AEPCO 2021 RFP Documents

AEPCO 2021 All Source RFP

Apache Site Plan

Apache Station Soils

Evaluation Form for Non-Renewable Designated Generation Resources

Evaluation Form for Energy Storage and Renewable Designated Generation Resources

Power Purchase Agreement Evaluation Form for Firm Liquidated Damages Energy and Capacity

Power Purchase Agreement Evaluation Form for Call Option Products

Power Purchase Agreement Evaluation Form for Load Management from Demand-Side Resources

Bidder Registration Form

Confidentiality Agreement

AEPCO 2021 RFP Schedule

Issue Final Version of All-Source RFP

November 5, 2021

Q&A on Substantive RFP Issues (email)

November 5, 2021 –

December 3, 2021

Open Period for Submission of Bidder Registration Forms

November 5, 2021 –

November19, 2021

Deadline for Submission of Bidder Registration Forms (Appendix D) at 5:00 p.m. MST

November 19, 2021

Open Period for Submission of Proposals

November 20, 2021 –

December 17, 2021

Proposals (Appendices) Deadline at 5:00 p.m. MST

December 17, 2021

Bid Screening and Analysis Period

December 20, 2021 –

April 29, 2022

Notification of All-Source RFP Shortlist

May 2, 2022

Open Period for Submission of Best and Final Offers

May 2, 2022 – May 13, 2022

Final Bid Analysis Period

May 16, 2022 – July 29, 2022

Notification to Bidders of Recommendation of Award(s)

August 1, 2022

Finalize mutually agreeable Term Sheet (subject to AEPCO and participating members’ Board of Directors approval)

December 31, 2022

Bidder/Stakeholder
Questions and Responses

Responses to all relevant questions submitted to AEPCO2021RFP@acespower.com will be provided below

Relevant questions and responses related to the 2021 APECO RFP will be posted on this page. 

Yes, so long as they are relevant to the RFP.

Responses to questions will be provided as soon as practical. Response times will vary depending upon the complexity of the question.

No, submitting a Notice of Intent does not obligate your company to submit an offer. However, a Notice of Intent is required to be able to submit an offer on behalf of your organization for this RFP. 

No deposit is needed in association with submitting an offer or being shortlisted.

Yes, AEPCO will consider offers for stand-alone wind if they meet the minimum requirements of the RFP. Figure 4 in the RFP contains the effective capacity contribution for stand-alone wind. AEPCO does not have a preferred ratio for wind or solar paired with storage. However, if a bidder chooses to propose a paired resource project and that proposal or price is dependent on the storage only being charged by that resource (e.g. to qualify for the Investment Tax Credit), there is a minimum ratio requirement to ensure AEPCO has sufficient charging energy for the battery. The ratio of renewable to storage can be exceeded or bidders can choose to submit paired resource projects that have no charging restrictions (i.e., has full flexibility to be charged from the grid) in which case there is no minimum ratio requirement.

Yes, AEPCO will consider this product. The capacity credit calculation will follow the same formula as paired resources and include all three subject to an interconnection sizing cap.

AEPCO does not currently have transmission rights from Four Corners to the AEPCO transmission system. Per Section 2.2 of the RFP, bidders should identify any charges assessed by third-party transmission systems, including applicable ancillary services, to reach AEPCO’s system.

The resources in Figure 4 of the RFP are calculated for resources located in Arizona. For wind resources located in substantially different locations, such as New Mexico, AEPCO will evaluate the bidder’s 8760 profile in Mountain Standard Time for correlation with AEPCO’s demand profile. Bidders should indicate if their profile is based on a specific past weather year or a typical year. For typical year profiles, AEPCO will assess the resource’s ability to contribute during peak hours in June, July, and August since AEPCO can realize their annual peak demand in any of those months.

AEPCO is looking for a coincident, aggregated product of at least 1 MW for the Load Management resource type, minimum quantities for other resource types only apply to those resources. Bidders can make that up from any load source (including residential) or number of sites. AEPCO expects there will be some minimum performance standard for any Load Management agreement based on measurement and verification data as there would be with any agreement for a supply-side resource.

Yes, AEPCO would consider the total capability. AEPCO would need to understand any potential operating restrictions of the resource to determine the effective capacity contribution (e.g., only be limited by the potential for forced outages or other generator operating limitations which AEPCO would assess as an energy limited alternative like battery storage).

