Powering Growth, Delivering Value
EEI Financial Conference l November 6-9, 2016
POWERING GROWTH
DELIVERING VALUE
Powering Growth, Delivering Value2
FORWARD LOOKING STATEMENTS
This presentation contains forward-looking statements based on current expectations, including statements regarding our earnings
guidance and financial outlook and goals. These forward-looking statements are often identified by words such as “estimate,”
“predict,” “may,” “believe,” “plan,” “expect,” “require,” “intend,” “assume” and similar words. Because actual results may differ
materially from expectations, we caution you not to place undue reliance on these statements. A number of factors could cause future
results to differ materially from historical results, or from outcomes currently expected or sought by Pinnacle West or APS. These
factors include, but are not limited to: our ability to manage capital expenditures and operations and maintenance costs while
maintaining high reliability and customer service levels; variations in demand for electricity, including those due to weather
seasonality, the general economy, customer and sales growth (or decline), and the effects of energy conservation measures and
distributed generation; power plant and transmission system performance and outages; competition in retail and wholesale power
markets; regulatory and judicial decisions, developments and proceedings; new legislation, ballot initiatives and regulation, including
those relating to environmental requirements, regulatory policy, nuclear plant operations and potential deregulation of retail electric
markets; fuel and water supply availability; our ability to achieve timely and adequate rate recovery of our costs, including returns on
and of debt and equity capital investments; our ability to meet renewable energy and energy efficiency mandates and recover related
costs; risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainty; current and future economic
conditions in Arizona, including in real estate markets; the development of new technologies which may affect electric sales or
delivery; the cost of debt and equity capital and the ability to access capital markets when required; environmental and other
concerns surrounding coal-fired generation, including regulation of greenhouse gas emissions; volatile fuel and purchased power
costs; the investment performance of the assets of our nuclear decommissioning trust, pension, and other postretirement benefit
plans and the resulting impact on future funding requirements; the liquidity of wholesale power markets and the use of derivative
contracts in our business; potential shortfalls in insurance coverage; new accounting requirements or new interpretations of existing
requirements; generation, transmission and distribution facility and system conditions and operating costs; the ability to meet the
anticipated future need for additional generation and associated transmission facilities in our region; the willingness or ability of our
counterparties, power plant participants and power plant land owners to meet contractual or other obligations or extend the rights for
continued power plant operations; and restrictions on dividends or other provisions in our credit agreements and ACC orders. These
and other factors are discussed in Risk Factors described in Part I, Item 1A of the Pinnacle West/APS Annual Report on Form 10-K for
the fiscal year ended December 31, 2015, which you should review carefully before placing any reliance on our financial statements,
disclosures or earnings outlook. Neither Pinnacle West nor APS assumes any obligation to update these statements, even if our
internal estimates change, except as required by law.
Powering Growth, Delivering Value3
PINNACLE WEST:
WHO WE ARE
We are a vertically integrated,
regulated electric utility in the
growing southwest United States
Pinnacle West (NYSE: PNW)
- Market Capitalization*: $8.5 billion
- Enterprise Value*: $12.8 billion
- Consolidated Assets: $15.5 billion
- Indicated Annual Dividend*: $2.62
- Dividend Yield*: 3.4%
Principal subsidiary:
- Arizona Public Service Company, Arizona’s largest
and longest-serving electric utility
Customers: 1.2 million (89% residential)
2016 Peak Demand: 7,051 MW
- All time high of 7,236 in July 2006
Generation Capacity: About 6,200 MW of owned or
leased capacity (~8,600 MW with long-term contracts)
- Including 29.1% interest in Palo Verde Nuclear
Generating Station, the largest in the U.S.
- Regulated utility provides stable, regulated
earnings and cash flow base for Pinnacle West
* As of October 31, 2016
Powering Growth, Delivering Value4
• Consolidated earned ROE more than 9.5% (weather-normalized) through 2016
• Annual dividend growth target of 5%, subject to declaration at Board of Director’s discretion
• Strong credit ratings and balance sheet
• Rate base growth of 6-7% (2015-2019); investing in a portfolio that is flexible, responsive, reliable
and cost-effective
Financial Strength
• Arizona’s long-term growth fundamentals remain largely intact, including population growth, job
growth and economic development
Leverage to Economic Growth
• Top quartile ratings in Power Quality and Reliability and Safety
• APS operates the Palo Verde Nuclear Generating Station, the largest nuclear plant in the United States
• Disciplined cost management
Operational Excellence
VALUE PROPOSITION
• At the forefront of utilities studying and deploying advanced infrastructure to enable reliable and
cost-efficient integration of emerging technologies into the grid and with customers
Modern Grid
• Working with Arizona Corporation Commission and key stakeholders to modernize rates
Proactively Addressing Rate Design
We are executing on our financial and operational objectives …
… while also advocating to ensure Pinnacle West and Arizona have a sustainable energy future
Powering Growth, Delivering Value5
2016 HIGHLIGHTS & ACCOMPLISHMENTS
Increased indicated annual dividend for fifth straight year, by 5%
Began construction on the $500M Ocotillo Modernization Project, including air permit approval
Completed major outages on Four Corners Units 4 and 5 and on-track with $400M SCR installation
Developed 37MW of Microgrids, including 25MW for the Department of the Navy at Yuma Marine
Corp Air Station
Joined the CAISO Energy Imbalance Market, with go live operations effective October 1st
On track for installation of our Advanced Distribution Management System, including advanced grid
technology installations
Completed development and entered testing phase of our new CIS system
Launched a new customer mobile app
Ranked in the top 10 nationally among large IOUs in the 2016 JD Power residential customer
satisfaction survey for Power Quality and Reliability
Completed the installation of 1,600 utility-owned residential rooftop solar systems
Completed 3 new transmission lines worth $146.5M investment
Successfully completed both Spring and Fall outages at Palo Verde Nuclear Generating Station
Palo Verde site average capacity factor maintained above 95%
Filed our first rate review in 5 years; proposing industry leading rate design
Completed hearings on the Value and Cost of Distributed Generation generic docket and preparing
for a final decision
Powering Growth, Delivering Value6
RATE BASE
APS’s revenues come from a
regulated retail rate base and
meaningful transmission business
$6.5
$8.3
$1.4
$1.8
2015 2016 2017 2018 2019
APS Rate Base Growth
Year-End
ACC FERC
Total Rate Base
Projected
Most Recent Rate Decisions
ACC - Proposed FERC
Rate Effective Date 7/1/2017 6/1/2016
Test Year Ended 12/31/2015* 12/31/2015
Rate Base $6.8B $1.4B
Equity Layer 56% 56%
Allowed ROE 10.5% 10.75%
*Adjusted to include post test-year plant in service through 6/30/2017
83%
17%
Generation & Distribution Transmission
Rate base $ in billions, rounded
Powering Growth, Delivering Value7
$263 $223 $220 $279
$66 $77
$234 $117 $44
$224
$197
$103
$58
$104
$1
$1 $201
$136
$211
$136
$340
$380
$399
$411
$85
$89
$75
$77
2015 2016 2017 2018
CAPITAL
EXPENDITURES
Capital expenditures are funded
primarily through internally
generated cash flow
($ Millions)
$1,233
$1,337
Other
Distribution
Transmission
Renewable
Generation
Environmental(1)
Traditional
Generation
Projected
$1,124
New Gas
Generation(2)
$1,057
• The table does not include capital expenditures related to 4CA’s 7% interest in Four Corners Units 4 and 5 of
$3 million in 2015, $30 million in 2016 and $27 million in 2017.
