Board of Directors
Annual Meeting
February 25, 2016
2015
Operations and Financial
Year In Review
Board of Directors Meeting – February 25, 2016
2015 Lost Time Accidents
2015
Goal
2015
Actual
0
1
Five-Year Trend
# of Accidents
5
4
3
2
1
0
2011
2012
2013
2014
2015
Significant Events in 2015
• Planned major maintenance outage of Rawhide Unit 1
successfully completed.
• Installed the Emerson Ovation DCS process control
computer system with high performance graphics and
analytics.
• Rolled out new Rawhide controls network to improve cyber
security and reliability.
• Completed the tripper deck dust collection project.
• Completed the variable frequency drive project at Rawhide
pump station to increase energy efficiency while improving
water utilization.
Significant Events in 2015
• Reorganized the Power Delivery division to better align
employee strengths with business needs.
• Re-filed a new version of Joint Dispatch (JDA) with FERC
to create a long term market opportunity for our excess
generation.
• Experienced a soft energy market throughout the year,
resulting in extremely low gas and surplus sales pricing.
• Municipal demand and energy were close to budget.
• Entered into a purchase power agreement (PPA) for 30
megawatts of solar at Rawhide Flats Solar Facility.
• First full year of Spring Canyon wind (60 MW).
Major Accomplishments in 2015
• Rawhide Unit 1 achieved 393 consecutive days of operation,
shattering the previous continuous run record of 292.
• Completed the major outage with over 34,000 labor hours and
zero lost time accidents.
• Procured all purchased energy needed to cover Rawhide and
Craig outages well below 2015 purchased power budget prices.
• Received a successful NATF peer review and NERC audit.
• Began to self-supply reserves during low market times, which
has and will continue to reduce costs.
• Several new fiber and water lease agreements, resulting in
increased revenues for Platte River and the cities.
• Negotiated an extension of the Rawhide coal contract, securing
the highest BTU and lowest sulfur coal available in the Powder
River Basin through 2022.
2015 Operational Results
2015 Variance
Indicator
Municipal Demand
(1.3%)

Municipal Energy
(0.0%)

Baseload Generation
(5.1%)

Wind Generation
(7.8%)

Surplus Sales Volume
(16.5%)

Surplus Sales Price
(21.0%)

2.6%

Category
Dispatch Cost
 > 2% |  +\- 2% of budget |  < -2%
System Resources
Total System Resources (4,066 GWh)
2015 variance: (1.1%)
Purchases
6%
Wind
7%
Hydro
15%
CTs
1%
Rawhide
48%
Craig
23%
Delivered Energy
Total System Deliveries (4,066 GWh)
2015 variance: (1.1%)
Surplus Shortterm
17%
Losses & Other
4%
Munis
79%
Municipal Delivered Energy
Total Municipal Deliveries (3,201 GWh)
2015 variance: (0.0%)
Purchases
7%
CTs
1%
Wind
10%
Craig
9%
Rawhide
54%
Hydro
19%
Equivalent Availability Trend*
Rawhide 2015 variance: (0.7%)
Rawhide
| Craig 2015 variance: (4.5%)
Craig
Industry Average
100%
95%
90%
85%
80%
75%
70%
65%
Black
plant
Water
induction
60%
55%
50%
2011
2012
2013
2014
*Data normalized for planned outages
2015
Net Capacity Factor Trend*
Rawhide 2015 variance: (1.3%)
Rawhide
Craig
| Craig 2015 variance: (9.3%)
Industry Average
100%
95%
90%
85%
80%
75%
70%
65%
60%
55%
50%
2011
2012
2013
2014
*Data normalized for planned outages
2015
Rawhide Emissions Trend
NOx & SO2 (lb/MBtu)
0.200
NOx Actual
SO2 Actual
NOx Limit
SO2 Limit
Hg (lb/GWh)
Actual
Limit
0.020
0.018
0.180
Voluntary
Reduction
0.160
0.016
0.014
0.140
0.012
0.120
0.010
0.100
0.080
0.008
0.060
0.006
0.040
0.004
0.020
0.002
0.000
0.000
2011
2012
2013
2014
2015
2012
2013
2014
2015
Surplus Sales vs. Gas Pricing
$/MWh
Surplus Sales Pricing
32
30
28
26
24
22
20
2011
2012
2013
2014
2015
Gas Pricing
$/MBtu
5.0
4.5
4.0
3.5
3.0
2.5
2011
2012
2013
2014
2015
Surplus Sales
Sales Mix (713,449 MWhs)
2015 blended sales price: $25.27 | 2015 variance (21.0%)
Contracts
12%
$31.53/MWh
CTs
2%
$54.64/MWh
Real Time
45%
$24.64/MWh
Preschedule
41%
$22.27/MWh
Surplus Sales Volume
2015 variance: (16.5%)
Budget
Actual
1,000
900
800
700
MWh (000’s)
600
500
400
300
200
100
0
2011
2012
2013
2014
2015
Dispatch Cost
2015 variance 2.6%
2015 Budget
2015 Actual
2015 Blended Cost
$135
70
60
$/MWh
50
40
30
20
10
0
Rawhide
CRSP
Craig
LAP
Wind
Purchases
CTs
Dispatch Cost Trend
Blended Dispatch Cost
35
30
25
$/MWh
20
15
Black
plant
Water
induction
10
5
0
2011
2012
2013
2014
2015
2015 Financial Summary
All Strategic Financial Plan targets were
exceeded.
AA credit rating affirmed.
Strategic
Financial Plan
Target
3 Yr Avg
2015
2014
2013
Net Income
(In Millions)
> $6 Million
$10.9 
$6.8

