INTRODUCTION



The following discussion should be read in conjunction with Pinnacle West's
Condensed Consolidated Financial Statements and APS's Condensed Consolidated
Financial Statements and the related Combined Notes that appear in Item 1 of
this report.  For information on factors that may cause our actual future
results to differ from those we currently seek or anticipate, see
"Forward-Looking Statements" at the front of this report and "Risk Factors" in
Part 1, Item 1A of the 2021 Form 10-K, and Part II, Item 1A of this report.


                                    OVERVIEW

Business Overview

Pinnacle West is an investor-owned electric utility holding company based in
Phoenix, Arizona with consolidated assets of about $22 billion. For over 130
years, Pinnacle West and our affiliates have provided energy and energy-related
products to people and businesses throughout Arizona.

Pinnacle West derives essentially all of our revenues and earnings from our
principal subsidiary, APS. APS is Arizona's largest and longest-serving electric
company that generates safe, affordable and reliable electricity for
approximately 1.3 million retail customers in 11 of Arizona's 15 counties. APS
is also the operator and co-owner of Palo Verde - a primary source of
electricity for the southwest United States and the largest nuclear power plant
in the United States.

COVID-19 Pandemic

Essential planned work and capital investments have continued during the
COVID-19 pandemic with priority given to support fire mitigation and summer
storm efforts, as well as heat related outages. Raw material shortages, rising
inflation, COVID-19 related work force disruptions and natural disasters are
putting increased pressure on the global supply chain. APS is experiencing some
delays in finished materials and tight labor markets. To date, APS has not
experienced labor or material supply chain shortages that have significantly
impacted its ability to serve its customers' needs. However, shortages are
causing some delays, and shifting of work projects based on material
availability. If APS continues to experience delays in materials, it could
experience an increase in purchased power costs for summer generation needs.
Such increased purchased power costs would be expected to be recoverable through
the PSA. See Note 4 for additional information on the PSA. APS has measures in
place to continually monitor and evaluate resource needs and supply chain
adequacy but cannot predict whether there will be material supply chain
shortages in the future.

Though the total expected impact of COVID-19 on future sales remains unknown,
APS experienced higher electric residential sales and lower electric commercial
and industrial sales from the outset of the pandemic through April 2021.
Beginning in May 2021, electric sales to commercial and industrial customers
increased to levels in line with pre-COVID sales and such sales levels have
remained to date.

The Coronavirus Aid, Relief, and Economic Security (CARES) Act allowed employers
to defer payments of the employer share of Social Security payroll taxes that
would have otherwise been owed from March 27, 2020, through December 31, 2020.
We deferred the cash payment of the employer's portion of Social Security
payroll taxes for the period July 1, 2020, through December 31, 2020, which was
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approximately $18 million. We paid half of this cash deferral by December 31,
2021, and the remainder will be paid by December 31, 2022.

On June 30, 2020, the United States Federal Energy Regulatory Commission
("FERC") issued an order granting a waiver request related to the existing
Allowance for Funds Used During Construction ("AFUDC") rate calculation
beginning March 1, 2020 through February 28, 2021.  On February 23, 2021, this
waiver was extended until September 30, 2021. On September 21, 2021, it was
further extended until March 31, 2022. The order provided a simplified approach
that companies may elect to implement in order to minimize the significant
distorted effect on the AFUDC formula resulting from increased short-term debt
financing during the COVID-19 pandemic.  APS adopted this simplified approach to
computing the AFUDC composite rate by using a simple average of the actual
historical short-term debt balances for 2019, instead of current period
short-term debt balances, and left all other aspects of the AFUDC formula
composite rate calculation unchanged. This change impacted the AFUDC composite
rate in 2021 and for the three month ended March 31, 2022.  Furthermore, the
change in the composite rate calculation did not impact our accounting treatment
for these costs. The change did not have a material impact on our financial
statements. See Note 1.

Strategic Overview



Our strategy is to deliver shareholder value by creating a sustainable energy
future for Arizona by serving our customers with clean, reliable and affordable
energy.

Clean Energy Commitment

We are committed to doing our part to make the future clean and carbon-free. As
Arizona stewards, we do what is right for the people and prosperity of Arizona.
Our vision is to create a sustainable energy future for Arizona through
providing clean, affordable, and reliable energy. We can accomplish our visions
through collaboration with customers, communities, employees, policymakers,
shareholders, and other stakeholders. Our clean energy goal is based on sound
science and supports continued growth and economic development while maintaining
reliability and affordable prices for APS's customers.

APS's clean energy goals consist of three parts:

•A 2050 goal to provide 100% clean, carbon-free electricity; •A 2030 target of achieving a resource mix that is 65% clean energy, with 45% of the generation portfolio coming from renewable energy; and •A commitment to end APS's use of coal-fired generation by 2031.



APS's ability to successfully execute its clean energy commitment is dependent
upon a number of important external factors, some of which include a supportive
regulatory environment, sales and customer growth, development of clean energy
technologies and continued access to capital markets.

2050 Goal: 100% Clean, Carbon-Free Electricity. Achieving a fully clean, carbon-free energy mix by 2050 is our aspiration. The 2050 goal will involve new thinking and depends on improved and new technologies.



2030 Goal: 65% Clean Energy. APS has an energy mix that is already 50% clean
with existing plans to add more renewables and energy storage before 2025. By
building on those plans, APS intends to attain an energy mix that is 65% clean
by 2030, with 45% of APS's generation portfolio coming from renewable energy.
"Clean" is measured as percent of energy mix which includes all carbon-free
resources like nuclear and demand-side management, and "renewable" is expressed
as a percent of retail sales. This target will serve as a checkpoint
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2031 Goal: End APS's Use of Coal-Fired Generation. The commitment to end APS's
use of coal-fired generation by 2031 will require APS to cease use of
coal-generation at Four Corners. APS has permanently retired more than 1,000 MW
of coal-fired electric generating capacity. These closures and other measures
taken by APS have resulted in a total reduction of carbon emissions of 33% since
2005. In addition, APS has committed to end the use of coal at its remaining
Cholla units by 2025.

APS understands that the transition away from coal-fired power plants toward a
clean energy future will pose unique economic challenges for the communities
around these plants. We worked collaboratively with stakeholders and leaders of
the Navajo Nation to consider the impacts of ceasing operation of APS coal-fired
power plants on the communities surrounding those facilities to propose a
comprehensive Coal Community Transition ("CCT") plan. The proposed framework
provided substantial financial and economic development support to build new
economic opportunities and addresses a transition strategy for plant employees.
We are committed to continuing our long-running partnership with the Navajo
Nation in other areas as well, including expanding electrification and
developing tribal renewable projects. Our proposed CCT plan supported the Navajo
Nation, where Four Corners is located, the communities surrounding the Cholla
Power Plant and the Hopi Tribe, which is impacted by closure of the Navajo
Plant. On November 2, 2021, the ACC approved an amended 2019 Rate Case ROO that
will require (i) equal payments over a three-year period that total $10 million
to the Navajo Nation, (ii) a $1 million one-time payment to the Hopi Tribe
within 60 days of the 2019 Rate Case decision, (iii) a $500,000 one-time payment
to the Navajo County communities within 60 days of the 2019 Rate Case decision,
(iv) up to $1.25 million for electrification of homes and businesses on the Hopi
reservation and (v) up to $1.25 million for the electrification of homes and
businesses on the Navajo Nation reservation. The payments and expenditures are
attributable to the future closures of Four Corners and Cholla, along with the
prior closure of the Navajo Plant. All ordered payments and expenditures would
be recoverable through rates.