• 2016 – 2018 as disclosed in Third Quarter 2016 Form 10-Q.
(1) Includes Selective Catalytic Reduction controls at Four Corners with in-service dates of Q4 2017 (Unit 5) and Q1 2018 (Unit 4)
(2) Ocotillo Modernization Project: 2 units scheduled for completion in Q4 2018, 3 units schedule for completion in Q1 2019
Powering Growth, Delivering Value8
RESOURCE PLANNING
Future resources need projected
in excess of 3,500 MW by 2022
and over 5,400 MW by 2027
Gas
Coal
Nuclear
RE + DE
EE
Composition of Energy Mix by Resource*
36%
14%18%
18%
14%2032
Note: RE = Renewable Energy; DE = Distributed Energy; EE = Energy Efficiency
*Data shown is based on the Updated 2017 Preliminary
Integrated Resource Plan filed September 30, 2016.
-
2,000
4,000
6,000
8,000
10,000
12,000
14,000
2017 2019 2021 2023 2025 2027 2029 2031
Existing
Contracts
Future Grid-Scale
Generation
Total Load Requirements
MW
Existing Owned
Resources
2017-2032 Supply / Demand Gap
23%
27%26%
11%
13%2017
Powering Growth, Delivering Value9
ECONOMIC
INDICATORS
Arizona and Metro Phoenix remain
attractive places to live and do
business
Single Family & Multifamily Housing Permits
Maricopa County
Above-average job growth in
construction, financial services and
wholesale trade sectors
Arizona ranked 1st for projected job
growth
- Forbes September 2015
E
Metro Phoenix growth rate 3rd fastest
among top 15 metro areas
- U.S. Census Bureau March 2016
Housing construction on pace to have
its best year since 2007
Vacancy rates in office and retail space
have fallen to pre-recessionary levels
0%
5%
10%
15%
20%
25%
'07 '08 '09 '10 '11 '12 '13 '14 '15 16
Nonresidential Building Vacancy – Metro Phoenix
Vacancy Rate
Office
Retail
Industrial
3Q
0
10,000
20,000
30,000
40,000
'07 '08 '09 '10 '11 '12 '13 '14 '15 '16
Single Family Multifamily
Powering Growth, Delivering Value10
THE GRID IS EVOLVING – INCREASINGLY
DYNAMIC AND COMPLEX
Drivers for
Change
– Traditional grid built for
one-way flow
– Technology advancements
(storage, home energy
management)
– Changing customer needs and
demands
– Proliferation of distributed
solar energy, which does not
align with peak
The Modern
Grid
– New technologies to enable
two-way flow
– Proactive vs. reactive
operations and maintenance
– Modern rate structure
– New ways to interact with
customer
– Mobility for our field personnel
– Smarter, more flexible real-
time system operations
– Support consumer products
and services
– Addresses cybersecurity
APS Laying
Foundation for
the Future
– Solar R&D initiatives
• Solar Partner Program
• Solar Innovation Study
– Smart meters fully deployed
– Investing in peaking capacity upgrades
(Ocotillo)
– Evaluating storage
• Battery pilot investments
• Microgrids
– Software upgrades for distribution
operations and customer service
– Ensuring our people have the relevant
skill sets
• Grid stability, power quality and reliability remain the core of a sustainable electrical system
• APS is at the forefront of utilities designing and planning for the electric grid
• Rates need to be modernized to enable advanced technologies and to reflect the true cost of service
Powering Growth, Delivering Value11
RENEWABLE
RESOURCES
APS is a leader in solar
Aragonne Mesa
Wind
90 MW
Snowflake
Biomass
14 MW
Glendale Landfill
Biogas
2.8 MW
Salton Sea
Geothermal
10 MW
• Solar* 1,050 MW
• Wind 289 MW
• Biomass 14 MW
• Geothermal 10 MW
• Biogas 6 MW
APS currently has over 1,350 MW
of renewable resources:
AZ Sun includes 4 MW of other APS owned utility scale solar;
Distributed Generation (DG) includes 15 MW of APS owned.
PPA is primarily 250 MW Solana Concentrated Solar Facility.
PPA
310 MW
DG
566 MW
AZ Sun
174 MW
* As of November 3, 2016 – with additional 86 MW under development
APS Solar Portfolio*
Yuma Foothills
Solar
35 MW
Powering Growth, Delivering Value12
ROOFTOP SOLAR CUSTOMERS USE THE GRID
24 HOURS PER DAY
TYPICAL GRID INTERACTION FOR ROOFTOP SOLAR
• Customers with rooftop solar systems do not pay for all of the electric services they use
• These unpaid costs are then paid by other customers (through higher rates) that can’t have or don’t
want solar
• This issue will only get bigger over time
Powering Growth, Delivering Value13
RESIDENTIAL VS.
UTILITY-SCALE SOLAR
Performance at system peak
On June 19th, APS customers hit “peak demand” for 2016 using more than 7,400 MW of electricity
• Noon: Customer demand still increasing; rooftop
solar peaks and begins to decline
• 5:30PM: Customer demand peaks; rooftop solar
producing at 28% of total capacity
• 7:30PM: Rooftop output at zero, but demand still
above 6,900 MW of power
• Solar panels at 8 of the AZ Sun plants rotate to
track the sun, achieving highest production earlier
in the day and maintaining it later
• At peak demand, utility-scale solar producing at
72% of total capacity
Residential Rooftop Solar AZ Sun Utility-Scale Solar
235
80
0
6,093
7,445
6,908
0
2,000
4,000
6,000
8,000
0
100
200
300
400
500
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
M
W
Hour Ending
123
7445
0
2,000
4,000
6,000
8,000
0
100
200
300
400
500
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
M
W
Hour Ending
AZ Sun
System Load
Residential Rooftop
System Load
Powering Growth, Delivering Value14
249
357 339
442
610
710 641
783
871 939
523
836
487
681
833
717
1159 1162
1353
1146
1005
1196
1087
1178
1170
777
1290
1031
1357
1547 1520
2315
1888
0
250
500
750
1000
1250
1500
1750
2000
2250
2500
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2014 Applications 2015 Applications 2016 Applications
* Monthly data equals applications received minus cancelled applications. As of September 30, 2016, over 49,000
residential grid-tied solar photovoltaic (PV) systems have been installed in APS’s service territory, totaling 380 MWdc of
installed capacity. Excludes APS Solar Partner Program residential PV systems.