$16.6 
$9.3

Debt Service
Coverage
> 1.5X
1.64

1.51

1.71

1.70

Days Cash
On Hand
> 200 Days
248

205

284

255

Debt to
Capitalization
< 50%
31%

29%

31%

34%

Significant Events
•
Municipal loads were very close to projections
•
Surplus sales pricing and energy lower than expected
•
Planned maintenance outages of Rawhide Unit 1 and Craig Unit 2
•
Full year of 60 MW of wind purchase power agreement
•
Lower wage expense due to vacancy savings
•
Water lease extended
•
Forced outage exchange agreement payout
•
Pension liability of $6.8 million
•
Board contingency transfers of $6.6 million
2015 Financial Results
Variance from Budget
(in millions)
Indicator
Net Income
($3.1)

Revenues
($10.6)

Operating Expenses
$8.5

Capital Expenditures
$4.7

Category
 > 2% |  +\- 2% of budget |  < -2%
Net Income
Variance from 2015 Budget: ($3.1M)
Income
SFP Target
18
$16.6
16
14
$/Millions
12
$11.4
$11.4
$9.3
10
8
$6.8
6
4
2
0
2011
2012
2013
2014
2015
Debt Coverage
Variance from 2015 Budget: (.09x)
Debt Coverage
SFP Target
2.0
1.80
1.8
1.72
1.70
1.71
1.51
Times
1.5
1.3
1.0
0.8
0.5
0.3
0.0
2011
2012
2013
2014
2015
Revenues vs. Expenditures
Operating Expenses
Debt Expenses
Capital Additions
Revenues
250
$219.1
$/Millions
200
$194.0
$189.9
$198.4
2013
2014
$176.7
150
100
50
0
2011
2012
2015
Revenues
Variance from 2015 Budget: ($10.6M)
2015 Budget
2015 Actual
200
180
$176.6
$176.0
160
$/Millions
140
120
100
80
60
$33.6
40
$23.4
20
$1.5
$1.7
0
Municipal Sales
Surplus Sales & Other
Other Revenue
2015 Municipal Demand
Variance from 2015 Budget: (1.3%) or ($0.6M)
Peak Municipal Demand
700
Budget
600
MW
500
400
300
596
471
470
460
200
408
398
Apr
May
639
627
573
436
464
487
Oct
Nov
Dec
100
0
Jan
Feb
Mar
Jun
Jul
Aug
Sep
Delivered Energy
Variance from 2015 Budget: At Budget
3,500
3,182
3,192
3,196
3,154
3,201
2011
2012
2013
2014
2015
3,000
GWh
2,500
2,000
1,500
1,000
500
0
Surplus Sales
Variance from 2015 Budget: ($10.2M)
Short-term
Wheeling
Contract
35
$30.9
$30.1
30
$25.6
$/Millions
25
$23.4
$23.0
20
15
10
5
0
2011
2012
2013
2014
2015
Other Revenues
Variance from 2015 Budget: $0.2M
Other Income
2.5
Interest Income
$2.0
2.0
$1.9
$/Millions
$1.7
1.5
$1.4
$1.2
1.0
0.5
0.0
2011
2012
2013
2014
2015
Operating Expenses
Variance from 2015 Budget: $8.5M
2015 Budget
60
$51.8
50
$50.0
2015 Actual
$51.1
$46.4
$/Millions
40
$33.3 $32.5
30
20
$16.3 $15.7
$13.3 $12.7
10
0
Production
Fuel
Purchased Power
A&G
Transmission
Production Expenses
Variance from 2015 Budget: $1.8M
40
2015 Budget
$36.2
35
2015 Actual
$36.0
$/Millions
30
25
20
15
$10.7
$9.5
10
$3.3
5
$3.0
$1.6
$1.4
0
Rawhide
Craig
Rawhide
60
50
$41.9
$42.9
2011
2012
Yampa
Power Operations
Power Operations
CTs
CTs
Wind
$45.0
$46.7
2013
2014
$50.0
$/Millions
40
30
20
10
0
2015
Fuel Expenses
Variance from 2015 Budget: $4.7M
2015 Budget
35.0
30.0
$28.8
$27.3
25.0
$/Millions
2015 Actual
$21.3
20.0
$17.0
15.0
10.0
5.0
$1.0
$2.2
0.0
Rawhide
Craig
Rawhide
60
$/Millions
50
Craig
Combustion Turbines
$52.6
$43.0
$44.4
2011
2012
Combustion Turbines
$50.0
$46.4
40
30
20
10
0
2013
2014
2015
Purchased Power Expenses
$/Millions
Variance from 2015 Budget: $0.8M
20
18
16
14
12
10
8
6
4
2
0
$17.9
$17.9
2015 Budget
$9.8
2015 Actual
$8.8
$3.2
$2.8
Hydro
Renewables
Hydro
Renewables
Other
Purchased Reserves
Other
$32.5
$28.0
25
$/Millions
$2.5
Purchased Reserves
35
30
$2.8
$26.9
$22.3
$23.8
20
15
10
5
0
2011
2012
2013
2014
2015
A&G Expenses
Variance from 2015 Budget: $0.6M
Operations
18
Energy Efficiency
$15.8
16
$14.3
$/Millions
14
12
$11.4
$11.7
2011
2012
$12.3
10
8
6
4
2
0
2013
2014
2015
Transmission Expenses
Variance from 2015 Budget: $0.6M
Wheeling
O&M
14
$12.6
12
$/Millions
10
$8.5
8
$7.4
$5.8
$6.2
2011
2012
6
4
2
0
2013
2014
2015
Capital Expenditures
Variance from 2015 Budget: $4.7
Production
40
35
Transmission
General
$34.8
$33.1
$/Millions
30
25
$19.5
20
$16.3
$16.2
2012
2013
15
10
5
0
2011
2014
2015
2015 Financial and Operating
Results
2015 NET INCOME
Budget: $9.9 million | Actual: $6.8 million | Variance: 33%
Rawhide Unit 1 Generation
Below-budget capacity factor
by 1.3%
(10-day extended outage)
 Craig Units Generation

