dam Safety Branch. There is

Page 159


also a member from Reclamation’s dam safety office who is sitting in on the meetings to stay up to speed on the project. This Project Review Board approved MWH’s preliminary design work and will continue to be involved in this project to provide reviews during subsequent design phases. At this point, MWH will be moving forward into the Intermediate Design phase which will begin to refine the preferred alternatives and provide a more detailed project design. The design phase is expected to last until mid 2018. The funding for the design phase was split between 2016 and 2017. As mentioned in the March Management Report, Northern Water is preparing an amendment to the fifth interim agreement which includes the continuation of design and mitigation costs. The due date for execution of this amendment and associated payment to Northern Water has been extended until the end of May. Based on this extension and the timeline associated with some of the water transaction agreements that are in progress to acquire additional storage in the Firming Project, this amendment will now be brought before the Board as a resolution for approval in May rather than April. Platte River’s portion of the design and mitigation cost at a participation level of 12,000 acre feet, is approximately $1.5 million, which is included in the 2017 budget. However, Platte River’s 2017 payment obligation is anticipated to be approximately $2 million, based on a participation level of just over 14,000 acre feet. The actual payment amount due will be specified in the amendment that will be brought to the board for approval in May. The construction phase will start in late 2018, following the design phase, and will last approximately three or four years. The firming project is estimated to be complete and ready to begin filling by the spring of 2021 or 2022. Rawhide Water Supply Update. Platte River continues to operate in a Windy Gap Short mode with the City of Fort Collins (special arrangement with the City of Fort Collins for the Reuse Plan and MOU requirements) due to a lack of Windy Gap water in the system. The current plans are to operate in Windy Gap Short mode through May and then resume regular Reuse Plan operations starting June 1. The overall water supply outlook is indicating an average water supply but will depend on upcoming spring temperatures and precipitation. The state snowpack levels had been well above average since mid December, but have recently started declining and precipitation has been below average recently. The state snowpack level was at 96 percent of average as of April 17. The most recent estimates from Northern Water indicate that there will be insufficient storage space available in the C-BT system to pump Windy Gap water this spring. While it does not look hopeful that Windy Gap water will pump this spring, it is anticipated that sufficient C-BT water will be available for lease to use in-lieu of Windy Gap water to meet the Reuse Plan obligations through the remainder of the 2017 water year (which ends in October). Staff previously secured a lease of C-BT water for use in-lieu of Windy Gap water to satisfy the needs of the 10-inch line pumping for plant process water. Staff will continue to monitor conditions and will seek leases of C-BT water as needed. Platte River Coal Supply Update. Platte River staff is in the process of negotiating a rail transportation contract extension for coal delivery to the Rawhide Energy Station. The current transportation agreement expires at the end of 2017 and this five-year contract extension will secure the Rawhide coal transportation through December 2022. Negotiations are progressing well and it is anticipated that a rail transportation contract will be executed in the next few months, at which time staff will provide an update to the Board. Resource Planning. Customized Resource Plan (CRP). Platte River continues to make progress on the CRP for its four municipal owners. Initial modeling results were produced in March and are undergoing an internal review for the pre-planned incremental renewables scenarios (25-200 MW of wind, 25-200 MW of solar, 300 MW blend). The regularly planned quarterly progress update will be held with project stakeholders on April 13 to review details of the modeling process and prepare for the delivery of initial results during Q3. Platte River staff members also presented an overview of the