Note: www.arizonagoessolar.org logs total residential application volume, including cancellations. Solar water heaters can also be found
on the site, but are not included in the chart above.
RESIDENTIAL PV
APPLICATIONS* 10 18 22 44 51
57
74
99
2009 2011 2013 2015 2016
Residential DG (MWdc) Annual Additions
YTD
Powering Growth, Delivering Value15
SOLAR PARTNER
PROGRAM
Learning how to efficiently enable
the integration of rooftop solar
and battery storage with our grid
• Overview
– Installing 10 MW of APS-owned residential PV systems; approximately 1,600 systems with average
system size of 6kW
– Advanced controllable inverters that can vary power output depending on grid conditions
– 4 MW of grid-tied battery storage on 2 of the participating feeders
– Collect and analyze real time data on energy production, energy usage, power regulation
capabilities and curtailment options
– Participating customers receive monthly bill credits through 20-year life
• Benefits
− Study system benefits (i.e. strategic deployment orientation,
advanced inverters, etc.)
− Provides support for advanced rate structure
− Provides an alternative for customers who cannot afford solar
or do not want a lease
• Expected timeline
– Installations through mid-2016
– Technology evaluation in 2016/2017
Powering Growth, Delivering Value16
SOLAR INNOVATION
STUDY
Examining the integration of
behind the meter advanced
technologies with demand-based
rates
• Overview
– Installing APS-owned residential PV systems on 75 homes
with various configurations of battery storage, energy
efficiency, demand controls and smart thermostats
connected to a cloud based energy management system
• Benefits
– Identify effective technology packages that can shift load
and minimize grid challenges
– Gain insight into customer behavior and preferences in use of ‘next generation’ demand control and
load shifting technologies
– Identify strategies to support sustainable growth of renewable resources
– Inform rate design in development of modernized demand based residential rates
• Expected timeline
– Design and installation in 2016/2017
– 5-year study
Powering Growth, Delivering Value17
• Total Capacity: 4,000 MW (3 units)
– APS operated
– APS share: 1,146 MW
– Output: 32.5 million MWh in 2015
– Approximately 2,700 employees
• Fukushima-related impacts
– Project completed in Q2 2016
– Total Fukushima-related costs approximately $126 million
(APS share is 29.1%)
– National Strategic Alliance for FLEX Emergency Response
(SAFER) Centers are located in Phoenix and Memphis,
opened in 2014
PALO VERDE NUCLEAR
GENERATING STATION
Largest nuclear generating plant
in the United States
Palo
Verde
Phoenix
Low risk of natural events at Palo Verde
In Service License*
Unit 1 1985 2045
Unit 2 1986 2046
Unit 3 1987 2047
* NRC approved 20-year license extensions in April 2011.
Note: Each of the pressurized water reactor units has a planned
refueling outage every 18 months (i.e. two total outages per year).
Powering Growth, Delivering Value
2016 APS RATE CASE
Powering Growth, Delivering Value19
Focus on
Clean Energy
Focus on
Customers
Focus on
Innovation
Focus on
Sustainability
• Generate power from
diverse portfolio and
support environmental
improvements
• Create sustainable path
forward for flexible
resource portfolio
• Optimize customer
service and reliability
• Better align rates with
the true cost of service
• Provide rate gradualism
and bill stability for
customers by managing
overall rate trajectory
and the transition to
new rate design
• Prudently invest in new
technologies
• Implement new
customer information
system to enable
adaptable customer
programs and rates
• Modernize rates to
enable advanced
technologies and grid
services
• Achieve an earned
return that provides for
financial stability and
allows for sustainable
investments in Arizona
• Maintain structure of
constructive regulatory
support
• Improve concurrent cost
recovery of plant
investments
2016 RATE CASE
FRAMEWORK
“A Bridge to the Future”
Rate Case Objectives
Powering Growth, Delivering Value20
2016 APS RATE CASE APPLICATION
• Filed June 1, 2016
• Propose new rates go into effect on July 1, 2017
• Docket Number: E-01345A-16-0036
• Additional details, including filing, can be found at
http://www.azenergyfuture.com/rate-review/
Procedural Schedule
Staff and Intervenor Direct Testimony (ex rate design)
Staff and Intervenor Direct Testimony (rate design)
APS Rebuttal Testimony
Staff and Intervenor Surrebuttal Testimony
Prehearing Conference
APS Rejoinder Testimony
Proposed Hearing Commencement Date
December 21, 2016
January 27, 2017
February 17, 2017
March 10, 2017
March 13, 2017
March 17, 2017
March 22, 2017
Powering Growth, Delivering Value21
2016 RATE CASE
KEY FINANCIALS
APS has requested a rate increase
to become effective July 1, 2017
Test year ended December 31, 2015
Total Rate Base - Adjusted $8.01 Billion
ACC Rate Base - Adjusted $6.77 Billion
Allowed Return on Equity 10.5%
Capital Structure
Long-term debt 44.2%
Common equity 55.8%
Base Fuel Rate (¢/kWh) 2.9882
Post-test year plant period 18 months
Overview of Rate Increase ($ in Millions)
Total stated base rate increase (inclusive of existing adjustor transfers) $ 433.4 15.00%
Less: Transfer to base rates of various adjustors already in effect (267.5) (9.26)
Net Customer Bill Impact $ 165.9 5.74%
Powering Growth, Delivering Value22
2016 RATE CASE
KEY FINANCIALS
APS has requested a rate increase
to become effective July 1, 2017
Overview of Rate Increase ($ in Millions) – Key Components
Post-Test Year Plant Additions $ 98.1
Fair Value Increment 51.9
ROE Increase from 10.0% to 10.5% 29.3
Increase due to Changes in Depreciation Schedules 81.4
Decrease Fuel and Purchased Power over Base Rates (61.7)
Decrease in Other Costs (33.1)
Total Base Rate Increase $ 165.9
Powering Growth, Delivering Value23
2016 RATE CASE SUMMARY
Focus on
Clean Energy
Focus
on Customers
Focus
on Innovation
Focus on
Sustainability
Ocotillo Modernization
Project
• Requesting cost deferral
order from in-service
dates in 2018 and 2019 to
effective date of rates in
next rate case
Four Corners Selective
Catalytic Reduction (SCR)
Equipment
• Requesting cost deferral
order from in-service
dates to incorporation of
the SCR costs in rates
using a step-increase
beginning in 2019
Residential Rate Design
Modernization
• Transition to 3-part
residential rate structure
including a variable
(energy kWh) charge, a
fixed (basic service)
charge, and a demand
charge
• Modify net energy
metering to differentiate
compensation between
energy consumed on site
and exported energy
General Service
(Business)
• Retire AG-1; introduce
aggregation discount for
customers with multiple
sites, a new rate for
customers with extra high
load factors and a
economic development
rate