Below-budget capacity factor by 11.6%
(surplus sales market conditions and
extended Craig 2 scheduled outage)
Municipal Sales
Below-budget demand (1.3%)
At budget energy
 Short Term Surplus Sales
Below-budget energy 19%
Below-budget price 25%

Operating Expenses
 Capital Expenses

Questions
Board of Directors Meeting
February 25, 2016
Operational Summary
January Variance
Category
Municipal Demand
(6.0%)

Municipal Energy
(0.8%)

(21.1%)

6.2%

Surplus Sales Volume
(49.7%)

Surplus Sales Price
(11.4%)

(1.5%)

Baseload Generation
Wind Generation
Dispatch Cost
 > 2% |  +\- 2% of budget |  < -2%
CIG Natural Gas Spot Price*
January 2011 - December 2015
$8.0
$7.23
$7.0
$/mmbtu
$6.0
$5.0
$4.25
$3.35 Average
$4.0
$3.0
$2.0
$1.93
$1.80
$1.0
$-
1/11 4/11 7/11 10/11 1/12 4/12 7/12 10/12 1/13 4/13 7/13 10/13 1/14 4/14 7/14 10/14 1/15 4/15 7/15 10/15
January 2015 - February 2016
$4.0
$/mmbtu
$3.5
$3.0
$2.78
$2.65
$2.35 Average
$2.5
$2.0
$1.81
$1.5
$1.0
1/15
2/15
3/15
4/15
5/15
6/15
*Source: CIG Historic Spot Px (Bloomberg)
7/15
8/15
9/15
10/15
11/15
12/15
1/16
2/16
Board of Directors Meeting
February 25, 2016
Financial Summary
Category
January
Variance from Budget
($ in milions)
$0.2

Debt Coverage
0.01x

Revenues
($1.8)

