Pinnacle West — Buying Time, Capacity, and Flexibility
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Decision date and information cutoff: 26 February 2025, 11:59 p.m. MST (Arizona)
Decision scope: APS's next incremental resource portfolio and procurement-screening strategy
Case convention: This is an author-created management decision exercise. The role and alternatives are hypothetical; company, regulatory, and solicitation facts are historical. No private deliberations are represented.
The decision
On 26 February 2025, Pinnacle West Capital Corporation (PNW) had just filed its FY2024 Form 10-K. Its Arizona Public Service subsidiary (APS) had received proposals in a new all-source resource solicitation. APS sought at least 2,000 MW for summer peaks, reserves, and the needs of extra-high-load-factor customers. The proposal deadline had passed on February 5. APS had scheduled shortlist notices for April through July and anticipated contract execution from June through December. Bidder identities, prices, proposed quantities, and scoring were not public. [S1, Item 7 and Note 1; S2, “What’s next”; S3, §§II–III]
You are preparing a recommendation for a hypothetical PNW strategy committee on how APS should evaluate the proposals and shape a shortlist. You do not know the bids and should not invent a winner. Recommend a decision rule and a portfolio posture: what reliability and delivery evidence must an offer provide, how should APS balance firm capacity with energy and flexibility, and how much should it preserve the ability to stage commitments as forecasts and project readiness become clearer?
The stakes are not simply whether Arizona will need more electricity. APS reported a peak-demand forecast above 13,000 MW by 2038, compared with about 8,200 MW at the time of its November 2024 announcement. APS described that as 60% growth over 14 years. This is a company forecast, not signed customer load. Public sources available for this case do not identify large-load customers or disclose their individual requests, commitments, ramp schedules, or payment obligations. [S2, “What’s next for APS’s energy grid and resource mix?”]
PNW, APS, and the customer
PNW is the publicly traded holding company; APS is its vertically integrated, rate-regulated electric utility and accounts for substantially all of PNW’s revenue and earnings. APS serves about 1.4 million homes and businesses in 11 Arizona counties. A resource choice can affect APS customer costs and service, while its financing and regulatory treatment can affect PNW. Those are connected outcomes, but they are not interchangeable. [S1, Item 1 and Note 1; S2, company description]
PNW reported FY2024 consolidated operating revenue of $5.125 billion and net income available to common stockholders of $608.8 million, compared with $4.696 billion and $501.6 million in FY2023. These parent-company totals describe financial context; they do not reveal the incremental customer cost, allowed return, or shareholder earnings from any APS proposal. [S1, consolidated statements of income, printed p. 95]
APS's latest announced procurement history also complicates the next choice. In November 2024 it said it had signed agreements for nearly 7,300 MW through its 2023 all-source RFP, describing 93% as coming directly from clean-energy technologies. Announced components included solar and wind PPAs, storage PPAs, gas-related expansions or contracts, and a solar plant under development. The figures are rounded; not all supply is APS-owned, operating, or immediately dispatchable. Storage MW describes power, not stored MWh, and durations were not all specified. [S2, opening and resource sections]
The 2024 RFP seeks at least 2,000 MW. It accepts power-purchase agreements (PPAs), build-transfer agreements (BTAs), engineering, procurement and construction (EPC) proposals, and load-management agreements (LMAs). Eligible resources include renewable, storage, thermal, and demand-side offers. The RFP requests hourly heat maps, firm summer capacity and reserves, delivery and interconnection information, and explanations of how non-dispatchable output contributes to reliability. It sets a 5 MW minimum and gives a mix of near-term and later commercial-operation windows. [S3, §§III, IV, VI and Appendix E]
The earlier agreements and new solicitation are different measures: signed agreements are not installed capacity, and the new RFP's requested MW are not awards. A comparison of 7,300 MW with 2,000 MW indicates only their announced scale. It does not show how much firm capacity is available in the same hours, what the new need will be after earlier projects arrive, or how much of the forecast is committed load.
A planning decision is not a project approval
APS's 2023 Integrated Resource Plan (IRP) described its preferred planning portfolio. On 8 October 2024, the Arizona Corporation Commission (ACC) acknowledged the 2023 IRPs while issuing additional planning requirements. The order expressly said acknowledgment was not endorsement or approval. It did not validate APS's load forecast or authorize each future project. The ACC required additional future portfolio and reporting work, including annual reporting on load-forecast accuracy and a resource-adequacy demonstration before a possible Four Corners exit. [S4, staff findings p. 2, acknowledgment limitation p. 6, orders pp. 7–11]
The APS RFP is a solicitation, not a project approval or cost-recovery decision. It states that a final agreement may be conditioned on regulatory actions or approvals satisfactory to APS and reserves APS's rights to accept or reject proposals. A shortlist, a signed contract, project-specific regulatory approval, and the treatment of costs in a later rate proceeding are separate steps. The record at this cutoff does not guarantee any of them. [S3, §XI(B)–(C)]
Affordability is already part of the regulatory context. In February 2024, the ACC approved an APS rate-case return on equity of 9.55%, with a 0.25% fair-value increment, versus APS's requested 10.25% ROE. The ACC estimated an approximately 8% impact, or $10–$12 per month, for a typical residential customer under that rate decision. This prior rate case is not a forecast of bills or recovery for any new resource. [S5, APS rate-case notice, docket E-01345A-22-0144]
What should count as a good offer?