Solar Partners Programs
• Installing 10 MW of
APS-owned residential PV
systems on 1,600 homes
with advanced inverters,
including 4 MW of battery
storage
Red Rock Solar
Generating Station
• 40 MW utility-scale solar
facility (post-test year
plant)
Microgrid Projects
• Two microgrids in service
by 4Q16; partnered with
Marine Corps Air Station
Yuma and Aligned Data
Center in Phoenix
Power Supply Adjustment
• Include environmental
chemical costs,
generation-related water
costs, and energy storage
products from 3rd party
providers
Environmental
Improvement Surcharge
• Increase from ~$5M total
cap to $10M year-over-
year cap
Depreciation Rate
Changes
• Change depreciation life
schedules including Cholla
Units 1 & 3, Ocotillo Units
1 & 2, Yucca Units 1-4
and AMI meters
Powering Growth, Delivering Value24
APS COST OF SERVICE
Appropriate to place residential
solar customers into a unique
sub-category of customers
108%
86%
Percent of Cost to Serve*
Residential
Solar
Customers
Demand
Rate
71%
• Cost of service shows disparities in ratio
of allocated costs to provide electric
service, and what customer classes pay
for the services received
• Solar customers on an energy-based rate
avoid approximately $72 per month
based on proposed rates
• Current rate structure results in 96% of
customers paying more than they should
to subsidize rooftop solar
• APS is the first utility to conduct a full
cost of service study considering solar
customers as a separate class Energy Rate
38%
Total
General
Service
(Business)
Customers Total
Residential
Customers
* Test-year ended December 31, 2015 based on current rates
Powering Growth, Delivering Value25
Focus Area Current State Rate Case Objective
Time-of-Use
Rates (TOU)
• > 50% of residential customers are on a
TOU rate
• On-peak hours from 12-7 PM (M-F)
• TOU difference in on-peak prices that are 4
times the off-peak prices
• Most residential customers on a TOU rate
• On-peak hours from 3-8 PM (M-F) to better
align with system peak
• TOU difference in on-peak prices that are 2
times the off-peak prices
Demand
Rates
• 11% of residential customers are on demand
rates, more than any other electric utility
• Most residential customers on demand rates
• Calculated on the highest demand averaged
over a one-hour period during the on-peak
period each month
Basic Service
(Fixed)
Charge
• Customers pay basic service charge ranging
from $8.67 - $16.91 per month
• Set basic service charge for all rate classes
ranging from $14 - $24 per month
Net Metering • Excess power compensated at full retail price • Excess power compensated at export price
aligned with avoided cost
• Recovery of cost to purchase through existing
PSA mechanism
• Grandfather qualified rooftop solar customers
Lost Fixed
Cost
Recovery
(LFCR)
• 1% year-over-year adjustment cap based on
total revenues
• Recovers portion of costs reduced by energy
efficiency (EE) and distributed generation
(DG) programs
• Similar construct, but increase year-over-year
adjustment cap to 2% based on total
revenues
• Increased portion of lost fixed costs eligible for
recovery
RATE DESIGN
MODERNIZATION
Rate design that better aligns
pricing with cost to serve and
leverages existing platform
Powering Growth, Delivering Value26
RATE DESIGN
MODERNIZATION
Key residential rate proposals
designed to reduce cost shift
among customers
• Streamlined rate choices for residential
customers including combinations of the
following:
– Reduced kWh charges for variable portion
(energy rate)
– Increased fixed charge component (basic
service charge)
– Variations of new demand (kW) charge
applied to on-peak hours
• Measured using a customer’s peak
demand during on-peak hours
(3-8 pm, Monday-Friday)
• Peak demand then multiplied by a
demand rate
• Example:
– 5kW demand during on-peak*
– $6.60/kW demand rate (R-1 rate plan)
– 5kW x $6.60 = $33.00 demand charge
Variable Variable
(energy rate per kWh)
Fixed
Fixed
(basic service charge)
Demand
(demand rate per kW)
Current
Customer Bill
Proposed
Customer Bill
* Peak demand is calculated on the highest demand averaged over a one-hour period during the on-peak period each month.
Powering Growth, Delivering Value27
RATE DESIGN:
A SOLID FOUNDATION
TO BUILD ON
Over 50% of APS residential
customers are already on
time-of-use rates, including
11% on demand rates
0%
25%
50%
75%
100%
Standard TOU - Energy TOU - Demand
Powering Growth, Delivering Value28
OCOTILLO MODERNIZATION PROJECT AND
FOUR CORNERS SCRs
Ocotillo Modernization
Project Four Corners SCRs
In-Service Dates
Units 6, 7 – Fall 2018
Units 3, 4 and 5 – Spring 2019
Unit 5 – Late 2017
Unit 4 – Spring 2018
Total Cost (APS) $500 million $400 million
Estimated Cost Deferral $45 million (through 2019) $30 million (through 2018)
Rate Request
Requesting cost deferral from date of
commercial operation to the effective
date of rates in next rate case
Requesting cost deferral order from
time of installation to incorporation of
the SCR costs in rates using a step
increase beginning in 2019
• Included in the 2016 rate case application, APS is requesting Accounting Deferral
Orders for two large generation-related capital investments
– Ocotillo Modernization Project: Retiring two aging, steam-based, natural gas units,
and replacing with 5 new, fast-ramping, combustion turbine units
– Four Corners Power Plant: Installing Selective Catalytic Reduction (SCR)
equipment to comply with Federal environmental standards
Powering Growth, Delivering Value
APPENDIX
Powering Growth, Delivering Value30
LEADERSHIP TEAM
Our top executives have more
than 100 combined years of
creating shareholder value in the
energy industry
Don Brandt
Chairman & Chief
Executive Officer
Mark
Schiavoni
EVP & Chief
Operating
Officer
Jeff
Guldner
SVP
Public Policy
Bob
Bement
EVP & Chief
Nuclear
Officer
Jim
Hatfield
EVP & Chief
Financial
Officer
Powering Growth, Delivering Value31
Bob
Stump (R)*
Tom
Forese (R)
Doug
Little (R)
Chairman
Terms to January 2019Terms to January 2017
Bob
Burns (R)
Other State Officials
Andy
Tobin (R)
ARIZONA CORPORATION COMMISSION
* Term limited - elected to four-year terms (limited to two consecutive)
** Submitted resignation to become effective December 2016
ACC Utility Division Director - Tom Broderick**
RUCO Director - David Tenney
Powering Growth, Delivering Value32
2016 KEY DATES
ACC Key Dates / Docket # Q1 Q2 Q3 Q4
Key Recurring Regulatory Filings
Lost Fixed Cost Recovery
E-01345A-11-0224 Jan 15
Transmission Cost Adjustor
E-01345A-11-0224 May 15
Renewable Energy Adjustor
E-01345A-16-0238 Jul 1
2017 DSM Implementation Plan
E-01345A-16-0176
Nov 18: Workshop
Dec 1: File energy
storage plan
APS Rate Case
E-01345A-16-0036 Jan 29: NOI Filing Jun 1: Initial filing
Dec 21: Direct
Testimony
Resource Planning and Procurement
E-00000V-15-0094
Feb 9: Stakeholder Mtg.