Operating Expenses
$2.0

Capital Additions
$1.5

Net Income
 > 2% |  +\- 2% of budget |  < -2%
Board of Directors Meeting
February 25, 2016
Debt Financing Overview
Series JJ Bonds
February 25, 2016
Agenda
•Overview of Financing
• Capital Projects
• Reimbursement Resolution
• General Timeline
•Issuing the Debt
•
•
•
•
•
Market Update
Bond Sale Process
Bond Sale Participants
Structuring the Bond Issue
Rating Agencies
•Board Approvals
• Authorizing Resolution
Why Issue Bonds?
Platte River’s five-year capital plan totals $225 million. A portion of
the power production and transmission projects will be funded by a
$60 million bond issue in early 2016. Platte River intends to issue
approximately $74 million of bonds in 2017 to help pay for the Windy
Gap Firming project and headquarters’ facilities master plan.
•SFP days cash on hand target 200 days, as of 12/31/15 205 days.
($ in thousands)
Power Production
Transmission
General
Facilities Master Plan - Headquarters
Windy Gap Firming Project
Total Capital Projects
2016
$21,129
14,384
2,224
2,547
1,746
$42,030
2017
$18,606
7,936
5,860
25,000
803
$58,205
2018
$27,233
3,372
5,184
0
48,016
$83,805
2019
$11,119
6,761
2,537
0
13
$20,430
2020
$8,296
10,713
1,582
0
13
$20,604
Projects Funded by Series JJ Bonds
Major Production Projects
Major Transmission Projects
Project
Project Costs
Project
Project Costs
RH Unit 1 DSC replacement/expansion
$7.7M
LaPorte substation – 230kV expansion
$7.1M
Superheater tube replacement
$7.0M
Boyd 115/230kV substation transformer
$7.0M
Dust collection system upgrades
$3.1M
Foothills substation
$4.1M
Condenser tube replacement
$3.0M
Generation availability transformer –RH
$1.7M
Coal dust pneumatic conveying system
$1.8M
Solar interconnection transformer – RH
$1.0M
Soldier Canyon 10” line modifications
$1.4M
Miscellaneous transmission projects
$7.1M
Air heater basket replacement
$1.3M
HVMCC switchgear replacement
$1.1M
Miscellaneous production projects
$5.6M
Total Production Project Costs
$32.0M
Total Transmission Project Costs
$28.0M
Reimbursement Resolution
• Reimbursement Resolution approved by the Board in
October 2014.
• Enables Platte River to issue up to $60M in bonds for
transmission and production projects.
• Through 12/31/15, Platte River has spent $15.6M on
identified projects, which will be reimbursed from
Series JJ bond proceeds.
Series HH – Refunding Opportunity
• Series HH bonds are advance refundable with a call date of
June 1, 2019
• Outstanding bonds available for refunding total $105.4M
• Outstanding bonds have coupon rates of 5%, and today’s rates
are significantly lower
• Maturity dates range from 2020 through 2029
• Under current market conditions, savings of over $11M on a PV
basis
• Average annual savings of approximately $950k to 2029
• Very interest-rate sensitive
• If interest rates were to rise 0.25%, PV savings would be reduced by
approximately $2M.
• Continue to monitor the change in PV savings with PFM
• Have up to 48 hours before pricing to finalize the refunding decision.
General Timeline
January and February:
• Draft Preliminary Official Statement (POS)
• Update financing plan
• Draft Notice of Sale (NOS) and Resolution
March:
• Rating agency meetings
• Finalize POS and NOS
• Board meeting to approve authorizing resolution
April:
•
•
•
•
Marketing of the bonds
Competitive sale of the bonds
Bond closing
Board meeting – review bond transaction
Public Financial Management
Financial Advisor: Dan Hartman
Tax-Exempt Interest Rates
Although rates are at levels slightly higher than the all-time lows reached at the
end of November 2012, interest rates are still far below their long-term averages
30 Year AAA MMD Rate Position
(February 12, 1986 to February 11, 2016)
MMD Range
Current MMD
Average MMD
10.00%
9.00%
8.00%
7.00%
6.00%
5.00%
4.00%
3.00%
2.00%
1.00%
0.00%
1 Year
Statistic
2/11/2016
Average
Spread to Avg.
Minimum
Spread to Min.
Maximum
Spread to Max.
1 Year
0.38%
2.61%
-2.23%
0.11%
0.27%
6.80%
-6.42%
2 Year
2 Year
0.52%
2.91%
-2.39%
0.27%
0.25%
6.80%
-6.28%
3 Year
4 Year
5 Year
7 Year
10 Year
15 Year
20 Year
25 Year
Summary of February 11, 2016 vs. 30 Year Historical MMD Rates
3 Year
4 Year
5 Year
7 Year
10 Year
15 Year
0.61%
3.13%
-2.52%
0.36%
0.25%
6.85%
-6.24%
0.69%
3.32%
-2.63%
0.47%
0.22%
6.95%
-6.26%
0.79%
3.50%
-2.71%
0.64%
0.15%
7.20%
-6.41%
1.11%
3.84%
-2.73%
0.93%
0.18%
7.60%
-6.49%
1.56%
4.22%
-2.66%
1.54%
0.02%
8.00%
-6.44%
2.03%
4.69%
-2.66%
1.90%
0.13%
8.50%
-6.47%
30 Year
20 Year
2.32%
4.96%
-2.64%
2.20%
0.12%
8.85%
-6.53%
25 Year
2.58%
5.09%
-2.51%
2.49%
0.09%
8.90%
-6.32%
30 Year
2.63%
5.13%
-2.50%
2.54%
0.09%
8.95%
-6.32%
Benchmark Tax-Exempt Interest Rate Progression
After trending rising throughout the first half of 2015, benchmark tax-exempt rates
have decreased considerably and are now near all-time lows
• Since the start of June 2015, the 20-Year AAA MMD rate has decreased 77
bps, with 60 bps of the decrease occurring since November
20-Year AAA MMD Rate History
(June 1, 1981 Inception to February 11, 2016)
(January 1, 2015 to February 11, 2016)
Decrease from Previous Day (Right Axis)
Increase from Previous Day (Right Axis)
20-Year AAA MMD
14.00%
3.50%
12.00%
3.00%
10.00%
2.50%
8.00%
2.00%
6.00%
1.50%
4.00%