The lowest quoted energy price may not produce the best fit. APS's solicitation asks for output by hour, summer capacity, reserves, transmission, interconnection, and delivery costs. Solar energy, stored energy, demand response, and dispatchable capacity can provide different services. Comparing nameplate MW or a single levelized cost per MWh would leave out timing, location, duration, availability, and system integration. The proposal record needed to assess these attributes is not public.
Timing creates a second trade-off. Earlier firm resources could reduce exposure to forecast shortages, market purchases, or a project delay. But long-lived or inflexible commitments can be costly if load ramps later or less than forecast. Staging, options, modularity, and performance gates can preserve choices, but delay also carries reliability risk. The public information gives no defensible estimate of APS's customer-specific shortage cost or the value of waiting.
The ownership form matters as well. A PPA may place some construction and operating risks on a counterparty; an owned or build-transfer project may give APS more control and a possible route to seek rate-base treatment. The risk allocation, financing, tax, guarantees, and future regulatory treatment depend on the specific contract and project. Neither ownership nor contracting guarantees lower customer bills or higher PNW earnings.
Two portfolio postures
Prioritize near-term firm capacity. Give greatest weight to firm summer contribution, reserves, delivery certainty, and commercial-operation date. Favor offers that can serve a credible near-term need, even if that means more dispatchable supply or less flexibility to defer. This posture responds to APS's forecast and reliability requirements. It risks committing customers to expensive or underused resources if load, project delivery, or existing supply develops differently than expected.
Stage a diversified portfolio. Favor a mix of firm capacity, renewable and storage profiles, demand-side flexibility, and contractual options. Use milestones, phased quantities, or later decision points where the RFP and offers permit them. This posture can preserve choice and manage forecast uncertainty. It risks leaving APS short if flexible or later resources are delayed, unavailable during peak hours, or unable to satisfy the actual load profile.
Both postures must be tested against offer-level information. There is no public basis to rank actual bidders or declare one resource type the winner.
Your assignment
Write a two-page recommendation for the hypothetical PNW strategy committee. Choose a portfolio posture or propose a clearly specified hybrid. Set out:
- The evidence threshold an offer must meet for hourly reliability, deliverability, interconnection, timing, and cost.
- How APS should compare energy, firm capacity, reserves, flexibility, clean-energy contribution, and ownership or contract forms.
- How it should manage the range of load outcomes without treating a forecast as a customer commitment.
- Which risks should be contractual, which require further regulatory review, and what APS should disclose to customers and investors.
- The evidence or milestones that would lead you to stage, accelerate, defer, or reject an otherwise attractive offer.
Use only information available by 26 February 2025. Do not assume bid prices, customer commitments, awards, or regulatory recovery. If you introduce numerical inputs, identify them as hypothetical and explain their purpose.
Discussion questions
- What service problem is APS buying capacity to solve? Which parts of the need are established by the RFP, and which depend on an uncertain forecast?
- How should the nearly 7,300 MW of announced 2023 agreements affect evaluation of the new 2,000 MW solicitation? What information would make that comparison meaningful?
- Which of the two portfolio postures is more defensible under forecast and delivery uncertainty? What is the strongest argument against it?
- How should APS compare a PPA, owned project, storage offer, demand-side offer, or dispatchable resource when bid-level cost and performance data are private?
- How do APS customer cost, reliability, and clean-energy goals relate to PNW shareholder returns? What should the committee avoid conflating?
- What must happen after APS selects or contracts with a proposal before a project is approved and its costs are treated in rates?
Sources and conventions
All facts are limited to the information cutoff. Figures described by APS as “nearly,” “about,” or “more than” remain rounded; components of the 2023 portfolio are not forced to sum to the headline. MW and MWh are kept distinct. Forecasts, solicitation targets, signed agreements, operating assets, awards, project approvals, and recoverable costs are different categories.
S1. Pinnacle West, FY2024 Form 10-K, filed 25 February 2025; Item 1, Item 7, Note 1 and consolidated statements of income, printed p. 95.
S2. APS, “APS Secures Its Largest-Ever Energy Supply to Reliably Serve Customers”, 20 November 2024; opening, resource sections, and “What’s next for APS’s energy grid and resource mix?”
S3. APS, 2024 All-Source RFP, final copy revised 31 December 2024; §§II–IV, VI, XI and Appendix E.
S4. Arizona Corporation Commission, Decision No. 79589, Docket E-99999A-22-0046; 8 October 2024 open meeting; staff findings p. 2, acknowledgment limitation p. 6, orders pp. 7–11.
S5. Arizona Corporation Commission, APS rate-case vote, 23 February 2024, Docket E-01345A-22-0144.