Consideration of Action to Approve a Post-2019 Power Portfolio

Transcription

1 Agenda Number 9biv CONTACT: Thomas W. McCann (623) MEETING DATE: April 5, 2018 AGENDA ITEM: Consideration of Action to Approve a Post-2019 Power Portfolio LINKAGE TO STRATEGIC PLAN, POLICY, STATUTE OR GUIDING PRINCIPLE: CAWCD 2016 Board of Directors Strategic Plan Effectively communicate financial issues to the Board, customers and stakeholders Maintain existing generation resources until appropriate alternatives are available Prepare for eventual replacement of NGS through implementation of the Post-NGS Power Strategy PREVIOUS BOARD ACTION/ACTIVITY: None October 17-18, 2013 Board of Directors Energy Retreat June 24, 2014 Board of Directors Scenario Planning Workshop October 1, 2015 Board of Directors approved Post-NGS Power Strategy February 2, 2017 Board report on NGS February-June 2017 Power Task Force meetings September 7, 2017 Board update on RFP process February 1, 2018 Board update on RFP process March 15, 2018 FAP Committee reviewed options for a post-ngs portfolio and recommended two options to the Board as the most preferred: the Max Fleet and the Lowest Cost; and also recommended that the Board discuss the entirety of all portfolios, including potential renewable sources, as considerations beyond lowest cost and least risk. ISSUE SUMMARY/DESCRIPTION: Board Direction In October 2015, the Board adopted a strategy for meeting CAP energy needs after NGS is no longer available. The 2015 strategy provided that CAP should assemble a diversified energy portfolio to meet its pumping needs and that CAP should pursue those power resources that offer the lowest levelized cost of ownership while still meeting CAP pumping needs and Board strategy. From February through June of 2017, the Board convened a Power Task Force that discussed CAP energy needs, potential options for supplying those needs, power market conditions and acquisition alternatives, and risk tolerance (hedging). The Power Task

2 Force received presentations by Western Grid Group, the National Renewable Energy Laboratory, K.R. Saline & Associates, APS and Navigant. (A summary of the first four meetings of the Power Task Force accompanies this brief.) The Power Task Force ultimately provided the following additional direction to staff in assembling a post-ngs energy portfolio: Diversification: No single generation unit should provide more than 15-20% of CAP energy needs. Base Load: Hedge 75% to 90% of CAP s base load energy needs prior to the delivery year. Variable Load: Hedge up to 40% of CAP s variable load energy needs prior to the year of delivery. Renewables: Consider firmed renewable energy proposals on an equal basis with nonrenewable proposals. Consider purchasing MW of non-firmed renewable energy. In November 2017, CAWCD issued a Request for Proposal for the Purchase of Electrical Capacity and Energy (RFP) to supply CAP pumping loads beginning in January The RFP sought proposals to serve up to 40% of CAP s variable load and up to 90% of CAP s base load needs. Eighteen responses were submitted by the January 17, 2018 due date. CAP Variable Load Six respondents submitted proposals to serve portions of CAP s variable energy demands at Mark Wilmer Pumping Plant. All of the proposals offered the same product a standard WSPP service agreement. Thus, the only basis for differentiating among proposals is price. Because energy under these agreements is not to be delivered until 2020 or 2021, the respondents requested and have been granted the opportunity to refresh their price quotes in late May. If the refreshed price quotes are attractive, staff may bring one or more variable load contracts to the Board for approval in June. CAP Base Load At the conclusion of the Power Task Force, various Board members indicated that they would like to see options (portfolios) that emphasized the following characteristics: Lowest cost Renewable energy Power generation on tribal lands Diversification Accordingly, based on the RFP responses staff has developed five portfolios for Board consideration to address CAP s base load power needs. 1. Lowest Cost. As the name suggests, this portfolio offers the lowest per-unit cost of the five alternatives. With this portfolio CAP would enter into (i) a 5-year power purchase agreement (PPA) with an Arizona utility that would provide 35 MW of capacity and energy from its fleet of generation resources and (ii) a 20-year PPA with an entity that would construct a 30 MW photovoltaic solar generation facility. Together, the two PPAs would provide 35.2% of CAP s base load energy needs.