1.00%
2.00%
0.50%
0.00%
0.00%
10
8
6
4
2
0
-2
-4
-6
-8
-10
Interest Rate Forecasts
On December 16, 2015 the FOMC established a new target range for the federal funds rate of ¼ to ½
percent, up from 0 to ¼ percent, where it was set on December 16, 2008.
The Federal Reserve (Fed) also raised the interest rate it pays banks on excess reserves deposited with the
Fed (“interest on excess reserves” or “IOER”) from ¼ percent to ½ percent
Fed governors have urged investors NOT to look to history for guidance on the pace of tightening or the final
resting point for overnight rates. In the past three tightening cycles, the end-point was 3.75% to 5.25%.
Amidst the uncertainty regarding how high and how fast long-term interest rates will go, the consensus
amongst economists is that short-term rates will increase more and faster than long-term rates
The Street's Interest Rate Forecast
(As of February 10, 2016)
Average Forecasts
Current
Q1 16
Q2 16
Q3 16
Q4 16
Q1 17
Q2 17
30-Year UST
2.53%
3.03%
3.17%
3.26%
3.34%
3.43%
3.54%
10-Year UST
1.70%
2.09%
2.29%
2.44%
2.60%
2.74%
2.99%
2-Year UST
0.70%
0.93%
1.15%
1.37%
1.56%
1.74%
2.09%
3M LIBOR
0.62%
0.69%
0.84%
1.03%
1.19%
1.41%
1.77%
Fed Funds Target Rate
(Upper)
0.50%
0.60%
0.80%
0.95%
1.15%
1.35%
1.70%
Fed Funds Target Rate
(Lower)
0.25%
0.30%
0.50%
0.67%
0.89%
1.10%
1.43%
Bond Sale Process
Plan of Finance
Legal Framework
Marketing
Administration
•
•
•
•
•
Select the team
Determine project cost and timing
Identify source of repayment
Size and structure the bonds
Determine method of sale
• Adopt Authorizing Resolution
• Tax analysis & due diligence
• Prepare disclosure document (official statement)
• Obtain ratings
• Underwriter & investor out reach
• Sell & price the bonds
•
•
•
•
•
•
•
Closing/money transfer
Invest bond proceeds
Begin project & track progress
Make principal & interest payments
Monitor for refinancing opportunities
Comply with Arbitrage Rebate Regulations (IRS/Tax Code)
On-going disclosure by complying with SEC Rule 15( c)2-12
Bond Sale Participants
Financing Participant
Firm
Role
Financial Advisor
PFM
Provide bond structuring and
market related advice
Bond and Special Counsel
Sherman & Howard LLC
Provision of key legal and tax
documentation and opinions
Trustee/Escrow Agent
Wells Fargo Bank, NA
Hold bond and escrow funds
Underwriter
TBD via competitive bid
Purchaser of the bonds
Consulting Engineer
Black & Veatch
Provides calculations for new bonds
per Power Bond Resolution
Accountant
BKD, LLP
Inclusion of audited financials
Verification Agent (if
including a refunding)
Causey, Demgen &
Moore Inc.
Verify that bond cashflows are
correct
Rating Agencies
S&P, Fitch
Provide ratings on the bonds
Structuring the Bond Issue
Estimated Sources and Uses
Estimated Sources of Funds
Par Amount
Premium on Bonds
Release of Bond fund money
Total
Estimated Uses of Funds
Project Fund
New Money
Refunding
Total
$ 52,635,000
$ 99,860,000
$152,495,000
7,771,032
19,862,112
27,633,143
-
2,123,444
2,123,444
$ 60,406,032
$121,845,556
$182,251,588
New Money
$ 60,000,000
-
121,079,937
121,079,937
Cost of Issuance
142,857
266,319
409,176
Underwriter’s Discount
263,175
499,300
762,475
$ 60,406,032
$121,845,556
$182,251,588
Total
$
Total
-
Refinancing Escrow
$ 60,000,000
Refunding
Structure of the Series JJ Bonds
• Tax-exempt
• Long-term bonds (final maturities greater than 10
years)
• Fixed rate, current interest, serial bonds
• Optional redemption: par call bonds within 10
years
• Competitive sale process
Competitive or Negotiated Sale?
Competitive Sale:
Sale process that includes the advertising of the bonds with the
sale date, time and place where bids will be taken. The bids are
then evaluated and the bonds are awarded to the underwriter
providing a bid resulting in the lowest true interest cost or net
interest cost.
Negotiated Sale:
Sale process in which the issuer, prior to the public sale date,
selects a qualified underwriter to act as book running senior
manager. The issuer often selects other underwriting firms to act
as co-managers. The managers, acting together as a syndicate,
make an offer to purchase the bonds from the issuer at a
negotiated price that will both produce the lowest interest cost to
the issuer and sell the bonds to investors.
Competitive or Negotiated Sale?
Attribute
Competitive Sale
Negotiated Sale
Issuer
General purpose government
Regular issuer
Independent authority,
Infrequent issuer
Credit Quality
“A” or better with stable outlook
General obligation or lease revenue
Below “A” - non-stable outlook
Project supported revenues
Market Conditions
Stable, predictable market
Strong investor demand
Volatile or declining market
Oversold market, heavy supply
Debt Structure
Tax-exempt, no concerns
Traditional serial, term, and coupon
Taxable
Innovative bond structuring
Marketing
Broad market participation
Limited need for pre-marketing
Ability to direct to local firms
Wide distribution including retail
Cost
Historically, spreads have been
lower for competitive
Equal or higher spreads than
competitive
The Series JJ Bonds are expected to be straight-forward, fixed rate, tax-exempt
bonds with a traditional 20 – 30 year structure. Currently, the bond market is