Consistent with the 2019 Rate Case decision, as of April 2022, APS has completed
the following payments that will be recoverable through rates related to the
CCT: (i) $3.33 million to the Navajo Nation; (ii) $500,000 to the Navajo County
communities; and (iii) $1 million to the Hopi Tribe. Consistent with APS's
commitment to the impacted communities, APS has also completed the following
payments: (i)$500,000 to the Navajo Nation for electrification; (ii) $1.1
million to the Navajo County Communities for CCT and economic development; and
(iii) $1.25 million to the Hopi Tribe for CCT and economic development. The ACC
has also authorized $1.25 million to be recovered through rates for
electrification of homes and businesses on both the Navajo Nation and Hopi
reservation. Expenditure of these funds is contingent upon completion of a
census of the unelectrified homes and businesses within APS service territory on
both the Navajo Nation and Hopi reservation.

In June 2021, APS and the owners of Four Corners entered into agreements to
operate Four Corners seasonally beginning in fall 2023, subject to the necessary
governmental approvals and conditions associated with changes in plant
ownership. Under seasonal operation, a single unit will remain online
year-round, subject to market conditions as well as planned maintenance outages
and unplanned outages. In addition, the other unit will be operational
throughout the summer season of June through October when customer demand is the
highest. APS believes that operating Four Corners seasonally will bring
environmental benefits and ensure continued service reliability for its
customers, especially during Arizona's hot summer months, as APS transitions to
ceasing to use coal-fired generation by 2031. By moving to seasonal operations,
Four Corners will become a more flexible resource that supports increasing
amounts of clean energy, helping to compensate for the intermittent output of
renewable resources. This change also helps ensure reliability of a critical
energy source while reducing operations and maintenance costs. APS estimates
that the shift to seasonal operations
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will reduce annual carbon emissions at Four Corners by an estimated 20-25%, as
compared to current conditions.

Renewables. APS's IRP (see Note 4 for additional information) establishes the
path to meeting our clean energy commitment and maintaining reliable electric
service for our customers. APS intends to strengthen its already diverse energy
mix by increasing its investments in carbon-free resources. Our IRP rapidly adds
clean energy and storage resources while maintaining reliable and affordable
service. Its near-term actions are focused on clean energy and positive customer
outcomes and includes: (a) competitive solicitations to procure clean energy
resources such as solar, wind, energy storage, and DSM resources, all of which
lead to a cleaner grid; and (b) strategic, short-term wholesale market purchases
from a combination of existing merchant natural gas units, neighboring utility
systems and wholesale market participants that ensure operational reliability.

APS has a diverse portfolio of existing and planned renewable resources,
including solar, wind, geothermal, biomass and biogas, that supports our
commitment to clean energy. That commitment has its foundation in the Palo Verde
generating station, which is the nation's largest carbon-free, clean energy
resource, and it provides critical reliable and affordable service for APS
customers. APS's longer-term clean energy strategy includes pursuing the right
mix of purchased power contracts for new facilities, procurement of new
facilities to be owned by APS, and the ongoing development of distributed energy
resources. This balance will ensure an appropriately diverse portfolio designed
to achieve the same operational reliability and customer affordability as APS's
near-term strategies. In addition, APS is actively seeking to include future
facility purchase options in its PPAs that will enable investments with greater
financial flexibility.

APS uses competitive "all source" requests for proposal ("RFPs") to pursue
market resources that meet its system needs and offer the best value for
customers. APS selects projects based on cost and non-cost factors, taking into
consideration timing and likelihood of successful contracting and development.
Under current market conditions, APS must aggressively contract for resources
that can withstand supply chain and other geopolitical pressures. Available
projects are guided by IRP timelines and quantities and APS maintains a flexible
approach that allows it to optimize system reliability and customer
affordability through the RFP process. Agreements for the development and
completion of future resources are subject to various conditions, including
successful siting, permitting and interconnection of the projects to the
electric grid. See "Business of Arizona Public Service Company - Energy Sources
and Resource Planning - Current and Future Resources - Renewable Energy Standard
- Renewable Energy Portfolio" in Item 1 for details regarding APS's renewable
energy resources.

In September 2019, APS issued an RFP that requested up to 250 MW of wind
resources to be in service as soon as possible, but no later than 2022. As a
result of this RFP, APS executed a 200 MW PPA for a wind resource that went into
service in January 2022. In December 2020, APS issued two additional RFPs: (i) a
battery storage RFP for projects to be located at two AZ Sun sites; and (ii) an
all-source RFP that solicited resources to meet our clean energy needs and
capacity to maintain system reliability, and was later amended to include a
request for 150 MW of solar resources to be developed on APS property and owned
by APS (collectively, the "December 2020 RFPs"). As a result of the all-source
RFP, APS executed a PPA in October 2021 for a 238 MW wind resource to be in
service by June 2023, and also executed an engineering, procurement, and
construction contract in November 2021 for a 150 MW solar resource to be owned
by APS and in service in early 2023. APS continues to negotiate contracts for
additional resources to be in service in 2024 in connection with the all-source
RFP. Once it secures those important resources and closes out the December 2020
RFPs, APS intends to issue its next all source RFP to address resource needs for
2025 and beyond.

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The following table summarizes the resources in APS's renewable energy portfolio
that are in operation and under development as of March 31, 2022. Agreements for
the development and completion of future resources are subject to various
conditions, including successful siting, permitting and interconnection of the
projects to the electric grid.
                                                     Net Capacity in Operation                   Net Capacity Planned / Under
                                                               (MW)                                    Development (MW)
Total APS Owned: Solar                                                248                                            150
Purchased Power Agreements Renewables:
Solar                                                                 310                                            435
Wind                                                                  399                                            238
Geothermal                                                             10                                              -
Biomass                                                                14                                              -
Biogas                                                                  3                                              -
Total Purchased Power Agreements                                      736                                            673
Total Distributed Energy: Solar (a)                                 1,281                                             82                (b)
Total Renewable Portfolio                                           2,265                                            905



(a)    Includes rooftop solar facilities owned by third parties. Distributed
generation is produced in Direct Current and is converted to Alternating Current
for reporting purposes.
(b)  Applications received by APS that are not yet installed and online.