Mar 1: Prelim IRP filed
Jul 18: Prelim IRP
Workshop
Sep 30: Update to
Prelim IRP*
Reducing System Peak Demand Costs
E-00000J-16-0257
Aug 4: Initial workshop
TBD: Second workshop
Value and Cost of Distributed Generation
E-00000J-14-0023
Feb 25: DG Methodologies
& Supporting Testimony
Apr 7: Rebuttal Testimony
and Alternate Proposal
Apr 15: Pre-hearing
Apr 18: Hearing
Jun 8-9 Hearing
Jun 13: Responses
Jul: Initial Briefs
Aug 5: Reply Briefs
Oct 7: ALJ ROO
Dec 13: Scheduled for Consideration at
ACC Open Meeting
Review, Modernization and Expansion of
Arizona Renewable Energy Standards
E-00000Q-16-0289
TBD TBD
ACC Open Meetings ACC Open Meetings Held Monthly
* April 2017: Final IRP due
Other K y Dates Q1 Q2 Q3 Q4
Arizona State Legislature In session Jan 11- May 7 (Adjourned)
Elections Aug 30: Primary Nov 8: General
All Source Request for Proposal (RFP) Mar 11: RFP Issued Jun 9: Responses Due TBD
Powering Growth, Delivering Value33
ARIZONA ELECTRIC UTILITIES
GENERAL RATE CASES
UNS Electric (93,000 customers)
Docket # E-04204A-15-0142
Application Filed May 5, 2015
Hearing (Mar 1 – 24, 2016)
Decision in Phase One (Decision No. 75697, Aug 18, 2016)
UNSE Customer Education Plan on Rates – Due Sep 30, 2016
Phase Two (Net Metering Issues) Testimony – Expected Dec 2016
Phase Two Hearing – Expected Jan 2017 (if necessary)
Phase Two Decision – Expected Mar 2017
Tucson Electric Power Company (415,000 customers)
Docket # E-01933A-15-0322
Application Filed Nov 5, 2015
Intervenor and Staff Direct Testimony (Jun 2016)
Rebuttal Testimony (Jul 25, 2016)
Non-unanimous Revenue Requirement Settlement Filed (Aug 15, 2016)
Settlement Direct Testimony (Aug 25, 2016)
Settlement Reply Testimony (Sep 1, 2016)
Hearing Begins (Sep 8, 2016)
Phase One Decision – Expected Dec 2016
Phase Two (Net Metering Issues) Testimony – Expected Dec 2016
Phase Two Hearing – To Be Scheduled
Sulphur Springs Valley Electric Cooperative (58,000 customers)
Docket # E-01575A-15-0312
Application Filed Aug 31, 2015
Direct Testimony - Ex Rate Design, Cost of Service (Mar 18, 2016)
Direct Testimony - Rate Design, Cost of Service (Apr 1, 2016)
Rebuttal Testimony (Apr 15, 2016)
Surrebuttal Testimony (May 4, 2016)
Rejoinder (May 11, 2016)
Prehearing (May 13, 2016)
Hearing (May 17, 2016) – Concluded May 27
ALJ Recommended Order (Oct 12, 2016)
Decision Expected at October ACC Open Meeting (Oct 27, 2016)
Trico Electric Cooperative (38,000 customers)
Docket # E-01461A-15-0363
Application Filed Oct 23, 2015
Direct Testimony - Ex Rate Design, Cost of Service (May 4, 2016)
Direct Testimony - Rate Design, Cost of Service (May 25, 2016)
Rebuttal Testimony (Jun 22, 2016)
Surrebuttal Testimony (Jul 8, 2016)
Non-unanimous Revenue Requirement Settlement (Jul 8, 2016)
Direct Settlement Testimony (Jul 29, 2016)
Reply Settlement Testimony (Aug 12, 2016)
Hearing (Aug 17, 2016)
Decision Expected December 2016
Powering Growth, Delivering Value34
FINANCIAL OUTLOOK Key Factors & Assumptions as of November 3, 2016
Assumption Impact
Retail customer growth • Expected to average about 2-3% annually
• Modestly improving Arizona and U.S. economic conditions
Weather-normalized retail electricity
sales volume growth
• About 0.5-1.5% after customer conservation and energy efficiency and
distributed renewable generation initiatives
Assumption Impact
AZ Sun Program • Additions to flow through RES until next base rate case
• First 50 MW of AZ Sun is recovered through base rates
Lost Fixed Cost Recovery (LFCR) • Offsets 30-40% of revenues lost due to ACC-mandated energy efficiency and
distributed renewable generation initiatives
Environmental Improvement
Surcharge (EIS)
• Assumed to recover up to $5 million annually of carrying costs for government-
mandated environmental capital expenditures
Power Supply Adjustor (PSA) • 100% recovery as of July 1, 2012
Transmission Cost Adjustor (TCA) • TCA is filed each May and automatically goes into rates effective June 1
• Beginning July 1, 2012 following conclusion of the regulatory settlement,
transmission revenue is accrued each month as it is earned.
Four Corners Acquisition • Four Corners rate increase effective January 1, 2015
Potential Property Tax Deferrals (2012 retail rate settlement): Assume 60% of property tax increases relate to tax
rates, therefore, will be eligible for deferrals (Deferral rates: 50% in 2013; 75% in 2014 and thereafter)
Gross Margin – Customer Growth and Weather (2016-2018)
Gross Margin – Related to 2012 Retail Rate Settlement
Outlook Through 2016: Goal of earning more than 9.5% Return on Equity (earned Return on Equity based on average
Total Shareholder’s Equity for PNW consolidated, weather-normalized)
Powering Growth, Delivering Value35
DIVIDEND GROWTH
Pinnacle West’s indicated annual
dividend is $2.62 per share;
targeting ~5% annual dividend
growth
$2.10
$2.18
$2.27
$2.38
$2.50
$2.62
2011 2012 2013 2014 2015 2016 2017 2018
Dividend Growth Goal
Indicated Annual Dividend Rate at Year-End
Projected
Future dividends subject to declaration at Board of Directors’ discretion.
Powering Growth, Delivering Value36
Credit Ratings
• A- rating or better at S&P, Moody’s and Fitch
2016 Major Financing Activities
• $250 million 10-year 2.55% APS senior unsecured
notes issued September 2016
• $350 million 30-year 3.75% APS senior unsecured
notes issued May 2016
• $100 million term loan closed April 2016
We are disclosing credit ratings to enhance understanding of
our sources of liquidity and the effects of our ratings on our
costs of funds.