stable. Given these factors, we recommend using a competitive sale process.
Platte River Refunding Economics
• Series HH bonds are advance refundable with a call date on
June 1, 2019
• Under current market conditions, savings of over $11 million on a
PV basis could be achieved by refunding approximately $105.4
million of callable Series HH bonds
• Average annual savings of approximately $950k through
2029
• Some flexibility to structure savings in certain fiscal years if
desired
• If rates were to rise 0.25%, PV savings would be reduced by
approximately $2 million
Refunding Economics, cont.
PRPA | Refunding Screen | Series HH
Candidate
Individual PV Savings
New Yield
Par
Serial
6/1/2020
$8,385,000
5.00%
6/1/2019
0.98%
$241,233
2.88%
$241,233
2.88%
($27,462)
89.78%
89.10%
Serial
6/1/2021
$8,800,000
5.00%
6/1/2019
1.12%
$524,476
5.96%
$765,710
4.46%
($68,857)
88.39%
87.96%
Serial
6/1/2022
$9,240,000
5.00%
6/1/2019
1.33%
$759,962
8.22%
$1,525,672
5.77%
($135,100)
84.91%
84.18%
Serial
6/1/2023
$9,705,000
5.00%
6/1/2019
1.53%
$976,502
10.06%
$2,502,174
6.93%
($204,219)
82.70%
81.65%
Serial
6/1/2024
$10,190,000
5.00%
6/1/2019
1.72%
$1,172,748
11.51%
$3,674,922
7.93%
($276,178)
80.94%
79.53%
Serial
6/1/2025
$10,700,000
5.00%
6/1/2019
1.88%
$1,369,483
12.80%
$5,044,405
8.85%
($344,245)
79.91%
78.21%
Serial
6/1/2026
$11,235,000
5.00%
6/1/2019
2.00%
$1,587,860
14.13%
$6,632,265
9.72%
($404,014)
79.72%
77.80%
Serial
6/1/2027
$11,795,000
5.00%
6/1/2019
2.08%
$1,592,575
13.50%
$8,224,839
10.27%
($453,782)
77.82%
70.28%
Serial
6/1/2028
$12,385,000
5.00%
6/1/2019
2.18%
$1,562,098
12.61%
$9,786,937
10.59%
($515,302)
75.19%
63.36%
Serial
6/1/2029
$13,005,000
5.00%
6/1/2019
2.27%
$1,533,665
11.79%
$11,320,603
10.74%
($577,673)
72.64%
57.56%
($3,006,833)
79.01%
> 5% Savings and 50% Escrow Efficiency
Positive Savings and >50% Escrow Efficiency
Positive Savings
Negative Savings
$11,320,603
%
$
%
PV Savings
as % of
Option
Value
Maturity
As of February 11, 2016.
$
Negative Escrow
Arbitrage Efficiency
Component
$105,440,000
Coupon Call Date
Cumulative PV Savings
72.44%
Refunding Economics, cont.
• Refunding to capture interest rate savings (high-to-low)
• PV savings is the concept which takes into account the time value
of money
Date
Prior Debt Service
6/1/2016 $
2,636,000.00
Prior Receipts
$
2,123,444.00
Refunding Debt
Service
Prior Net Cash Flow
$
673,644.44
$
618,891.67
Present Value to
04/15/2016 @
2.1363884%
Savings
$
54,752.77
$
49,283.04
6/1/2017
5,272,000.00
-
5,272,000.00
4,344,000.00
928,000.00
903,222.22
6/1/2018
5,272,000.00
-
5,272,000.00
4,344,000.00
928,000.00
885,250.94
6/1/2019
5,272,000.00
-
5,272,000.00
4,344,000.00
928,000.00
867,637.23
6/1/2020
13,447,375.00
-
13,447,375.00
12,480,100.00
967,275.00
887,333.87
6/1/2021
13,432,750.00
-
13,432,750.00
12,465,400.00
967,350.00
870,190.44
6/1/2022
13,421,750.00
-
13,421,750.00
12,457,000.00
964,750.00
851,048.58
6/1/2023
13,413,125.00
-
13,413,125.00
12,449,700.00
963,425.00
833,468.70
6/1/2024
13,400,750.00
-
13,400,750.00
12,438,000.00
962,750.00
816,844.84
6/1/2025
13,388,500.00
-
13,388,500.00
12,425,250.00
963,250.00
801,148.15
6/1/2026
13,375,125.00
-
13,375,125.00
12,411,250.00
963,875.00
785,861.89
6/1/2027
13,359,375.00
-
13,359,375.00
12,396,625.00
962,750.00
769,473.60
6/1/2028
13,344,875.00
-
13,344,875.00
12,380,125.00
964,750.00
755,884.74
6/1/2029
13,330,125.00
-
13,330,125.00
12,367,500.00
962,625.00
739,846.72
$ 152,878,305.56
$ 139,897,283.33
$ 12,981,022.23
$ 11,315,791.51
$ 155,001,750.00
$ 2,123,444.44
Rating Agencies
Rating Agencies
• Three major ratings agencies are Moody’s Investors Service, Inc.
(“Moody’s”), Standard and Poor’s (“S&P”), and Fitch Ratings (“Fitch”)
• Municipal market generally requires two ratings, although PRPA currently
maintains ratings from all three
• Credit rating agencies are firms that analyze the probability of the debt
instrument returning all of the principal to the investor
• Municipal credit ratings are opinions of the investment quality of issuers
and issues in the municipal and tax-exempt markets
• Underwriters and investors rely upon the credit quality judgment made by
the rating agencies
• The municipal bond market has slightly different rating criteria from the
corporate debt market owing to the unique characteristics inherent in
public debt
• Municipal public power ratings are generally driven by:
• Revenue/Expenses and debt coverage
• Generation portfolio – both cost of power and compliance with
environmental regulations
• Competitive position and rates
• Management strength and strategic planning efforts
What is a Rating?
•
•
An alphabetic and/or numeric symbol
used to give relative indications of credit
quality.
Measures the risk to the investor that
issuer will default, both the willingness
and ability to pay.
Independent, objective & relative
assessments of both qualitative &
quantitative factors.
Moody’s
S&P
Fitch
Investment
Grade
•
Aaa
AAA
AAA
Aa
AA
AA
A
A
A
Baa
BBB
BBB
Non-Investment
Grade
Long-Term Municipal Ratings
Ba
BB
BB
B
B
B
Caa
CCC
CCC
Ca
CC
CC
C
C
C
Note: Moody’s ratings within certain categories are
modified by number (1, 2 and 3) while S&P and Fitch
are modified by “+” and “-” symbols.
Current Rating Agency Views
Summary of Rating Agency Views