Energy Storage. APS deploys a number of advanced technologies on its system,
including energy storage. Energy storage provides capacity, improves power
quality, can be utilized for system regulation and, in certain circumstances, be
used to defer certain traditional infrastructure investments. Energy storage
also aids in integrating renewable generation by storing excess energy when
system demand is low and renewable production is high and then releasing the
stored energy during peak demand hours later in the day and after sunset. APS is
utilizing grid-scale energy storage projects to meet customer reliability
requirements, increase renewable utilization, and to further our understanding
of how storage works with other advanced technologies and the grid.

In 2018, APS issued an RFP for approximately 106 MW of energy storage to be
located at up to five of its AZ Sun sites. Based upon its evaluation of the RFP
responses, APS decided to expand the initial phase of battery deployment to 141
MW by adding a sixth AZ Sun site. These battery storage facilities are expected
to be in service during the summer of 2022. On August 2, 2021, APS executed a
contract for an additional 60 MW of utility-owned energy storage to be located
on APS's AZ Sun sites. This contract, with a 2023 in-service date, will complete
the addition of storage on current APS-owned utility-scale solar facilities.

Additionally, in February 2019, APS signed two 20-year PPAs for energy storage
totaling 150 MW. These PPAs were subject to ACC approval in order to allow for
cost recovery through the PSA. APS received the requested ACC approval on
January 12, 2021, and service under the agreements is expected to begin in 2022
with respect to 100 MW and in 2023 with respect to 50 MW.

As a result of its December 2020 RFPs, as of May 2022, APS has executed four
20-year PPAs for resources that include energy storage: (a) two PPAs for
standalone energy storage resources totaling 300 MW; and (b) two PPAs totaling
275 MW solar plus storage resource. The PPAs are also subject to ACC approval to
enable cost recovery through the PSA. APS received the requested ACC approval
for three out of four of the projects on December 16, 2021. The remaining
project was filed in February 2022 for ACC approval and on
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April 13, 2022, the ACC approved this application. Service under the agreements
is expected to begin in 2023 and 2024.

APS currently plans to install more than 900 MW of energy storage by 2025, including the energy storage projects under PPAs and AZ Sun retrofits described above. The remaining energy storage is expected to be made up of resources solicited through current and future RFPs.



The following table summarizes the resources in APS's energy storage portfolio
that are in operation and under development as of March 31, 2022. Agreements for
the development and completion of future resources are subject to various
conditions.

                                                      Net Capacity in Operation (MW)               Net Capacity Planned / Under Development (MW)
APS Owned: Energy Storage                                                   -                                                   201
Purchase Power Agreements - Energy Storage                                  -                                                   725
Residential Energy Storage                                                          13(a)                                         3
Total Energy Storage Portfolio                                             13                                                   929

(a) This includes 13.1 MW of APS customer-owned batteries and 0.2 MW of APS-owned residential batteries.

Palo Verde. Palo Verde, the nation's largest carbon-free, clean energy resource,
will continue to be a foundational part of APS's resource portfolio. The plant
currently supplies nearly 70% of our clean energy and provides the foundation
for the reliable and affordable service for APS customers. Palo Verde is not
just the cornerstone of our current clean energy mix; it also is a significant
provider of clean energy to the southwest United States. The plant is a critical
asset to the Southwest, generating more than 32 million megawatt-hours annually
- enough power for more than 4 million people. Its continued operation is
important to a carbon-free and clean energy future for Arizona and the region,
as a reliable, continuous, affordable resource and as a large contributor to the
local economy.

Affordable

We believe it is APS's responsibility to deliver electric services to customers
in the most cost-effective manner. Since January 2018 through March 2022, the
average residential bill decreased by 1.44%, or $2.12, due to net reductions in
cost recovery adjustor mechanisms.

Building upon existing cost management efforts, APS launched a customer
affordability initiative in 2019. The initiative was implemented company-wide to
thoughtfully and deliberately assess our business processes and organizational
approaches to completing high-value work and internal efficiencies. In 2021, APS
continued to drive this initiative by identifying opportunities to streamline
its business processes and deliver sustainable cost savings, which resulted in
the Company identifying approximately $30 million in annual incremental cost
saving opportunities in 2022. APS is continuing this initiative in 2023.

Participation in the Energy Imbalance Market ("EIM") continues to be a tool for
creating savings for APS's customers from the real-time, voluntary market. APS
continues to expect that its participation in EIM will lower its fuel and
purchased-power costs, improve situational awareness for system operations in
the Western Interconnection power grid, and improve integration of APS's
renewable resources. APS continues to evaluate opportunities that benefit our
customers and is exploring opportunities to move to a day-ahead market with the
expectation of reliably achieving incrementally greater cost savings and using
the region's increasing renewable resources more efficiently. As part of that
effort, APS is exploring several options. APS is in
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discussions with the current EIM operator, the CAISO, the Western Resource
Adequacy Program, the Western Markets Exploratory Group, and the Southwest Power
Pool. Each of these explorations also involve other entities and are being
undertaken to evaluate the feasibility and cost/benefit of creating a voluntary
day-ahead market.

Reliable

While our energy mix evolves, the obligation to deliver reliable service to our
customers remains. Notwithstanding the challenges presented by the COVID-19
pandemic, as well the Phoenix metropolitan experiencing the warmest June on
record and its summer monsoon being the third wettest over the last 41 years,
APS continued to provide reliable service to its customers in 2021.

Planned investments will support operating and maintaining the grid, updating
technology, accommodating customer growth, and enabling more renewable energy
resources. Our advanced distribution management system allows operators to
locate outages, control line devices remotely and helps them coordinate more
closely with field crews to safely maintain an increasingly dynamic grid. The
system also integrates a new meter data management system that increases grid
visibility and gives customers access to more of their energy usage data.

Wildfire safety remains a critical focus for APS and other utilities. We
increased investment in fire mitigation efforts to clear defensible space around
our infrastructure, continue ongoing system upgrades, build partnerships with
government entities and first responders and educate customers and communities.
These programs contribute to customer reliability, responsible forest management
and safe communities.

The new units at our modernized Ocotillo Power Plant provide cleaner-running and
more efficient units. They support reliability by responding quickly to the
variability of solar generation and delivering energy in the late afternoon and
early evening when solar production declines as the sun sets and customer demand
peaks.

In April 2021, the CAISO sought FERC authorization for certain tariff changes
intended to try to address risks associated with high heat weather events.
Although APS is generally supportive of some of these changes, others would
change the load, export, and wheeling priorities in a way that would unfairly
benefit California entities at the expense of non-California entities. On June
25, 2021, FERC issued an order accepting the CAISO's proposed changes. On July
26, 2021, APS filed seeking a rehearing of FERC's June 25, 2021 order. On August
26, 2021, FERC issued a notice indicating that the pending requests for
rehearing were denied by operation of law and providing for further
consideration. On March 15, 2022, FERC issued an order addressing the arguments
raised on rehearing, denying clarification, and dismissing the rehearing
request.