BALANCE SHEET STRENGTH
$50
$600
$250
$125
$-
$100
$200
$300
$400
$500
$600
2017 2018 2019 2020
APS PNW
($Millions)
Debt Maturity Schedule
Powering Growth, Delivering Value37
2010 2011 2012 2013 2014 2015
APS
FFO / Debt 23.7% 23.6% 27.7% 31.5% 27.5% 29.7%
FFO / Interest 3.3x 4.2x 4.8x 5.6X 5.5x 5.8x
Debt /
Capitalization 52.6% 52.9% 50.7% 47.7% 45.3% 45.8%
Pinnacle West
FFO / Debt 22.3% 23.0% 26.7% 29.8% 26.5% 28.9%
FFO / Interest 3.1x 3.8x 4.4x 4.9X 5.2x 5.6x
Debt /
Capitalization 54.6% 54.4% 52.1% 49.1% 46.7% 47.0%
CREDIT RATINGS AND
METRICS
Key credit metrics remain strong
Source: Standard & Poor’s
APS Parent
Corporate Credit Ratings
Moody’s A2 A3
S&P A- A-
Fitch A- A-
Senior Unsecured
Moody’s A2 -
S&P A- -
Fitch A -
Note: Moody’s, S&P, and Fitch all rate
Outlook for APS and Parent as “Stable”
We are disclosing credit ratings to enhance
understanding of our sources of liquidity and the
effects of our ratings on our costs of funds.
Powering Growth, Delivering Value38
OPERATIONS &
MAINTENANCE
OUTLOOK
Goal is to keep O&M per kWh flat,
adjusted for planned outages
$754 $761 $788
$805 $772
$150 $124
$137 $103
$96
$83
2011 2012 2013 2014 2015 2016E
PNW Consolidated RES/DSM*
*Renewable energy and demand side management expenses are offset by adjustment mechanisms.
($ Millions)
$825 -
$845
Powering Growth, Delivering Value39
500
550
600
650
700
750
OPERATIONAL EXCELLENCE
30.230.430.4
30.8 30.6
31.231.3
31.9
31.4
32.332.5
20
22
24
26
28
30
32
34
1998 2001 2004 2007 2010 2013
108
97
65
58
47
35
44 43
0
30
60
90
120
2008 2009 2010 2011 2012 2013 2014 2015
Palo Verde
Palo Verde has exceeded its own record for generation - 32.5 million
megawatt-hours annual production in 2015. Palo Verde is the only plant
in the U.S. to exceed 30M MW annual production.
Safety
APS achieved another safe year in 2015. APS ranks in the
Top Quartile of electric utility companies.
0
20
40
60
80
100
2008 2009 2010 2011 2012 2013 2014 2015
APS Industry Top Quartile
Power Quality and Reliability
Ranked 9th highest nationally among 53 large investor-owned electric
utilities in 2016 J.D. Power residential customer survey.
Lowering Outage Time Per Customer
Top quartile in industry over past several years.
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Industry Average
APS
2015
Powering Growth, Delivering Value40
• Cumulative savings from energy
efficiency programs must be equivalent
to 22% of annual retail sales by 2020
• Annual milestones in place to measure
progress toward cumulative 2020 goal
– 9.5% by 2015
– 22% by 2020
ARIZONA’S RENEWABLE RESOURCE AND
ENERGY EFFICIENCY STANDARDS
• Portion of retail sales to be supplied by
renewable resources
– 6% by 2016
– 15% by 2025
• Distributed energy component
– 30% of total requirement
Energy Efficiency RequirementsRenewable Energy (RES) Requirements
APS on track to double 2016
requirement
APS on track to meet target
Powering Growth, Delivering Value41
• 10-Year Transmission Plan filed January 2016
(115 kV and above)
– 110 miles of new lines
• Also includes:
– Delaney-Palo Verde 500kV (2016)
– Delaney-Sun Valley 500kV (2016)
– Sun Valley-Trilby Wash 230kV (2016)
– Morgan-Sun Valley 500kV (2018)
– North Gila-Orchard 230kV (2021)
• Projects to deliver renewable energy approved by
ACC
• Transmission investment diversifies regulatory
risk
– Constructive regulatory treatment
– FERC formula rates and retail adjustor
APS TRANSMISSION
Strategic transmission investment
is essential to maintain reliability
and deliver diversified resources
to customers
Legend
Planned lines
Existing lines
Solar potential area
Wind potential area
Phoenix
Flagstaff
Tucson
Powering Growth, Delivering Value42
BRIGHT CANYON ENERGY
TRANSCANYON
A 50/50 Joint Venture formed with BHE U.S.
Transmission, a subsidiary of Berkshire Hathaway
Energy, to develop, build and own transmission
infrastructure for the western United States. In
2016, formed a strategic alliance with Pacific Gas
and Electric Company to jointly pursue competitive
transmission opportunities solicited by the California
Independent System Operator (CAISO)
BRIGHT CANYON ENERGY
Pinnacle West subsidiary formed to pursue long-term
growth opportunities in the electric energy industry
Powering Growth, Delivering Value43
Mechanism Adopted / Last Adjusted Description
Power Supply Adjustor
(“PSA”)
April 2005 /
February 2016
• Recovers variance between actual fuel and purchased power costs and
base fuel rate
• Includes forward-looking, historical and transition components
Renewable Energy
Surcharge (“RES”)
May 2008 /
February 2016
• Recovers costs related to renewable initiatives
• Collects projected dollars to meet RES targets
• Provides incentives to customers to install distributed renewable
energy
Demand-Side
Management
Adjustment Clause
(“DSMAC”)
April 2005 /
March 2014
• Recovers costs related to energy efficiency and DSM programs above
$10 million in base rates
• Provides performance incentive to APS for net benefits achieved
• Provides conservation education, rebates and other incentives to
participating customers
Environmental
Improvement
Surcharge (“EIS”)
July 2007 /
April 2016
• Allows recovery of certain carrying costs for government-mandated
environmental capital projects
• Capped at $5 million annually
Transmission Cost
Adjustor (“TCA”)
April 2005 /
June 2016
• Recovers FERC-approved transmission costs related to retail customers
• Resets annually as result of FERC Formula Rate process (see below)
FERC Formula Rates 2008 /
June 2016
• Recovers transmission costs based on historical costs per FERC Form 1
and certain projected data
Lost Fixed Cost
Recovery (“LFCR”)
July 2012 /
May 2016
• Mitigates loss of portion of fixed costs related to ACC-approved energy
efficiency and distributed renewable generation programs
REGULATORY
MECHANISMS
We have achieved a supportive
regulatory structure and
improvements in cost recovery
timing
Powering Growth, Delivering Value44
• FERC Formula Rates adopted in 2008
• Adjusted annually with 10.75% allowed ROE
• Based on FERC Form 1 and projected closings
– Update filed each May
– Annual rate true-up compares projected revenue requirement to actual, with variance
incorporated into next annual update
• Retail portion flows through ACC Transmission Cost Adjustor (TCA)