Moody’s Investors Service
Richard Donner / Chee Mee Hu
Standard & Poor’s
Paul Dyson / Peter Murphy
Fitch Ratings
Stacey Mawson / Lina Santoro
Aa2
Stable Outlook
AA
Stable Outlook
AA
Stable Outlook
Strengths
— Sales to highly creditworthy participants with
weighted Aa2/Aa3 ratings under long-term all
requirements contract
— Take and pay contracts that extend to 2050
— Autonomous rate setting ability
— Very competitive wholesale rates
— Robust financial metrics, with very low debt
ratio
— Maintenance of conservative financial
policies
— Continued strong fixed charge coverage at
no less than 1.5x historically and projected
at 1.3x-2.1x
— Strong liquidity at approximately nine
months of operations
— Strong financial and operating policies
— Efficient, low cost generating resources that
enable PRPA to maintain competitive rates
— Low debt burden at 31% debt to
capitalization
— Low cost provider, with very competitive
rates for the region
— Sound and stable financial metrics, which
compare favorably to AA medians
— Court-validated all requirements contracts
that extend through 2050
— Diverse retail customer base and a stable
economy in the service territory
— Strong management of rates, including
raising rates for wholesale sales uncertainty
Concerns
— Significant concentration in coal generation
— Managing growth within the service territory
— Meeting future environmental compliance
requirements, including recently released
Clean Power Plan
— Lack of a debt service reserve fund
— Risks related to increasingly stringent
emissions standards for coal-fired
generation, which represented 81% of total
energy in 2014
— Plans to additional $130 million of bonds in
2016-2020 which could put pressure on
coverage metrics
— Environmental standards that have the
potential to be costly
— Variability in off-system market pricing
— Ongoing environmental laws and regulations
that will affect coal generation,
notwithstanding that PRPA assets appear
well positioned to comply with most recent
standards
— Debt service coverage has dipped below AA
medians, but expected to rebound
March Board Meeting –
Board Approvals
Basic Documents
To be reviewed and approved at the March Board
meeting:
• Eleventh Supplemental Power Bond Resolution
• Official Notice of Sale
• Preliminary Official Statement (POS)
• Refunding Trust and Escrow Agreement
• Continuing Disclosure Certificate
Questions / Discussion
Board of Directors Meeting
February 25, 2016
Community Solar Pilot
Board of Directors Meeting
February 2016
Purpose Today
• Review motivations for a system-wide community solar pilot
(all four municipalities)
• Introduce draft pilot program model concepts
• Consider key unknowns / uncertainties
• Next steps
Reasons to Offer Community Solar
Municipality Interest in
a New Solar Offering
Business Strategy
(Positioning for the Future)
WHAT WE’VE HEARD –
• Stakeholder pressure
• Reduce revenue erosion – retail and
wholesale
• Customer interest in expanded
choice
‒ Current offerings “not enough”
• Voluntary premium (wind)
• Increasing renewable supply in
overall mix (utility scale)
• Mitigate excessive net metering
payments (vs. cost of service / value)
• Position as a utility that offers solar
• Marketing / public relations benefits
• Collaborate to gain economy of scale
• Transition toward improved solar cost
allocation (less subsidy)
• “Chain of title” considerations
• Operations coordination (metering /
scheduling)
• Expand utility learning / experience
• Balance market messages to
customers
https://www.youtube.com/watch?v=JW24Xeh3xqI
Solar Cost Trend
DOE Sun Shot / NREL – August 2015
Photovoltaic System Pricing Trends: Historical, Recent and Near-Term Projections, 2105 Edition
77
Solar Growth in Four Municipalities
Cumulative Net Metered Solar Installed
(excludes Community Solar and Feed-in Tariff Solar)
Cumulative Capacity Installed (kW dc)
4,500
Average annual growth ~ 40%/yr
Capacity doubling every 2-3 years
(all third party marketers)
4,000
3,500
3,000
2,500
2,000
Solar Investment Tax Credit extended
Full value through 2019
Ramping down through 2022
1,500
1,000
500
0
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
System Level Pilot Program
Concepts
• ~ 1 MW pilot solar project size
• Residential market focus
‒ Approx. 300 to 400 customers
• Single site
‒ Location & specs TBD
• Counterparty collaboration:
‒ Solar developer/operator
‒ Solar program administration
(promotion / enrollment / billing data)
‒ Could be one “turn-key” provider
• “Buy all, sell all” model:
‒ Not net metered
‒ Participants continue to buy all energy
at existing Municipal retail rates
‒ Participants own kW “shares”
• Sell all energy from solar share to utility
• Pay capital costs / own generation
• Solar energy payment & share pricing
TBD
‒ Adequate to encourage participation
and compete with solar marketers
Energy Payment –
Possible Financial Perspectives
Marginal
System Benefits
Wholesale
Rate
Central
Station Solar
“Value of solar to
system”
“The competition”
“Comparable offering”
• Fuel savings (coal &
gas)
• Variable O&M reduction
• Surplus sales impact
• Reserve cost impact
• Capital investment delay
• CO2 cost
• Energy payment at net
value to the system
• Already losing revenue