The resource must be available every day for a 6 hour duration window for June through September as stated in Section 2.2.5; however, AEPCO would not necessarily expect to have to call on the resource every day. Actual frequency and duration of events will vary year to year depending on the weather and market conditions. It will also depend on the size of the resource being offered. Larger resources will be needed for longer durations and greater frequency. If the bidder identifies event duration and/or frequency limitations in Appendix C-5, AEPCO will assess the resource like other energy limited alternatives to determine the effective capacity contribution.

There does not need to be a specific asset identified. AEPCO will consider market products as well. The requirements for those product types can be found in Sections 2.2.3 and 2.2.4 of the RFP.

AEPCO’s legal team is willing to review proposed redlines to the confidentiality agreement.

AEPCO does not have a single designated point of interconnection for projects for this RFP, given the potential range of project sizes and locations. AEPCO’s system at Apache includes two substations and 69kV, 115kV, and 230kV sub-transmission/transmission; however, availability at any given substation, voltage, or location would be determined by the interconnection queue and process. Larger projects can be assumed to interconnect at 230 kV, while smaller (less than 50 MW) can be assumed to interconnect at 69 kV.

Yes, AEPCO will equally consider AC-coupled and DC-coupled designs. Bidder should specify if the battery storage can or cannot be charged from the grid with its proposed design.

AEPCO is currently in the bilateral WECC market and predominantly interacts with other market participants according to the terms of the WSPP Inc. agreement; however, AEPCO generally self-supplies ancillary services for its own sub-balancing area from its resources and would follow any applicable WECC and NERC standard rules for ancillary services. AEPCO could potentially join an organized market sometime in the future during the term of a proposed agreement and would work with any successful bidder to account for this possibility in the contracting phase.

To the extent a bidder’s project can physically charge from the grid and provide ancillary services, AEPCO would allow it. Yes, the PPA could allow for grid charging, arbitrage, and ancillary services. As described in Section 3.2., item 3.e, bidders should specify if their resource is capable of providing ancillary services at the proposed pricing for AEPCO to consider in its evaluation (e.g., a battery may technically be capable of providing regulation, but should only be noted as a concurrent benefit if the different use case does not result in different pricing).

Per Section 2.2 of the RFP, bidders should identify any charges assessed by third-party transmission systems, including applicable ancillary services, to reach AEPCO’s system. AEPCO would consider being the counterparty with the third-party transmission provider; however, the bidder must demonstrate that transmission is available and the cost of the transmission service will be included in the economic evaluation.

AEPCO will work with any bidder proposing to use Apache land to optimize the location and provide support during any environmental permitting process. The map should be used for indicative acreage, proximity to existing transmission lines, and weather characteristics, but final siting would be subject to AEPCO’s input and approval. Bidders should assume all the sites will require due diligence prior to siting and include the cost and schedule impact of any necessary environmental permitting and/or rezoning their resource may require.

AEPCO will enable ancillary service characteristics on capable resources in its expansion plan modeling to value their contribution relative to AEPCO’s system needs. Battery energy storage must have a minimum of 120 full cycles per year for AEPCO to count the resource for firm capacity; however, AEPCO will consider bids for more than 120 cycles that allow for economic energy arbitrage or other potential value streams (like ancillary services). Bidders should only identify ancillary services that can be provided within the proposed operating parameters and AEPCO would expect to manage the use of the resource (for peak shaving, energy arbitrage, 10-minute reserves, etc.) within those parameters.

For example, a 100 MW battery that is proposed and is dependent on charging from solar (e.g., to qualify for the Investment Tax Credit) must be paired with a solar array that is at least 100 MW. The battery cannot be so much larger than the solar array such that there could be a risk of not being able to reach the necessary state of charge for reliable peak shaving. If a proposal allows for charging the battery from the grid at any time, there is no requirement for the relative size of the battery in a hybrid system.

The resource must be available every day for a six-hour duration window for June through September, as stated in Section 2.2.5; however, AEPCO would not necessarily expect to have to call on the resource every day. Actual frequency and duration of events will vary year to year, depending on the weather and market conditions. It will also depend on the size of the resource being offered, as larger resources will be needed for longer durations and greater frequency.

AEPCO does not have a preference and the capacity value calculation would treat separate systems as operationally the same as a hybrid (unless the interconnection of the hybrid limits the coincident output of the PV and BESS).