3 When added to CAP s existing Hoover entitlement, this portfolio would be sufficient to meet all of CAP s base load energy needs during the summer peak. 2. Max Fleet. With this portfolio CAP would enter into (i) a 5-year power purchase agreement (PPA) with an Arizona utility that would provide 50 MW of capacity and energy from its fleet of generation resources and (ii) a 20-year PPA with an entity that would construct a 30 MW photovoltaic solar generation facility. Together, the two PPAs would provide 46.9% of CAP s base load energy needs. When added to CAP s existing Hoover entitlement, this portfolio would be sufficient to meet all of CAP s base load energy needs during the summer peak. 3. Tribal Lands. With this portfolio CAP would enter into (i) a 5-year power purchase agreement (PPA) with an Arizona utility that would provide 35 MW of capacity and energy from its fleet of generation resources and (ii) a 20-year PPA with an entity that would construct a 30 MW photovoltaic solar generation facility located on tribal trust lands. Together, the two PPAs would provide 35.1% of CAP s base load energy needs. When added to CAP s existing Hoover entitlement, this portfolio would be sufficient to meet all of CAP s base load energy needs during the summer peak. 4. Max Diversity. With this portfolio CAP would enter into (i) a 5-year power purchase agreement (PPA) with an Arizona utility that would provide 25 MW of capacity and energy from its fleet of generation resources, (ii) a 20-year PPA with an entity that would construct a 30 MW photovoltaic solar generation facility, and (iii) a 20-year PPA for 37 MW of firm energy with entities that would construct a photovoltaic solar generation facility and provide services to firm the energy output of that facility. Together, the three PPAs would provide 46.6% of CAP s base load energy needs. When added to CAP s existing Hoover entitlement, this portfolio would provide more energy than CAP needs to meet its base load energy needs during the summer peak, which could require CAP to sell surplus energy during those periods. 5. Max Solar. With this portfolio CAP would enter into (i) a 20-year PPA with an entity that would construct a 30 MW photovoltaic solar generation facility, and (ii) a 20-year PPA for 37 MW of firm energy with entities that would construct a photovoltaic solar generation facility and provide services to firm the energy output of that facility. Together, the two PPAs would provide 27.2% of CAP s base load energy needs. When added to CAP s existing Hoover entitlement, this portfolio would be sufficient to meet all of CAP s base load energy needs during the summer peak. Slide 26 of the staff presentation shows the total estimated cost of supplying CAP s total base load energy needs under each of the five portfolios. Next Steps Staff is requesting that the Board select a preferred portfolio in April. Based on the Board s direction, staff would then negotiate appropriate PPAs with respondents and bring those agreements to the Board for approval in June.

4 Agenda Number 9biv Attachment 1 Power Task Force Meetings Summary Task Force Meeting on February 16, 2017 Presentations by Staff Impact of NGS Closure on CAP The cost of generation at NGS is now more expensive than other alternatives. If CAP had bought energy at prevailing market rates in 2016, rather than using NGS, it would have saved $38.5 million. Sales of surplus NGS energy in 2016 provided approximately $12 million in CAP repayment assistance. If NGS closes, the potential energy savings for CAP likely outweigh the loss of repayment revenue. Post-NGS Strategy The strategy approved by the CAP Board in October 2015 states that when NGS is no longer available CAP should assemble a diversified energy portfolio in which no single generation source or contract provides more than 15-20% of CAP s energy needs. The strategy further states that CAP will pursue power resources that offer the lowest levelized cost of ownership while still meeting CAP pumping needs and Board strategy. CAP Energy Needs CAP s energy needs fall into two categories: base load and variable load. Base load, mainly associated with CAP pumping plants downstream of Mark Wilmer PP, is driven by customer deliveries and is fairly predictable. Base load is best served by more certain resource supplies. Variable load, mostly at Mark Wilmer PP, can be shaped daily and seasonally to take advantage of changes in the power market. Variable load can be served using a flexible, market-based strategy. Potential Options for CAP Pumping Energy CAP has many options for replacing NGS, including a full requirements agreement with a utility that has a fleet of generators, purchase power agreements and market purchases. It is probably not feasible or desirable for CAP to own its own generation resource. CAP should conduct a competitive process to identify the lowest cost options to serve the CAP load reliably. CAP could entertain bids to serve all or any portion of the CAP load. It may be advantageous to leave a portion of the CAP variable load open to the market.