REGULATORY
MECHANISMS (TCA)
We have achieved constructive
transmission rate treatment with
annual adjustments
As Filed 2016 2015 2014
Annual
Rate
Increase
Rate
Effective
Date
Annual
Rate
Increase
Rate
Effective
Date
Annual
Rate
Increase
Rate
Effective
Date
Retail Portion (TCA) $25M 6/1/2016 $(7)M 6/1/2015 $5M 6/1/2014
Wholesale Portion -- 6/1/2016 $(11)M 6/1/2015 $1M 6/1/2014
Total Increase
(Decrease) $25M $(18)M $6M
Equity Ratio 56% 58% 58%
Rate Base (Year-End) $1.4B $1.3B $1.3 B
Test Year 2015 2014 2013
Powering Growth, Delivering Value45
6/1
Rate Goes
Into Effect
REGULATORY
MECHANISMS (TCA)
We have achieved constructive
transmission rate treatment with
annual adjustments
2015 2016
JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC
6/1
Rate Goes
Into Effect
~5/15
File/Post
FERC Rate
~5/1
File FERC
Form 1
~5/15
File/Post
FERC Rate
~5/1
File FERC
Form 1
• New accounting treatment began July 1, 2012, effective with 2012 Settlement Agreement
• Quarterly true-ups can occur throughout the year
2015 Revenue
2015 Rates
(Including True-Up)
2016 Rates
(Including True-Up)
2016 Revenue
Quarterly True-Ups Quarterly True-Ups
Powering Growth, Delivering Value46
2012 2013 2014 2015 2016
2016 Revenue
2015 Revenue
2014 Revenue
2013 Revenue
2012 Revenue
Rate Recovery
• Lost Fixed Cost Recovery (LFCR) was implemented
as part of the July 2012 settlement
– Estimated to offset 30-40% of revenues lost
due to ACC-mandated energy efficiency (EE)
and distributed renewable generation (DG)
initiatives
• Annual filing by January 15th each year with new
rates typically in effect March 1st, based on the EE
and DG savings from the preceding calendar year
– Subject to an annual 1% year-over-year cap
based on applicable company revenues
• Revenue accrued each month as it is earned,
creating a regulatory asset since the rates lag
REGULATORY
MECHANISMS (LFCR)
Lost Fixed Cost Recovery
2013 ACC
Order
2014 ACC
Order
2015 ACC
Order
2016 ACC
Order
Rates Effective March 2013 March 2014 March 2015 May 2016
LFCR Rate 0.2% 0.95% 1.46% 1.71%
Residential rate per lost kWh $0.031 $0.031 $0.031 $0.031
Non-residential rate per lost kWh $0.023 $0.023 $0.023 $0.023
LFCR Adjustment (Annualized) $5.1 Million $25.4 Million $38.5 Million $46.4 Million
LFCR Revenue (Accrued in prior year) $7.3 Million (1) $22.6 Million $34.5 Million $46.0 Million
(1) Represents six months in 2012.
Powering Growth, Delivering Value47
ENVIRONMENTAL
PLAN
Regional Haze compliance is the
biggest driver of environmental
spend over the next few years
Regional Haze / BART
(SCR)
Mercury and Other
Hazardous Air Pollutants
(ACI + Baghouse)
Coal Combustion
Residuals
Cooling Water
Intake
Structures –
CWA 316(b)
EPA Ruling Announced in 1999, with site-specific requirements announced more recently
MATS compliance by April
2015, with potential for
one-year extension
Announced on December
19, 2014 (Subtitle D)
Announced in
May 2014
Four
Corners
Units 4 & 5
Approximately $400M for SCRs in 2016-2018
(does not include CAPEX related to
4CA 7% interest)
$0
APS estimates that its share
of incremental costs to
comply with the CCR rule
for Four Corners is
approximately $15 million,
and its share of incremental
costs for Cholla is in the
range of $5 million to $40
million. APS expects to
incur certain of these costs
during 2016-2018
timeframe.
Immaterial
$0Cholla Unit 3
On September 11, 2014, APS announced a
proposal to close Unit 2 by April 2016 and stop
burning coal at the other APS-owned units
(1 and 3) by the mid-2020’s. If EPA does not
approve the plan, SCR for Unit 3 would cost
approximately $100 million.
$8M
Navajo Plant
Units 1-3
Up to ~$200M for SCRs and baghouses
On July 28, 2014, EPA issued the final BART
rule incorporating the better-than-BART
alternative proposed by SRP and others
Approximately $1 million Approximately $1 million To be determined
Clean Power Plan: On August 3, 2015, the U.S. EPA issued its final rules to reduce carbon dioxide emissions from fossil fuel-fired power plants
including those on Tribal lands. APS is reviewing the rules, while working closely with other utilities, the Arizona Department of Environmental Quality,
the ACC, tribal officials and other impacted stakeholders to determine how best to proceed. On February 9, 2016, the U.S. Supreme Court granted a
stay of the Clean Power Plan pending judicial review, which temporarily delays compliance obligations.
Note: Dollars shown at ownership. Estimates as of September 30, 2016.
• Cholla: Unit 1 is not BART-eligible; Unit 2 retired on October 1, 2015; Unit 4 is owned by PacifiCorp.
• SO2 NAAQS and greenhouse gas-related costs will be determined based upon EPA rule makings, with no spend occurring before 2016.
• ACI = Activated Carbon Injection; NAAQS = National Ambient Air Quality Standard; SCR = Selective Catalytic Reduction control technology
Powering Growth, Delivering Value48
Emissions
• 820 MW of coal has been retired including 560 MW at Four Corners Units 1-3 in 2013 and 260 MW at Cholla Unit 2
as of October 1, 2015.
• Four Corners: 2013 transaction to purchase Southern California Edison’s ownership in Units 4 and 5 and closure of
units 1, 2 & 3 leads to expected reductions of emissions; particulates are expected to decline by 43%, NOx by 36%,
CO2 by 30%, mercury by 61% and SO2 by 24%.
• Cholla Power Plant: Closure of Unit 2 as of October 1, 2015 will reduce mercury emissions by 51%, particulates
by 34%, NOx by 32%, and CO2 and SO2 by 23% each. We also announced plans to work with the U.S. EPA to stop
burning coal at our remaining Cholla units by the mid-2020s
• Navajo Generating Station: Plan proposed by a group of stakeholders, including SRP, the operating agent, was
approved by the EPA in 2014. The plan will achieve even greater NOx emission reductions than the EPA’s proposal
• Participated in Carbon Disclosure Project since 2006
COAL FLEET STRATEGY
APS’s proactive approach to
reducing emissions leads to coal’s
expected share of the energy mix
being reduced to 14%
13% 14%
11% 18%
26% 18%
27%
14%
23%
36%
2017 2032
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Note: RE = Renewable Energy; DE = Distributed Energy; EE = Energy Efficiency
Data shown is based on the Updated 2017 Preliminary Integrated Resource Plan filed September 30, 2016.