In October of 2021, APS announced plans to evaluate regional market solutions as
part of the informal Western Markets Exploratory Group ("WMEG"). As part of
WMEG, APS is exploring the potential for a staged approach to new market
services, including day-ahead energy sales, transmission system expansion, and
other power supply and grid solutions consistent with existing state
regulations. WMEG hopes to identify market solutions that can help achieve
carbon reduction goals while supporting reliable, affordable service for
customers. APS is unable to predict the outcome of these discussions.

APS's key elements to delivering reliable power include resource planning,
sufficient reserve margins, customer partnerships to manage peak demand, fire
mitigation, and operational preparedness. Seasonal readiness procedures at APS
also include walkdowns to ensure good material conditions and critical control
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Table of Contents system surveys. APS also plans for the unexpected by conducting emergency operations drills and coordinating on fire and emergency management with federal, state, and local agencies.

Customer-Focused



Recognizing that creating customer value is inextricably linked to increasing
shareholder value, APS's focus remains on its customers and the communities it
serves. Accordingly, it is APS's goal to achieve an industry-leading,
best-in-class customer experience, while demonstrating compassion and advocacy
for its customers. This multi-year objective includes incrementally improving
APS's J.D. Power ("JDP") overall customer satisfaction ratings from the fourth
quartile to the first quartile of its peer set comprised of large investor-owned
utilities.

APS's JDP residential overall customer satisfaction rating improved in the
fourth quarter of 2021, ranking in the third quartile. That improvement trend
continued with the latest JDP residential 2022 first-quarter results. APS made
quartile gains in every single driver of customer satisfaction with APS moving
into the top half of the third quartile for overall satisfaction when compared
to its large investor-owned peers. APS's strongest performing drivers in the
latest JDP survey were Power Quality and Reliability and Customer Care, both of
which performed well above the large investor-owned peer set averages.

Developing Clean Energy Technologies

Electric Vehicles



APS is making electric vehicle charging more accessible for its customers and
helping Arizona businesses, schools and governments electrify their fleets. In
2021, APS continued its expansion of its Take Charge AZ Pilot Program. As of
year-end 2021, APS had installed over 400 charging ports at customer locations
with more stations expected to be added through 2022. The program provides
charging equipment, installation, and maintenance to business customers,
government agencies, non-profits, and multifamily housing communities. In
addition to the Level 2 charging stations, APS has begun construction of DC fast
charging stations that will be owned and operated by APS at five locations in
Arizona, with the first location that opened in March 2022. The other four
projects' locations are expected to be completed during 2022, with each location
including 2-150 kilowatt and 2-350 kilowatt DC fast charging ports. Charging at
these stations will be accessible through the Electrify America charging
network. APS also has a goal of 450,000 light-duty electric vehicles in its
service territory by 2030.

Additionally, as part of APS's DSM plan, APS has launched an Electric Vehicle
Charging Demand Management Pilot Program to proactively address the growing
electric demand from electric vehicle charging as electric vehicles become more
widely adopted. This program includes the APS SmartCharge data gathering
program, an electric vehicle smart charger rebate for qualifying electric
vehicle chargers, and a $100 rebate to home builders for new home 240V charging
station garage outlets.

The ACC ordered the state's public service corporations, including APS, to
develop a long-term, comprehensive Statewide Transportation Electrification Plan
("TE Plan") for Arizona. The TE Plan is intended to provide a roadmap for
Transportation Electrification in Arizona, focused on realizing the associated
air quality and economic development benefits for all residents in the state
along with understanding the impact of electric vehicle charging on the grid.
APS actively participated in developing this plan. The ACC approved the plan in
December 2021. APS recently filed its first TE Plan Annual Progress Report to
the ACC and is currently working with stakeholders to develop a budget and
implementation plan for ACC review later this year.

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Hydrogen Production

Palo Verde, in partnership with Idaho National Laboratory ("INL"), Energy Harbor
Corporation ("Energy Harbor") and Xcel Energy Incorporated ("Xcel"), was chosen
by the DOE's Office of Nuclear Energy to participate in a series of hydrogen
production projects with the goal to improve the long-term economic
competitiveness of the nuclear power industry. The multi-phase projects began in
2020 with a series of small-scale hydrogen production demonstration projects led
by Energy Harbor and Xcel, as well as a technical and economic assessment
performed by INL of using electricity generated at Palo Verde to produce
hydrogen.

Based on the experience from Palo Verde's utility partners' small scale
demonstration projects and from the Palo Verde-specific technical and economic
assessment performed by INL, in April 2021, PNW Hydrogen LLC ("PNW Hydrogen"), a
newly formed subsidiary of Pinnacle West, applied for DOE funding for a larger
scale hydrogen production demonstration project using electricity sourced from
Palo Verde. On October 7, 2021, PNW Hydrogen was notified that DOE's Office of
Energy Efficiency & Renewable Energy and Office of Nuclear Energy had selected
PNW Hydrogen's application for an award of $20 million in federal funding to
support the hydrogen production demonstration project, subject to negotiation
and execution of a definitive Cooperative Agreement funding instrument between
PNW Hydrogen and DOE.

Carbon Capture

Carbon capture technologies can isolate CO2 and either sequester it permanently
in geologic formations or convert it for use in products. Currently, almost all
existing fossil fuel generators do not control carbon emissions the way they
control emissions of other air pollutants such as sulfur dioxide or oxides of
nitrogen. Carbon capture technologies are still in the demonstration phase and
while they show promise, they are still being tested in real-world conditions.
These technologies could offer the potential to keep in operation existing
generators that otherwise would need to be retired. APS will continue to monitor
this emerging technology.

Environmental, Social, and Governance ("ESG") Practices



Pinnacle West has been integrating ESG practices into its core work for almost
30 years. As a business strategy, we seek solutions that provide "shared value,"
meaning solutions that address societal and environmental challenges in a way
that also delivers business value. Our commitment extends beyond implementing
sustainability practices; we are dedicated to working with our stakeholders to
identify and address the sustainability issues that we are uniquely positioned
to impact through our business. In 2020, in support of our clean energy
commitment and the growing focus on ESG within our organization, we increased
our efforts by dedicating a new Sustainability Department at Pinnacle West to
integrating ESG best practices into the everyday work of the Company.

As a first step, the Company engaged the Electric Power Research Institute
("EPRI") and leveraged input from employees, large customers, limited-income
advocates, economic development groups, environmental non-governmental
organizations, leading sustainability academics and other stakeholders to
identify and assess the sustainability issues that matter most. In total, 23
Priority Sustainability Issues ("PSIs") were identified and prioritized. The
most critical category, Integral Shared Value, includes four issues deemed most
important and most able to be impacted by our actions: clean energy, customer
experience, energy access and reliability and safety and health. These Integral
PSIs provide the foundation for informing our strategic direction, creating a
framework for incorporating best practices and driving enterprise-wide alignment
and accountability. In 2021, the Company engaged EPRI for the second phase of
this work, focused on benchmarking best practices within these four Integral
Shared Value PSIs. We will utilize the benchmarking information to identify
opportunities for further improvement in our ESG performance.
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In 2021, the Company established a Social Issues Committee Framework. The goal
of the framework is to provide a process for considering emergent social issues,
and for determining whether or how best to engage. The committee's
responsibility is to determine, using a set of principles grounded in the APS
Promise and the PSIs, whether engagement on specific emergent social issues is
appropriate and, if so, how best to engage.