5 Task Force Meeting on March 16, 2017 Presentations by Staff Review of CAP Energy Needs CAP s base load energy demands are dictated by water deliveries. CAP has little to no ability to shape or adjust this load. Base load needs are best supplied by forwardpurchased resources and longer terms to achieve price stability and limit risk. CAP s variable load is primarily associated with the Mark Wilmer Pump Plant. CAP has significant flexibility to schedule this load in response to market conditions. Variable load is best served by spot market purchases, supplemented by short-term products when economic. Update on Power Market Natural gas production in the U.S. has increased significantly in recent years and prices have fallen as a result. Current forward pricing for natural gas is fairly flat through Prices for electricity are also projected to remain relatively low for some time. Significant increases in renewable generation in recent years, particularly in California, have resulted in an oversupply of energy during certain times of the day and year. This oversupply is represented by the so-called Duck Curve. CAP has been able to take advantage of this situation, buying energy for as little as $3-7/MWh significantly less than the Palo Verde market price. Review of Power Acquisition Alternatives In general, market purchases of energy can be executed on a day-ahead basis (spot market) or as a forward purchase at a fixed price typically 0 to 3 years in advance of delivery. Such purchases provide flexibility to take advantage of favorable electricity prices. Power purchase agreements (PPA) are usually executed for more than three years. The PPA is an effective tool to manage forward risk for loads that are somewhat inflexible. A full requirements contract would typically be for a longer term. Pricing could be similar to a PPA, based on an index or tied to a utility s rates. A full requirements contract may provide an opportunity to reduce transmission costs or administrative costs, and may provide long-term price stability. Generation ownership would require a large up-front capital investment and long-term regulatory and O&M obligations. This option may not be compatible with Board guidance to diversify CAP s energy portfolio. 2

6 Discussion Regarding Risk Tolerance CAP base load needs are probably best met through hedging simply defined as the forward purchase of physical electricity. This will promote stable pumping energy rates. Hedging is independent of current and future market conditions. The majority of CAP's variable load should not be hedged. CAP can schedule this load to avoid exposure to high market prices and can react to price variability on a near instantaneous basis. By relying on market purchases, CAP can take maximum advantage of favorable market conditions to keep pumping energy rates as low as possible. Task Force Meeting on April 20, 2017 Presentation by Amanda Ormond, Western Grid Group Energy Landscape Shaping Opportunities The primary risk of wind and solar energy is the intermittent nature of those resources. But when combined with hydropower, storage or market purchases, wind and solar can provide a firm supply. Prices for wind and solar energy have been declining. Natural gas prices have been volatile in the past. Arizona must import all of its natural gas, and the growing demand for natural gas will require increases in pipeline capacity. The development of the Energy Imbalance Market, which offers a 5-minute trading platform, supports use of renewable resources. There is growing support for renewable energy among the public, CAP subcontractors and industry. Presentation by David J. Hurlbut, National Renewable Energy Laboratory Update on Trends Affecting the Southwest Power Market Capacity factors for combined cycle natural gas plants in the southwest are increasing while those for coal plants are declining. Renewable energy generation is increasing and the costs of utility-scale solar energy are decreasing. Natural gas prices have historically been volatile and that could continue. Renewables combined with natural gas capacity in a mixed resource portfolio could provide a hedge against future price volatility. 3

7 Task Force Meeting on May 18, 2017 Presentation by Ken Saline, K.R. Saline & Associates Arizona Transmission Challenges The Arizona transmission system is robust and supports the statewide load forecast through Several large-scale, high voltage merchant transmission projects are in the final planning stages for Arizona. California s renewable portfolio standard and the resulting Duck Curve is changing the way that power flows on the grid, increasing the flow from west (CA) to east (AZ). Presentation by Brad Albert, Arizona Public Service Wholesale Energy Markets in the West The power supply portfolio in the west is changing due to renewable energy policies and low natural gas prices, resulting in low (and even negative) wholesale prices. Merchant gas generators are struggling to remain viable. Natural gas prices are projected to remain stable for the long-term. APS maintains a balanced portfolio, with coal currently supplying 32% of its energy needs and natural gas 21%. APS employs a three-year rolling commodity hedge program to manage energy price risk, particularly with respect to natural gas. Renewable energy generation, particularly in California, significantly exceeds mid-day load during certain months of the year, resulting in strong negative pricing in the wholesale market. At times, APS has been paid more than $150/MWh to take renewable generation from California. This situation is expected to continue as California increases its renewable portfolio standard to 50% by Presentation by Dale Probasco, Navigant Consulting Macro Overview Of Desert Southwest Power Market - Challenges And Opportunities Navigant projects that the southwest will have excess generation capacity for the next twenty years. Natural gas prices are projected to remain relatively flat through 2020 and then increase and be more volatile in the future. Pipeline capacity expansion will be needed to keep pace with demand for natural gas. There will continue to be coal plant retirements. Most new generation facilities will be natural gas-fired or solar. 4