AEPCO does not have unlimited rights over the Pinal West 345/500 kV transformer (or from any of the preferred PODs), so it could depend on the size of the resource and what other resources may be competing for that path. Bidders can assume no additional wheel at this time; however, AEPCO may include the cost of that wheel during its evaluation after assessing the feasibility of solutions within AEPCO’s transmission asset portfolio. AEPCO can also take delivery at PINALWEST345 directly.

Bidders should assume the cost of stepping up to the delivery voltage at their chosen location. AEPCO will estimate the remaining cost of the interconnection for the evaluation. Bidders should try to site their project substation as close to the existing Apache substation as possible to minimize overhead gen-tie costs.

AEPCO does not have a preferred term length, it may vary by resource type and its expected useful life.

There are no boundaries for this All-Source RFP, AEPCO will consider any project a bidder proposes.

No information needs to be provided for site control if the project is proposed to be on AEPCO-owned land at Apache. Bidders should identify which portion of the site(s) they are proposing, though final siting will be subject to AEPCO’s input and approval.

Submitting a bidder registration is non-binding.

The Credit Support Provider will come into play if the potential counterparty is not creditworthy or does not provide audited financial statements. It is typically a creditworthy parent company.

AEPCO will provide this information by email, please request it individually.

This will be negotiated between AEPCO and the counterparty. The main factor will be the creditworthiness of the perspective counterparties. There may not be a requirement if the party has an investment grade rating and/or strong financials. The initial requirement will be audited financial statements for review.

This will be negotiated between AEPCO and the counterparty. The main factor will be the creditworthiness of the perspective counterparties. There may not be a requirement if the party has an investment grade rating and/or strong financials.

Yes, AEPCO is willing to consider distributed generators or batteries that either reduce customer load at the site or backfeed to the grid to supply other load (if they are designed for and have the approval of the distribution provider to backfeed). Bidders should note if there are any run time or dispatch limitations of a distributed generator (e.g. due to emission permitting).

AEPCO does not have a single designated point of interconnection for projects for this RFP given the potential range of project sizes and locations. AEPCO’s system at Apache includes two substations and 69kV, 115kV, and 230kV sub-transmission/transmission; however, availability at any given substation, voltage, or location would be determined by the interconnection queue and process. Larger projects can be assumed to interconnect at 230 kV, while smaller (less than 50 MW) can be assumed to interconnect at 69 kV.

AEPCO will work with any bidder proposing to use Apache land to optimize the location and provide support during any environmental permitting process. The map should be used for indicative acreage, proximity to existing transmission lines, and weather characteristics, but final siting would be subject to AEPCO’s input and approval. Bidders should assume all the sites will require due diligence prior to siting and include the cost and schedule impact of any necessary environmental permitting and/or rezoning their resource may require.

AEPCO will estimate the remaining cost of the interconnection beyond the project POI for the evaluation. Bidders should try to site their project substation as close to the existing Apache substation as possible to minimize overhead gen-tie costs. AEPCO will either directly pay these costs or include it as part of the developer’s scope of work with a corresponding price update (to be determined during contract negotiation).

No, bidders should not assume existing capacity rights are necessarily available for new projects given the breadth of potential resources and sizes being solicited with this All-Source RFP.

Bidders should assume the cost of stepping up to the interconnection delivery voltage, including the project substation, at their chosen location and AEPCO will estimate the remaining cost of the interconnection for the evaluation. Bidders should try to site their project substation as close to the existing Apache substation as possible to minimize overhead gen-tie costs. Refinement of interconnection costs will be done as part of the interconnection process.

Bidders should not assume any AEPCO or Apache site-specific tax abatement. However, some resource types may qualify for a partial exemption of personal property tax according to Arizona state law. Bidders should include all applicable taxes in their pricing.

Preferred parcels may depend on the technology being proposed. The map should be used for indicative acreage, proximity to existing transmission lines, and weather characteristics, but final siting would be subject to AEPCO’s input and approval.

 

Option 1

Option 2

PV Power MWAC

200

200

ESS Power Rating MWAC

50

200

ESS Energy Rating MWh

200

800

Hours

4

4

Capacity in this definition means the power rating. Both options provided for example in this question would be acceptable—with Option 1 the solar capacity is 400% of the battery capacity (greater than the 100% minimum) and Option 2 is exactly 100% and would be as small as the solar can be paired with the example 200MW/800MWh battery. And just for added clarification, if the battery is not restricted in its charging source and can charge from the grid, there is no relative size requirement.

Yes, but date of submission may be considered in part of the evaluation (quality of proposal).