In 2021, the Company finalized an ESG Strategic Framework to guide our work. The
framework is based upon three foundational pillars: ESG Policy Advocacy (we
advocate for policy that supports our clean energy goals); Driving Performance
(improving our ESG performance in the most important areas, including our PSIs);
and effectively communicating and amplifying our ESG story to our various
stakeholders, including investors, customers, employees and beyond. The
framework will guide and shape our ESG work moving forward.

Regulatory Overview



On October 31, 2019, APS filed an application with the ACC (the "2019 Rate
Case") seeking an increase in annual retail base rates of $69 million. This
amount includes recovery of the deferral and rate base effects of the Four
Corners SCR project that was the subject of a separate proceeding. See "Four
Corners SCR Cost Recovery" in Note 4). It also reflects a net credit to base
rates of approximately $115 million primarily due to the prospective inclusion
of rate refunds currently provided through the TEAM. The proposed total annual
revenue increase in APS's application is $184 million. The average annual
customer bill impact of APS's request is an increase of 5.6% (the average annual
bill impact for a typical APS residential customer is 5.4%).

The principal provisions of APS's application were:



•a test year comprised of 12 months ended June 30, 2019, adjusted as described
below;
•an original cost rate base of $8.87 billion, which approximates the
ACC-jurisdictional portion of the book value of utility assets, net of
accumulated depreciation and other credits;
•the following proposed capital structure and costs of capital:

                                                 Capital Structure        Cost of Capital
      Long-term debt                                    45.3         %                 4.1 %
      Common stock equity                               54.7         %        10.15        %
      Weighted-average cost of capital                                         7.41        %



•a 1% return on the increment of fair value rate base above APS's original cost
rate base, as provided for by Arizona law;
•a Base Fuel Rate of $0.030168 per kWh;
•authorization to defer until APS's next general rate case the increase or
decrease in its Arizona property taxes attributable to tax rate changes after
the date the rate application is adjudicated;
•a number of proposed rate and program changes for residential customers,
including:
?a super off-peak period during the winter months for APS's time-of-use with
demand rates;
?additional $1.25 million in funding for APS's limited-income crisis bill
program; and
?a flat bill/subscription rate pilot program;
•proposed rate design changes for commercial customers, including an
experimental program designed to provide access to market pricing for up to 200
MW of medium and large commercial customers;
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•recovery of the deferral and rate base effects of the construction and
operating costs of the Ocotillo modernization project. See Note 4 for a
discussion of the 2017 Settlement Agreement; and
•continued recovery of the remaining investment and other costs related to the
retirement and closure of the Navajo Plant. See Note 4 for details related to
the resulting regulatory asset.

On October 2, 2020, the ACC Staff, the Residential Utility Consumer Office
("RUCO") and other intervenors filed their initial written testimony with the
ACC. The ACC Staff recommended, among other things, (i) a $89.7 million revenue
increase, (ii) an average annual customer bill increase of 2.7%, (iii) a return
on equity of 9.4%, (iv) a 0.3% or, as an alternative, a 0% return on the
increment of fair value rate base greater than original cost, (v) the recovery
of the deferral and rate base effects of the construction and operating costs of
the Four Corners SCR project and (vi) the recovery of the rate base effects of
the construction and ongoing consideration of the deferral of the Ocotillo
modernization project. RUCO recommended, among other things, (i) a $20.8 million
revenue decrease, (ii) an average annual customer bill decrease of 0.63%, (iii)
a return on equity of 8.74%, (iv) a 0% return on the increment of fair value
rate base, (v) the nonrecovery of the deferral and rate base effects of the
construction and operating costs of the Four Corners SCR project pending further
consideration, and (vi) the recovery of the deferral and rate base effects of
the construction and operating costs of the Ocotillo modernization project.

The filed ACC Staff and intervenor testimony include additional recommendations,
some of which materially differ from APS's filed application. On November 6,
2020, APS filed its rebuttal testimony and the principal provisions which differ
from its initial application include, among other things, a (i) $169 million
revenue increase, (ii) average annual customer bill increase of 5.14%, (iii)
return on equity of 10%, (iv) return on the increment of fair value rate base of
0.8%, (v) new cost recovery adjustor mechanism, the Advanced Energy Mechanism,
to enable more timely recovery of clean investments as APS pursues its clean
energy commitment, (vi) recognition that securitization is a potentially useful
financing tool to recover the remaining book value of retiring assets and
effectuate a transition to a cleaner energy future that APS intends to pursue,
provided legislative hurdles are addressed, and (vii) the CCT plan related to
the closure or future closure of coal-fired generation facilities of which $25
million would be funds that are not recoverable through rates with a proposal
that the remainder be funded by customers over 10 years.

The CCT plan includes the following proposed components: (i) $100 million that
will be paid over 10 years to the Navajo Nation for a sustainable transition to
a post-coal economy, which would be funded by customers, (ii) $1.25 million that
will be paid over five years to the Navajo Nation to fund an economic
development organization, which would be funds not recoverable through rates,
(iii) $10 million to facilitate electrification projects within the Navajo
Nation, which would be funded equally by funds not recoverable through rates and
by customers, (iv) $2.5 million per year in transmission revenue sharing to be
paid to the Navajo Nation beginning after the closure of the Four Corners
through 2038, which would be funds not recoverable through rates, (v) $12
million that will be paid over five years to the Navajo County Communities
surrounding Cholla Power Plant, which would primarily be funded by customers,
and (vi) $3.7 million that will be paid over five years to the Hopi Tribe
related to APS's ownership interests in the Navajo Plant, which would primarily
be funded by customers. In 2021, APS committed an additional $900,000 to be paid
to the Hopi Tribe related to APS's ownership interests in the Navajo Plant.

On December 4, 2020, the ACC Staff and intervenors filed surrebuttal testimony.
The ACC Staff reduced its recommended rate increase to $59.8 million, or an
average annual customer bill increase of 1.82%. In RUCO's surrebuttal, the
recommended revenue decrease changed to $50.1 million, or an average annual
customer bill decrease of 1.52%. The hearing concluded on March 3, 2021, and the
post-hearing briefing concluded on April 30, 2021.