8 Agenda Number 9biv Attachment 2 NGS Replacement Energy Responses to RFP Thomas W. McCann March 15, 2018 How We Got Here Board energy workshops in October 2013 & June 2014 amid continuing uncertainty about NGS future Post NGS strategy adopted in October 2015 NGS owners announced in February 2017 that they would not operate the plant after 2019 Power Task Force met February through June 2017 CAP issued RFP for post NGS energy in November 2017 RFP responses received in January

9 Proposed Next Steps FAP portfolio recommendation (today) Board selects preferred portfolio (April) Agreements negotiated with power providers (April May) Board approves contracts for post 2019 pumping energy (June) 3 CAP Energy Needs Variable Load Variable Load at Mark Wilmer Pumping Plant can be shaped daily and seasonally to take advantage of changes in the power market, allowing CAP to optimize pumping to lower energy costs Base Load 0 GWH Base Load, at pumping plants downstream of Mark Wilmer, is driven by customer deliveries and is fairly predictable, requiring more certain resource supplies 2

10 McCULLOUGH Las Vegas CRYSTAL Page NGS DAVIS PARKER Parker MWP 289 MW HAVASU BOUSE HOOVER MEAD HARCUVAR LITTLE HARQUAHALA 123 MW PALO VERDE West HASSAYAMPA Phoenix Area SUN VALLEY Buckeye NEW WADDELL LIBERTY RACEWAY Sun City NAVAJO CAP PARKER DAVIS INTERTIE APS 57 MW MORGAN WESTWING North Scottsdale PINNACLE PEAK ROGERS Mesa COOLIDGE THUNDERSTONE SALT GILA SPOOK HILL ED 2 TWIN PEAKS RATTLESNAKE TAP ED 5 49 MW ED 4 RED ROCK SAGUARO BRADY PICACHO Tucson A Tucson B SANDARIO BRAWLEY SAN XAVIER Avra Valley 31 MW SNYDER HILL / BLACK MOUNTAIN TUCSON Tucson DEL BAC Post NGS Strategy (Adopted Oct. 2015) When NGS is no longer available, CAP will assemble a diversified energy portfolio to meet its pumping needs No single generation source or contract should provide more than 15 20% of CAP energy needs CAP will pursue those power resources that offer the lowest levelized cost of ownership while still meeting CAP pumping needs and Board strategy 6 3

11 Additional Direction from Power Task Force 1. Diversification: No single generation unit should provide more than 15 20% of CAP energy needs 2. Base Load: Hedge 75% to 90% of CAP s base load energy needs prior to the delivery year 3. Variable Load: Hedge up to 40% of CAP s variable load energy needs prior to the year of delivery 4. Renewables: a. Consider firmed renewable energy proposals on an equal basis with non renewable proposals b. Consider purchasing MW of non firmed renewable energy 7 RFP Products Sought Part A: Up to 40% of the capacity and energy requirements for MWPP (Variable Load) Part B: Up to 125 MW of capacity with capability to supply up to 1000 GWh of energy, with no more than 75 MW from any single unit (Base Load energy) Part C: Full energy requirements for CAP re lift plants for one or more geographic load centers (Base Load geography) 4

12 RFP Part A RFP identified 6 separate products, ranging from MW, covering onpeak and off peak hours during various seasons 6 respondents All respondents offered standard WSPP service agreements Respondents will have an opportunity to refresh price quotes in late May RFP Part B Up to 1000 GWh for CAP base load; intermittent resources limited to 30 MW 12 responses received Unfirmed solar/wind Firmed solar Utility fleet Wide range in price Variety of proposed delivery points 5

13 RFP Part C Full requirements for CAP pumping plants (other than MWPP) in specific geographic areas 2 responses received No discernable advantage to geographic approach as compared to Part B RFP Evaluation Criteria Functional Capabilities and Experience Relevant Market Expertise Financial Strength Proposed Energy Supply and Delivery What CAP facilities candidate is proposing to supply and ability to supply these facilities Generation technology and plant/fleet size that will be utilized to serve the CAP load Fuel(s) hedging Delivery point for the energy Indicative Pricing 12 6