Gas
Coal
Nuclear
RE + DE
EE
Powering Growth, Delivering Value49
WATER STRATEGY
APS, and Palo Verde in particular,
has provided national and
international leadership on the
use of reclaimed water for power
generation
68%
17%
15%Reclaimed Water
Groundwater
Surface Water
APS 2015 Fleet
Water Use By Source Type
Vision: APS continues to strive for sustainable and cost-effective water supplies for energy production
for APS customers.
Mission: To execute a strategic water resource management program that provides APS timely and
reliable information to manage our water resources portfolio efficiently and effectively, and helps
ensure long-term water supplies and water contingency plans for each of our facilities, even in times of
extended drought.
• Each APS power plant has a unique water strategy, developed to promote efficient and sustainable
use of water.
Water Usage and Intensity: Goal is to maximize
use of renewable water resources and minimize use
of non-renewable resources. Our 2016 initiatives include:
• Reducing consumption of non-renewable water resources by
8% over 2014 levels, and
• Reducing water intensity company-wide by 20 percent over
2014 levels
Palo Verde Nuclear Generating Station: The only nuclear
plant in the world that does not sit on a large body of water.
Instead, it uses treated effluent, or wastewater, from several
area municipalities, recycling approximately 20 billion gallons of
wastewater each year
Powering Growth, Delivering Value50
GENERATION PORTFOLIO*
Plant Location No. of Units Dispatch COD Ownership Interest1 Net Capacity (MW)
NUCLEAR
1,146 MW Palo Verde Wintersburg, AZ 3 Base 1986-1989 29.1% 1,146
COAL
1,672 MW
Cholla Joseph City, AZ 2 Base 1962-1980 100 387
Four Corners Farmington, NM 2 Base 1969-1970 63 970
Navajo Page, AZ 3 Base 1974-1976 14 315
GAS - COMBINED CYCLE
1,871 MW
Redhawk Arlington, AZ 2 Intermediate 2002 100 984
West Phoenix Phoenix, AZ 5 Intermediate 1976-2003 100 887
GAS - STEAM TURBINE
220 MW Ocotillo Tempe, AZ 2 Peaking 1960 100 220
GAS / OIL
COMBUSTION TURBINE
1,088 MW
Sundance Casa Grande, AZ 10 Peaking 2002 100 420
Yucca Yuma, AZ 6 Peaking 1971-2008 100 243
Saguaro Red Rock, AZ 3 Peaking 1972-2002 100 189
West Phoenix Phoenix, AZ 2 Peaking 1972-1973 100 110
Ocotillo Tempe, AZ 2 Peaking 1972-1973 100 110
Douglas Douglas, AZ 1 Peaking 1972 100 16
SOLAR
189 MW
Hyder & Hyder II Hyder, AZ - As Available 2011-2013 100 30
Paloma Gila Bend, AZ - As Available 2011 100 17
Cotton Center Gila Bend, AZ - As Available 2011 100 17
Chino Valley Chino Valley, AZ - As Available 2012 100 19
Foothills Yuma, AZ - As Available 2013 100 35
Distributed Energy Multiple AZ Facilities - As Available Various 100 15
Gila Bend Gila Bend, AZ - As Available 2015 100 32
Luke Air Force Base Glendale, AZ - As Available 2015 100 10
Desert Star Buckeye, AZ - As Available 2015 100 10
Various Multiple AZ Facilities - As Available 1996-2006 100 4
Total Generation Capacity 6,186 MW
1 Includes leased generation plants* As disclosed in 2015 Form 10-K.
Powering Growth, Delivering Value51
PURCHASED POWER CONTRACTS*
Contract Location Owner/Developer Status1 PPA Signed COD Term (Years) Net Capacity (MW)
SOLAR
310 MW
Solana Gila Bend, AZ Abengoa IO Feb-2008 2013 30 250
RE Ajo Ajo, AZ Duke Energy Gen Svcs IO Jan-2010 2011 25 5
Sun E AZ 1 Prescott, AZ SunEdison IO Feb-2010 2011 30 10
Saddle Mountain Tonopah, AZ SunEdison IO Jan - 2011 2012 30 15
Badger Tonopah, AZ PSEG IO Jan-2012 2013 30 15
Gillespie Maricopa County, AZ Recurrent Energy IO Jan-2012 2013 30 15
WIND
289 MW
Aragonne Mesa Santa Rosa, NM Ingifen Asset Mgmt IO Dec-2005 2006 20 90
High Lonesome Mountainair, NM Foresight / EME IO Feb-2008 2009 30 100
Perrin Ranch Wind Williams, AZ NextEra Energy IO Jul-2010 2012 25 99
GEOTHERMAL
10 MW Salton Sea Imperial County, CA Cal Energy IO Jan-2006 2006 23 10
BIOMASS
14 MW Snowflake Snowflake, AZ Novo Power IO Sep-2005 2008 15 14
BIOGAS
6 MW
Glendale Landfill Glendale, AZ Glendale Energy LLC IO Jul-2008 2010 20 3
NW Regional Landfill Surprise, AZ Waste Management IO Dec-2010 2012 20 3
INTER-UTILITY
540 MW
PacifiCorp Seasonal
Power Exchange - PacifiCorp IO Sep-1990 1991 30 480
Not Disclosed Not Disclosed Not Disclosed IO May-2009 2010 10 60
HEAT RATE OPTIONS
150 MW Call Option - Not Disclosed IO Oct-2005 2007 10 150
CONVENTIONAL
TOLLING
1,074 MW
CC Tolling Not Disclosed Not Disclosed IO Mar-2006 2007 10 514
CC Tolling Not Disclosed Not Disclosed IO Aug-2007 2010 10 560
DEMAND RESPONSE
25 MW Demand Response Not Disclosed Not Disclosed IO Sep-2008 2010 15 25
Total Contracted Capacity 2,418 MW
1 UD = Under Development; UC = Under Construction; IO = In Operation* As disclosed in 2015 Form 10-K.
Powering Growth, Delivering Value52
INVESTOR RELATIONS CONTACTS
Paul J. Mountain, CFA
General Manager, Investor Relations & Audit Services
(602) 250-4952
paul.mountain@pinnaclewest.com
Ted Geisler
Director, Investor Relations
(602) 250-3200
ted.geisler@pinnaclewest.com
Chalese Haraldsen
(602) 250-5643
chalese.haraldsen@pinnaclewest.com
Pinnacle West Capital Corporation
P.O. Box 53999, Mail Station 9998
Phoenix, Arizona 85072-3999
Visit us online at: www.pinnaclewest.com