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On August 2, 2021, the Administrative Law Judge issued a Recommended Opinion and
Order in the 2019 Rate Case (the "2019 Rate Case ROO") and issued corrections on
September 10 and September 20, 2021. The 2019 Rate Case ROO recommended, among
other things, (i) a $111 million decrease in annual revenue requirements, (ii) a
return on equity of 9.16%, (iii) a 0.30% return on the increment of fair value
rate base greater than original cost, with total fair value rate of return
further adjusted to include a 0.03% reduction to return on equity resulting in
an effective fair value rate of return of 4.95%, (iv) the nonrecovery of the
deferral and rate base effects of the operating costs and construction of the
Four Corners SCR project (see "Four Corners SCR Cost Recovery" below for
additional information), (v) the recovery of the deferral and rate base effects
of the operating costs and construction of the Ocotillo modernization project,
which includes a reduction in the return on the deferral, (vi) a 15%
disallowance of annual amortization of Navajo Plant regulatory asset recovery,
(vii) the denial of the request to defer until APS's next general rate case the
increase or decrease in its Arizona property taxes attributable to tax rate
changes, and (viii) a collaborative process to review and recommend revisions to
APS's adjustment mechanisms within 12 months after the date of the decision. The
2019 Rate Case ROO also recommended that the CCT plan include the following
components: (i) $50 million that will be paid over 10 years to the Navajo
Nation, (ii) $5 million that will be paid over five years to the Navajo County
Communities surrounding Cholla Power Plant, and (iii) $1.675 million that will
be paid to the Hopi Tribe related to APS's ownership interests in the Navajo
Plant. These amounts would be recoverable from APS's customers through the RES
adjustment mechanism. APS filed exceptions on September 13, 2021, regarding the
disallowance of the SCR cost deferrals and plant investments that was
recommended in the 2019 Rate Case ROO, among other issues.

On October 6, 2021 and October 27, 2021, the ACC voted on various amendments to
the 2019 Rate Case ROO that would result in, among other things, (i) a return on
equity of 8.70%, (ii) the recovery of the deferral and rate base effects of the
operating costs and construction of the Four Corners SCR project, with the
exception of $215.5 million (see "Four Corners SCR Cost Recovery" below), (iii)
that the CCT plan include the following components: (a) a payment of $1 million
to the Hopi Tribe within 60 days of the 2019 Rate Case decision, (b) a payment
of $10 million over three years to the Navajo Nation, (c) a payment of $500,000
to the Navajo County communities within 60 days of the 2019 Rate Case decision,
(d) up to $1.25 million for electrification of homes and businesses on the Hopi
reservation and (e) up to $1.25 million for the electrification of homes and
businesses on the Navajo Nation reservation. These payments and expenditures are
attributable to the future closures of Four Corners and Cholla, along with the
prior closure of the Navajo Plant and all ordered payments and expenditures
would be recoverable through rates, and (iv) a change in the residential on-peak
time-of-use period from 3 p.m. to 8 p.m. to 4 p.m. to 7 p.m. Monday through
Friday, excluding holidays. The 2019 Rate Case ROO, as amended, results in a
total annual revenue decrease for APS of $4.8 million, excluding temporary CCT
payments and expenditures. On November 2, 2021, the ACC approved the 2019 Rate
Case ROO, as amended. On November 24, 2021, APS filed with the ACC an
application for rehearing of the 2019 Rate Case and the application was deemed
denied on December 15, 2021, as the ACC did not act upon it. On December 17,
2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals and
a Petition for Special Action with the Arizona Supreme Court, requesting review
of the disallowance of $215 million of Four Corners SCR plant investments and
deferrals (see "Four Corners SCR Cost Recovery" below for additional
information) and the 20 basis point penalty reduction to the return on equity.
On February 8, 2022, the Arizona Supreme Court declined to accept jurisdiction
on APS's Petition for Special Action. The appeal at the Arizona Court of Appeals
is proceeding in the normal course. APS cannot predict the outcome of this
proceeding.

Consistent with the 2019 Rate Case decision, APS implemented the new rates
effective as of December 1, 2021. On December 3, 2021, ACC Staff notified the
ACC of a discrepancy between the written decision, which approved the change in
time-of-use on-peak hours to 4 p.m. to 7 p.m. but did not explicitly approve the
10-months contemplated in APS's verbal testimony to implement the new
time-of-use hours. On December 16, 2021, the ACC ordered APS to complete the
implementation of the time-of-use peak period by
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April 1, 2022. On January 12, 2022, the ACC voted to extend until September 1,
2022, the deadline to complete the implementation of the new on-peak hours for
residential customers. In addition, the ACC ordered extensive compliance and
reporting obligations and will be continuing to explore whether penalties or
rebates would be owed to certain customers. APS cannot predict the outcome of
this matter.

APS expects to file an application with the ACC for its next general retail rate case by mid-year 2022 but is continuing to evaluate the timing of such filing.

See Note 4 for information regarding additional regulatory matters.

Four Corners SCR Cost Recovery



As part of APS's 2019 Rate Case, APS included recovery of the deferral and rate
base effects of the Four Corners SCR project. On November 2, 2021, the 2019 Rate
Case decision was approved by the ACC allowing approximately $194 million of SCR
related plant investments and cost deferrals in rate base and to recover,
depreciate and amortize in rates based on an end-of-life assumption of July
2031. The decision also included a partial and combined disallowance of $215.5
million on the SCR investments and deferrals. APS believes the SCR plant
investments and related SCR cost deferrals were prudently incurred, and on
December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of
Appeals requesting review of the $215.5 million disallowance and the appeal is
proceeding in the normal course. Based on the partial recovery of these
investments and cost deferrals in current rates and the uncertainty of the
outcome of the legal appeals process, APS has not recorded an impairment or
write-off relating to the SCR plant investments or deferrals as of March 31,
2022. If the 2019 Rate Case decision to disallow $215.5 million of the SCRs is
ultimately upheld, APS will be required to record a charge to its results of
operations, net of tax, of approximately $154.4 million. We cannot predict the
outcome of the legal challenges nor the timing of when this matter will be
resolved. See Note 4 for additional information regarding the Four Corners SCR
cost recovery.

Financial Strength and Flexibility



Pinnacle West and APS currently have ample borrowing capacity under their
respective credit facilities and may readily access these facilities ensuring
adequate liquidity for each company.  Capital expenditures will be funded with
internally generated cash and external financings, which may include issuances
of long-term debt and Pinnacle West common stock.

Other Subsidiaries



Bright Canyon Energy. On July 31, 2014, Pinnacle West announced its creation of
a wholly-owned subsidiary, BCE.  BCE's strategy is to develop, own, operate and
acquire energy infrastructure in a manner that leverages the Company's core
expertise in the electric energy industry.  In 2014, BCE formed a 50/50 joint
venture with BHE U.S. Transmission LLC, a subsidiary of Berkshire Hathaway
Energy Company.  The joint venture, named TransCanyon, is pursuing independent
electric transmission opportunities within the 11 states that comprise the
Western Electricity Coordinating Council, excluding opportunities related to
transmission service that would otherwise be provided under the tariffs of the
retail service territories of the venture partners' utility affiliates. As of
March 31, 2022, BCE had total assets of approximately $60 million.

BCE is in advanced development stage on a microgrid facility in Los Alamitos,
California ("Los Alamitos") featuring 31 MW of solar, 20 MW of battery storage,
and 3 MW of backup generators. Supported by a long-term power purchase agreement
with San Diego Gas and Electric Company, Los Alamitos will supply 20 MW of solar
and battery storage capacity to the Southern California grid and provide
resilient backup power in the event of a grid emergency to the Army and
California National Guard at Joint Forces
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Training Base Los Alamitos. The Los Alamitos project is scheduled to achieve
commercial operation in 2023. See Note 3 regarding a credit agreement entered
into by BCE to finance capital expenditures and related costs for this microgrid
project.