to marketers of rooftop
solar at wholesale rate
• Support community solar
to same level as central
station (Rawhide Flats)
• Support community solar
to same level for our
product
• Energy payment at
contract price for
Rawhide solar
• Energy payment at
wholesale rate
Still gathering input from other utilities
Working with rate consultant
Visiting with solar program providers
(some may have no value today)
80
Project Related Activities
• Joint Municipal / Platte River team engagement
‒ Program concepts / planning / coordination
‒ Site identification / review
• Draft project charter being circulated
‒ Defining project scope / schedule / resources
• Conceptual discussions with Utility Directors
• Gathering input on Financial Perspectives
‒ Drives approach for program incentive levels
• Gathering additional market information
‒ Customer perspectives / other utility experience / vendors
• Evaluating potential grant funding for low income participants
• Continued communications with Board of Directors
Next Steps / Future Communications
• Ongoing – team collaboration (Municipalities & Platte River)
• March – Utility Director & Board meetings:
‒ Discuss financial metrics & incentive estimates
‒ Introduce IGA concepts
• April – Utility Director & Board meetings:
‒ Financial recommendations
‒ IGA approval
• March to May – RFP issuance / proposals / review
• May to June – City Councils/Town Board IGA approval
• July – Authorizing resolution for Community Solar Pilot
Questions / Discussion?
Board of Directors Meeting
February 25, 2016
Headquarters Campus
February 25, 2016
Headquarters Campus Project
Agenda
•
•
•
•
•
•
•
Purpose of today’s meeting
Review alternatives
Review cost and evaluation criteria
Staff recommendation
2016 Timeline
Design & input process
Next steps
– No decision is being requested from the Board in February
Four Alternates Evaluated
Alternate B
Alternate A
Fix existing
Teardown and rebuild
and add additional space
•Allows for growth
•Access critical
•Inefficient layout
•Limited Innovation
Opportunities
•Allows for growth
•Access critical
•Business continuity
•Efficient design
Alternate C
Greenfield site
•Right sized
•Sustainable
•Innovative
•Efficient layout
Alternate D
Greenfield site,
Lease
•Right sized
•Sustainable
•Innovative
•Efficient layout
Cumulative Costs for each Alternate
$120
$100
Cumulative dollars (Millions)
$80
$60
$40
$20
$2015
2020
2025
2030
2035
2040
2045
2050
Fiscal year
Alt. A
Alt. B
Alt. C
Alt. D
2055
2060
2065
Comparing the Alternates
A: Renovate
Existing Site
Safety
Business Disruption
Long-Term Cost
Energy Efficiency &
Innovation
Physical Security
Code Compliance
B: Rebuild
on Existing Site
C: New Site
D: New Site,
Lease Option
Feedback – What we’ve heard from Board
members
• Recognition of the need for a new HQ facility
• Questions about:
–
–
–
–
Location
Travel patterns
Investment in technology and innovation
What does Platte River staff want and need in a new facility
• Staff recommendation and discussion
Initial Timeline
Follow up with
Utility Directors
Present to
Board/Site Tours
CH2M Hill
Recommendation
Pre-Design &
Programming with
Board Input
Recommendation
to Board
Schematic
Design Phase
Board
updates
Follow up with
Utility Directors
Present Budget
to Board
Present to
Utility
Directors
Board
Selects
Alternate
Award Design
Contract
Regular
design
review with
project
stakeholders
and Board
December
November
September
August
July
June
May
April
March
February
January
December
November
October
2016
September
August
2015
Develop
Design RFP
Design & Input Process
User
Architect Selection
Pre-Design & Programming
Stakeholders
Groups
Project
Team
Schematic Design Phase
Design Development Phase
$2.5M
Construction Document Phase
General Contractor RFP
Construction Phase
Review
Input
Wrap Up
• What additional information does the Board need to move
forward with a decision to select Alternate A, B, C or D in
March?
– The Board’s decision to select Alternate A, B, C or D is necessary for
staff to proceed with developing an RFP to select a design firm, award
the design contract, and begin the design process
– Board input will be built into the design phase and coordinated by the
design team at multiple milestones once initial direction is provided
– No construction activity associated with Alternates B, C or D will occur
without final Board approval and authorization
Wrap Up
• Scope clarification
– Work to date has focused on replacing existing facilities with new
structures to accommodate current and future growth projections
with a basic/mid range investment and “business as usual”
• Additional campus design options (a menu of choices) and the inclusion of
potential technology and innovation concepts will be built into the pre
design and programming phase – for Board consideration and approval –
prior to any final design or construction commitment – once the preferred
alternate is selected
• Final budgeting and construction costs can be affected, influenced, and
driven by such design options
• This process will be facilitated and managed throughout by the design
team
Next Steps
Direction from
BOD at March
Meeting
Initiate 2016
Budgeted
Activities
Board of Directors Meeting
February 25, 2016