14 Suggested Portfolio Options 1. Lowest Cost 2. Max Fleet 3. Tribal Lands 4. Max Diversity 5. Max Solar 13 Lowest Cost Portfolio Source Quantity PPA Term Utility fleet 35 MW 5 years Solar (unfirmed) 30 MW 20 years Estimated Unit Cost Hedge $34.24/MWh 35.2% Hedge = percent of CAP base load energy needs covered by PPAs 14 7

15 Lowest Cost Portfolio Base Load Energy Base Load Capacity MW Lowest Cost Portfolio Off Peak Average Load On Peak Average Load Spring Summer Fall Spring Summer Fall (Jan May) (Jun Aug) (Sep Dec) (Jan May) (Jun Aug) (Sep Dec) Forward/Daily Purchases Hoover Utility Fleet Solar 15 Max Fleet Portfolio Source Quantity PPA Term Utility fleet 50 MW 5 years Solar (unfirmed) 30 MW 20 years Estimated Unit Cost Hedge $34.91/MWh 46.9% Hedge = percent of CAP base load energy needs covered by PPAs 16 8

16 Max Fleet Portfolio Base Load Energy Base Load Capacity MW Max Fleet Portfolio Off Peak Average Load On Peak Average Load Spring Summer Fall Spring Summer Fall (Jan May) (Jun Aug) (Sep Dec) (Jan May) (Jun Aug) (Sep Dec) Forward/Daily Purchases Hoover Utility Fleet Solar 17 Tribal Lands Portfolio Source Quantity PPA Term Utility fleet 35 MW 5 years Solar (unfirmed)* 30 MW 20 years * Located on tribal lands Estimated Unit Cost Hedge $40.78/MWh 35.1% Hedge = percent of CAP base load energy needs covered by PPAs 18 9

17 Tribal Lands Portfolio Base Load Energy Base Load Capacity MW Tribal Lands Portfolio Off Peak Average Load On Peak Average Load Spring Summer Fall Spring Summer Fall (Jan May) (Jun Aug) (Sep Dec) (Jan May) (Jun Aug) (Sep Dec) Forward/Daily Purchases Hoover 60 Solar Utility Fleet 19 Max Diversity Portfolio Source Quantity PPA Term Utility fleet 25 MW 5 years Solar (unfirmed) 30 MW 20 years Solar (firmed) 37 MW 20 years Estimated Unit Cost Hedge $41.27/MWh 46.6% Hedge = percent of CAP base load energy needs covered by PPAs 20 10

18 Max Diversity Portfolio Base Load Energy Base Load Capacity MW Max Diversity Portfolio Off Peak Average Load On Peak Average Load Spring Summer Fall Spring Summer Fall (Jan May) (Jun Aug) (Sep Dec) (Jan May) (Jun Aug) (Sep Dec) Firmed Solar Forward/Daily Purchases Hoover Solar 20 Utility Fleet 21 Max Solar Portfolio Source Quantity PPA Term Solar (unfirmed) 30 MW 20 years Solar (firmed) 37 MW 20 years Estimated Unit Cost Hedge $44.37/MWh 27.2% Hedge = percent of CAP base load energy needs covered by PPAs 22 11

19 Max Solar Portfolio Base Load Energy Base Load Capacity MW Off Peak Average Load On Peak Average Load Spring Summer Fall Spring Summer Fall (Jan May) (Jun Aug) (Sep Dec) (Jan May) (Jun Aug) (Sep Dec) Max Solar Portfolio Forward/Daily Purchases 89 Hoover Firmed Solar Solar 23 Portfolio Comparison Capacity (MW) Lowest Cost Max Fleet Tribal Lands Max Diversity Max Solar Utility Fleet Solar (UF) * Solar (F) * Located on tribal lands 24 12

20 Portfolio Comparison Energy (GWh) Lowest Cost Max Fleet Tribal Lands Max Diversity Max Solar Hedge% 90% 75% 25 Portfolio Comparison Portfolio PPA Cost ($/MWh) PPA Hedge Base Load Cost ($M) Lowest Cost $ % $35.0 Max Fleet $ % $36.2 Tribal Lands $ % $37.6 Max Diversity $ % $39.0 Max Solar $ % $37.1 PPA Hedge = percent of CAP base load energy needs covered by PPAs Base Load Cost = total cost to supply CAP Base Load needs assuming 90% hedge for all portfolios 26 13

21 Proposed Next Steps FAP portfolio recommendation (today) Board selects preferred portfolio (April) Agreements negotiated with power providers (April May) Board approves contracts for post 2019 pumping energy (June) 27 Questions az.com