BCE and Ameresco, Inc. jointly own a special purpose entity that is sponsoring
the K?pono Solar project. This project is a 42 MW solar and battery storage
facility in O?ahu, Hawaii that will supply clean renewable energy and capacity
under a 20-year power purchase agreement with Hawaiian Electric Company, Inc.
The K?pono Solar project is expected to be completed in 2024.

El Dorado. El Dorado is a wholly-owned subsidiary of Pinnacle West. El Dorado
owns debt investments and minority interests in several energy-related
investments and Arizona community-based ventures.  El Dorado committed to a $25
million investment in the Energy Impact Partners fund, which is an organization
that focuses on fostering innovation and supporting the transformation of the
utility industry. The investment will be made by El Dorado as investments are
selected by the Energy Impact Partners fund. As of March 31, 2022, El Dorado has
contributed approximately $10 million to the Energy Impact Partners fund.
Additionally, El Dorado committed to a $25 million investment in invisionAZ
Fund, which is a fund focused on analyzing, investing, managing and otherwise
dealing with investments in privately held early stage and emerging growth
technology companies and businesses primarily based in the State of Arizona, or
based in other jurisdictions and having existing or potential strategic or
economic ties to companies or other interests in the State of Arizona.

Key Financial Drivers



In addition to the continuing impact of the matters described above, many
factors influence our financial results and our future financial outlook,
including those listed below.  We closely monitor these factors to plan for the
Company's current needs, and to adjust our expectations, financial budgets and
forecasts appropriately.

Electric Operating Revenues.  For the years 2019 through 2021, retail electric
revenues comprised approximately 94% of our total operating revenues.  Our
electric operating revenues are affected by customer growth or decline,
variations in weather from period to period, customer mix, average usage per
customer and the impacts of energy efficiency programs, distributed energy
additions, electricity rates and tariffs, the recovery of PSA deferrals and the
operation of other recovery mechanisms.  These revenue transactions are affected
by the availability of excess generation or other energy resources and wholesale
market conditions, including competition, demand and prices.

Actual and Projected Customer and Sales Growth. Retail customers in APS's
service territory increased 2.2% for the three-month period ended March 31,
2022, compared with the prior-year period. For the three years through 2021,
APS's customer growth averaged 2.2% per year. We currently project annual
customer growth to be 1.5% to 2.5% for 2022, and the average annual growth will
be in the range of 1.5% to 2.5% through 2024 based on anticipated steady
population growth in Arizona during that period.

Retail electricity sales in kWh, adjusted to exclude the effects of weather
variations, increased 4.4% for the three-month period ended March 31, 2022,
compared with the prior-year period. While steady customer growth was somewhat
offset by energy savings driven by customer conservation, energy efficiency, and
distributed renewable generation initiatives, the main drivers of positive sales
for this period were residential sales being stronger than anticipated due to
continued work-from-home policies, a strong improvement in sales to commercial
and industrial customers, and the ramp-up of new data center customers. Though
the total expected impact of COVID-19 on future sales remains unknown, APS
experienced higher electric residential sales and lower electric commercial and
industrial sales from the outset of the pandemic through April 2021.
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Beginning in May 2021, electric sales to commercial and industrial customers
increased to levels in line with pre-COVID sales and such sales levels have
remained to date.

For the three years through 2021, annual retail electricity sales growth
averaged 1.7%, adjusted to exclude the effects of weather variations. We
currently project that annual retail electricity sales in kWh will increase in
the range of 1.5% to 2.5% for 2022, and average annual growth will be in the
range of 3.5% to 4.5% through 2024, including the effects of customer
conservation, energy efficiency and distributed renewable generation
initiatives, but excluding the effects of weather variations. This projected
sales growth range includes the impacts of new, large manufacturing facilities,
which are expected to contribute to average annual growth in the range of 1.0%
to 2.0% through 2024. This projected sales growth range also includes our
estimated contributions of several large data centers, but not all, and we will
continue to estimate contributions and evaluate sales guidance as these
customers develop more usage history. These estimates could be further impacted
by changes in the expected growth of the Arizona economy, slower than expected
ramp-up of the new data centers, larger manufacturing facilities not coming to
Arizona as expected, a change in the duration of remote work, changes in the
expected commercial and industrial expansions, or acceleration of the expected
effects of customer conservation, energy efficiency and distributed renewable
generation initiatives.

Actual sales growth, excluding weather-related variations, may differ from our
projections as a result of numerous factors, such as economic conditions,
customer growth, usage patterns and energy conservation, ramp-up of data
centers, impacts of energy efficiency programs and growth in DG, and responses
to retail price changes.  Based on past experience, a 1% variation in our annual
residential and small commercial and industrial kWh sales projections under
normal business conditions can result in increases or decreases in annual net
income of approximately $20 million, and a 1% variation in our annual large
commercial and industrial kWh sales projections under normal business conditions
can result in increases or decreases in annual net income of approximately $5
million.

Weather.  In forecasting the retail sales growth numbers provided above, we
assume normal weather patterns based on historical data.  Historically, extreme
weather variations have resulted in annual variations in net income in excess of
$25 million.  However, our experience indicates that the more typical variations
from normal weather can result in increases or decreases in annual net income of
up to $15 million.

Fuel and Purchased Power Costs.  Fuel and purchased power costs included on our
Condensed Consolidated Statements of Income are impacted by our electricity
sales volumes, existing contracts for purchased power and generation fuel, our
power plant performance, transmission availability or constraints, prevailing
market prices, new generating plants being placed in service in our market
areas, changes in our generation resource allocation, our hedging program for
managing such costs and PSA deferrals and the related amortization.

Operations and Maintenance Expenses.  Operations and maintenance expenses are
impacted by customer and sales growth, power plant operations, maintenance of
utility plant (including generation, transmission, and distribution facilities),
inflation, unplanned outages, planned outages (typically scheduled in the spring
and fall), renewable energy and demand side management related expenses (which
are offset by the same amount of operating revenues) and other factors.

Depreciation and Amortization Expenses.  Depreciation and amortization expenses
are impacted by net additions to utility plant and other property (such as new
generation, transmission, and distribution facilities), and changes in
depreciation and amortization rates.  See "Liquidity and Capital Resources"
below for information regarding the planned additions to our facilities.

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Property Taxes.  Taxes other than income taxes consist primarily of property
taxes, which are affected by the value of property in-service and under
construction, assessment ratios, and tax rates.  The average property tax rate
in Arizona for APS, which owns essentially all of our property, was 10.7% of the
assessed value for 2021, 10.8% for 2020 and 10.9% for 2019. We expect property
taxes to increase as we add new generating units and continue with improvements
and expansions to our existing generating units and transmission and
distribution facilities.