Page 160


project at the Fort Collins Energy Board in February and will meet with the Loveland Utilities Commission in May. Power Supply Plan. The 2017 Q1 model runs for the 2018 Budget projections were completed in March and will be finalized after an internal review in early April. As part of the quarterly Power Supply Plan process, final results will be distributed internally in mid April. Organized Market Support. Support is ongoing with regular attendance at the Mountain West Transmission Group, including the analysis of participation in an organized market and the technical aspects of the DC ties. For this month’s Board report, Platte River will submit an update to its “Report on Organized Power Markets—RTOs and ISOs”, which was originally submitted to the Board in October 2016. The update will include a discussion of capacity markets and the position the Mountain West Transmission Group is taking toward them in the implementation of a regional wholesale market. Load Forecast. The planning department continues to develop the load forecast process using a newly acquired program, e-Views. Historical load, weather, regional economic data, and municipal consumption and demand data are being obtained and added to the database. A weather data service provider gathered sample data from several weather stations and met with Platte River to select the best weather stations for use within our municipal areas. Mountain West Transmission Group (MWTG). The MWTG published an updated version of its Frequently Asked Questions (FAQs) on March 24. Many of the additional questions were asked on behalf of the Colorado Association of Municipal Utilities (CAMU). These FAQs are available to the public. Various teams of MWTG and the Southwest Power Pool (SPP) staff continue to have strategic discussions related to the MWTG Term Sheet items. Since details tend to derail strategic efforts, a technical team was formed this month to address market and operations technical issues such as metering, real-time data exchange, modeling, DC ties, remedial action schemes, and compliance. This team will give MWTG a head start on understanding some of the detailed technical issues of concern. The MWTG travelled to Little Rock, Arkansas for the April Steering Committee meeting. Staff members participated in a guided tour of SPP’s control center which houses the Reliability Coordinator, Transmission Operations and Market Operations. Their staff answered many questions and spent a lot of time with us on the tour. We were very impressed with SPP’s employees and their facilities, both operating and corporate. MWTG is working to complete negotiations of the Term Sheet items with SPP prior to SPP’s Members and Stakeholders meeting in July. Should MWTG choose to join SPP, the market go-live date would be in the first half of 2019. CUSTOMER SERVICE

Energy Efficiency (EE) Programs. In 2017, efficiency programs are expected to result in new energy savings of 30,000 MWh and demand reduction of 5,000 kW. A total of $9.15 million has been budgeted, with $5.28 million from Platte River and $3.87 million from the municipalities. The projected result is a levelized cost of energy of $35/MWh, assuming the entire budget is spent. To date, EE programs have achieved 3,706 MWh of new energy savings and 643 kW of new summer peak demand reduction at a cost of $1.16 million. The table below compares current results to projected results and breaks the results out by customer type.

Page 161


Customer Segment

Service provided 2017 Results

2017 Results projected

by year end* Commercial & Industrial

Efficiency assessments 44 330 Efficiency project rebates 136 1,000

Energy savings (MWh) 3,655 27,000 Residential Efficiency assessments 242 1,000

Discounted efficient lighting products 3,500 100,000

Energy savings (MWh) 51 3,000 Totals Energy savings (MWh) 3,706 30,000

* Projections are updated throughout the year based on available budgets and estimates of customer participation.

Community Solar. Staff continues to work towards a community solar program that could serve all four municipalities. As described during the March Board meeting, a critical step in the program design process is to survey customers about their interest in solar program pricing and feature. Platte River hired the Pacific Consulting Group to design and administer the survey and worked with municipality staff to enlist customers for the survey. The survey closed on April 7 with 1,256 completed surveys, with responses from all four communities. According to Pacific Consulting, this is a great response rate. They have begun analyzing the results and should be able to provide staff an update by the end of April. During the March Board meeting we had discussed coming back in front of the Board in April to discuss the community solar program. However, Platte River and municipality staff would like to ensure we have adequate time to review the results before presenting them to the Board, so we will plan to present the results during the May Board meeting. GENERAL & FOLLOW UP ITEMS

HQ Campus. FCI Contructors, Inc has been hired as our construction manager/general contractor. They will work closely with the design team and staff through the balance of the schematic design process and throughout the detailed design phase. Windy Gap Unit Transactions. Staff is continuing to make progress in selling a number of Windy Gap units and securing additional Windy Gap Firming Project storage. Negotiations with a group of selected entities from the Request For Proposal process have gone well and agreements are currently being drafted and reviewed. It is anticipated that the majority of the transactions will be completed by the end of June, with remaining transactions being completed later this summer or fall. As a result of these transactions, Platte River will be able to achieve the minimum target storage of 14,000 acre feet and the number of units sold will be well within the Board approved parameter. Staff will report back to the Board with additional details as the transactions wrap up.

Page 162

Documents

Board of Directors Regular Meeting 2000 E. Horsetooth Rd, Fort … · 2016-08-04 · 2016 BKD Audit Report . Director Bergsten moved to accept the 201BKD Audit Report as presented