Pension and other postretirement non-service credits - net.  Pension and other
postretirement non-service credits can be impacted by changes in our actuarial
assumptions. The most relevant actuarial assumptions are the discount rate used
to measure our net periodic costs/credit, the expected long-term rate of return
on plan assets used to estimate earnings on invested funds over the long-term,
the mortality assumptions and the assumed healthcare cost trend rates. We review
these assumptions on an annual basis and adjust them as necessary.

Interest Expense.  Interest expense is affected by the amount of debt
outstanding and the interest rates on that debt (see Note 3).  The primary
factors affecting borrowing levels are expected to be our capital expenditures,
long-term debt maturities, equity issuances and internally generated cash flow.
An allowance for borrowed funds used during construction offsets a portion of
interest expense while capital projects are under construction.  We stop
accruing AFUDC on a project when it is placed in commercial operation.

Income Taxes.  Income taxes are affected by the amount of pretax book income,
income tax rates, certain deductions and non-taxable items, such as AFUDC.  In
addition, income taxes may also be affected by the settlement of issues with
taxing authorities.

                             RESULTS OF OPERATIONS

Pinnacle West's only reportable business segment is our regulated electricity
segment, which consists of traditional regulated retail and wholesale
electricity businesses (primarily sales supplied under traditional cost-based
rate regulation) and related activities and includes electricity generation,
transmission and distribution.

Operating Results - Three-month period ended March 31, 2022, compared with three-month period ended March 31, 2021.



Our consolidated net income attributable to common shareholders for the three
months ended March 31, 2022, was $17 million, compared with consolidated net
income attributable to common shareholders of $36 million for the prior-year
period.  The results reflect a decrease of approximately $18 million for the
regulated electricity segment primarily due to higher depreciation and
amortization expense resulting from the absence of the Ocotillo modernization
project and the Four Corners SCR project regulatory deferrals that ended upon
the 2019 Rate Case effective date and increased plant assets and higher income
taxes. These negative factors were partially offset by higher revenue driven by
customer usage and customer growth, increased transmission revenue and lower
operations and maintenance expense.

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The following table presents net income attributable to common shareholders by
business segment compared with the prior-year period:

                                                                    Three Months Ended
                                                                        March 31,
                                                                 2022                2021            Net Change
                                                                            (dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses    $      516          $     497          $       19
Operations and maintenance                                         (217)              (229)                 12
Depreciation and amortization                                      (187)              (158)                (29)
Taxes other than income taxes                                       (58)               (59)                  1
Pension and other postretirement non-service credits - net           24                 28                  (4)
All other income and expenses, net                                    9                 15                  (6)

Interest charges, net of allowance for borrowed funds used during construction

                                                 (61)               (57)                 (4)
Income taxes                                                         (4)                 4                  (8)
Less income related to noncontrolling interests (Note 6)             (4)                (5)                  1
Regulated electricity segment income                                 18                 36                 (18)
All other                                                            (1)                 -                  (1)
Net Income Attributable to Common Shareholders               $       17          $      36          $      (19)



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Operating revenues less fuel and purchased power expenses. Regulated electricity
segment operating revenues less fuel and purchased power expenses were $19
million higher for the three months ended March 31, 2022, compared with the
prior-year period. The following table summarizes the major components of this
change:

                                                                          Increase (Decrease)
                                                                                 Fuel and
                                                       Operating                purchased
                                                        revenues              power expenses            Net change
                                                                         (dollars in millions)

Lower refunds in the current year related to the
Tax Act (Note 4)                                   $      31                $             -          $          31
Higher retail revenue due to customer growth and
changes in customer usage patterns, partially
offset by the impacts of energy efficiency and
distributed generation                                    22                              9                     13
Higher transmission revenues (Note 4)                     12                              -                     12
Higher renewable energy regulatory surcharges,
partially offset by operations and maintenance
costs                                                      5                              -                      5
Effects of weather                                        (3)                            (1)                    (2)
Changes in net fuel and purchased power costs,
including off-system sales margins and related
deferrals                                                 52                             57                     (5)
Lost fixed cost recovery                                 (10)                             -                    (10)
Impact of new retail base rates from 2019 ACC
general rate case effective December 1, 2021             (23)                             -                    (23)
Miscellaneous items, net                                   -                              2                     (2)
Total                                              $      86                $            67          $          19



Operations and maintenance. Operations and maintenance expenses decreased $12
million for the three months ended March 31, 2022, compared with the prior-year
period primarily because of:

•A decrease of $15 million in non-nuclear generation costs primarily due to lower planned outages and lower operating costs;

•A decrease of $6 million related to employee benefits;



•An increase of $5 million primarily related to costs for renewable energy and
similar regulatory programs, which are partially offset in operating revenues
and purchased power; and

•An increase of $4 million in other miscellaneous factors.



Depreciation and amortization. Depreciation and amortization expenses were $29
million higher for the three months ended March 31, 2022, compared to the
prior-year period primarily due to $16 million for the Ocotillo modernization
project and the Four Corners SCR project regulatory deferrals that ended upon
the 2019 Rate Case effective date and $13 million related to increased plant in
service and updated depreciation rates.

Pension and other postretirement non-service credits, net. Pension and other
postretirement non-service credits, net were $4 million lower for the three
months ended March 31, 2022, compared to the prior-year period primarily due to
actual market returns being lower than estimated returns in 2021.
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Income taxes.  Income taxes were $8 million higher for the three months ended
March 31, 2022, compared with the prior-year period primarily due to lower
amortization of excess deferred taxes and the net operating loss carryback
benefit that the Company recognized during the first quarter of 2021, partially
offset by lower pre-tax income.


                        LIQUIDITY AND CAPITAL RESOURCES

Overview

Pinnacle West's primary cash needs are for dividends to our shareholders and
principal and interest payments on our indebtedness.  The level of our common
stock dividends and future dividend growth will be dependent on declaration by
our Board of Directors and based on a number of factors, including our financial
condition, payout ratio, free cash flow and other factors.

Our primary sources of cash are dividends from APS and external debt and equity
issuances.  An ACC order requires APS to maintain a common equity ratio of at
least 40%.  As defined in the related ACC order, the common equity ratio is
defined as total shareholder equity divided by the sum of total shareholder
equity and long-term debt, including current maturities of long-term debt.  At
March 31, 2022, APS's common equity ratio, as defined, was 51%.  Its total
shareholder equity was approximately $6.8 billion, and total capitalization was
approximately $13.3 billion.  Under this order, APS would be prohibited from
paying dividends if such payment would reduce its total shareholder equity below
approximately $5.3 billion, assuming APS's total capitalization remains the
same.  This restriction does not materially affect Pinnacle West's ability to
meet its ongoing cash needs or ability to pay dividends to shareholders.

APS's capital requirements consist primarily of capital expenditures and maturities of long-term debt. APS funds its capital requirements with cash from operations and, to the extent necessary, external debt financing and equity infusions from Pinnacle West.


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