La Capra Associates told the Georgia Public Service Commission in a memo filed May 26 that Georgia Power may want to rethink its recommendation to delay issuing a request for proposals (RFP) for new wind capacity until after the utility files its 2016 integrated resource plan (IRP) with the commission.
La Capra reviewed a Feb. 27 wind request for information (RFI) report submitted by Georgia Power as part of its compliance with the stipulation approved by the Georgia PSC. The stipulation provided for certification of the Blue Canyon II and VI wind power purchase agreements (PPAs) and included an agreement by Georgia Power to further evaluate opportunities for future wind resource procurement. Georgia Power issued an RFI on Dec. 4, 2014, and the La Capra’s Wind RFI Report provides the information it gathered via the RFI process.
“Georgia Power received a healthy response to its RFI,” said La Capra. “There were 26 responses from 14 different companies. Given the different pricing options provided with some bids, there were 40 separate project entries. The projects were located in 21 different location across the Midwest and Southern United States. There were 8 projects from Oklahoma totaling 2000 megawatts (MW). None of the responses offered a Georgia site.
“The indicative pricing information submitted in the responses shows that there is a lot of wind available at attractive pricing. The Wind RFI Report states that project pricing ranged from $15.77 to $84.26 per MWh for contracts varying in length from 15 to 25 years. The pricing includes the renewable energy credits associated with the power. Pricing was either given at the busbar or delivered to the Southern Company interface. Projects priced at the busbar were generally priced lower than those which included delivery to the Southern Company interface.
“The Company looked at transmission costs and availability to bring wind power from the wind resource heavy regions in Midcontinent Independent System Operator, Inc. (MISO) and Southwest Power Pool (SPP) into the Southern Balancing Authority (SBA). The analysis of delivery charges between MISO and SPP and the SBA, based on 2014 market price data, shows that the average charges in 2014 would have been relatively modest ($1 to $6 per MWh for congestion and $0 to $2 per MWh for losses), but the maximum delivery charge in 2014 would have been very high (as much as $340 per megawatt hour (MWh) for congestion and $128 per MWh for losses).
“We reviewed the 2014 data behind these figures and found that the maximum prices only occurred during a small fraction of the hours in 2014. Other than those few hours of very high cost charges, delivery charges were close to the average prices in most hours. The company did not provide any information to indicate how transmission developed in these markets during 2014 or planned for later years might change the outlook for delivery charges in future years, but they did note that forecasts call for more moderate and stabilizing conditions which would be a very different environment from experiences in the past few years.
“Additionally, the Company looked at the cost and availability of firm transmission transfer capability to SBA across the interfaces with MISO, Tennessee Valley Authority (TVA) and Virginia-Carolinas Subregion (VACAR) of the Southeast Electric Reliability Council (SERC). The three interfaces were evaluated over a time period of nine years (2016-2024) for firm wind energy additions in 100 MW increments. For each 100 MW increment, necessary transmission upgrades were identified and a cost estimate was made for the required upgrades. The Company concluded that the SBA could not accommodate the proposed levels of additional long term firm wind generation in the next several years due the need to plan and implement upgrades that would expand the firm transfer capability limits into SBA.
“We note that the firm transfer limits assessment has bearing on the ability for the capacity value of the wind projects to be delivered to SBA, but does not preclude delivery of energy from such projects on a non-firm basis (subject to interruption at times when the system is actually operating at the transfer limits). The intermittent nature of wind means that these projects offer only limited capacity value. The energy value of the wind projects is their predominant value. The Company did not evaluate the potential for, or the costs of, non-firm imports into the SBA. Utilizing non-firm transmission options could allow the Company to contract for more wind energy than the firm transmission limitation allows. Given the low energy costs of many of these projects, relative to the Company’s avoided energy costs, non-firm options for wind energy should be evaluated, as well.
“Georgia Power did an analysis of the net benefits of the project proposals by comparing the projects’ total cost to customers versus the Company’s avoided cost. The Company estimated the cost of firm delivery to the SBA for those projects that did not provide pricing for power delivered to SBA. The net benefit for each project was determined by subtracting the cost of energy purchased, the delivery cost, and the cost of any required transmission improvements from Georgia Power’s avoided cost.
“In the Wind RFI Report, the Company stated that the calculated net benefits ranged from -$13.58/MWh to $24.31/MWh. The Company also provided the Commission Staff with a spreadsheet showing the net benefits of all the project configurations analyzed. Of the 37 project configurations analyzed, 30 project configurations had positive net benefits, with the majority of these having significant net benefits.
“As stated above, the Company did not evaluate the potential for or costs of non-firm transmission for the proposed projects into the SBA. The net benefits calculation also used firm, rather than non-firm, transmission costs. However, 10 of the 30 project configurations that showed net benefits were projects that proposed busbar delivery and therefore included the Company’s assumed cost of firm transmission. This indicates that consideration of non-firm options could enhance the value of some options that are already showing net benefit with firm transmission. Wind is primarily an energy rather than capacity resource, so it may not be necessary for a wind project to have firm transmission to create benefits for rate payers.”
La Capra says possible expiration of a federal tax credit is a major reason to move now
“While the Company acknowledges that the results of the RFI ‘suggest that there are potential deals that may provide savings,’ the Company feels that the results do not warrant issuing an RFP in advance of the next Integrated Resource Plan (IRP). The Company feels that generation expansion and retirement plans are more appropriately addressed through the IRP process. The Company also states that waiting until the 2016 IRP process may allow more insight on how procuring wind from outside the Southern Company system might provide value in the context of compliance obligations from pending environmental regulations like the Environmental Protection Agency’s (EPA) Clean Power Plan.
“There are several risks to waiting to issue an RFP until after the 2016 IRP process: the future availability of the production tax credit (PTC) and future changes in the market dynamics which may result from environmental regulations such as the Clean Power Plan. The Company does not address either of these risks in the Wind RFI report.”
The PTC currently offers a 2.3 cents/kWh tax credit to wind projects that begin construction by Dec. 31, 2014, La Capra added. Project developers can meet the begin construction by:
- Beginning physical work of a significant nature; or
- Paying/incurring at least 5% of the total project costs before Jan. 1, 2015.
“If the Company were to issue an RFP now, it is likely that some of the project proponents would be able to meet the threshold for beginning construction before January 1, 2015,” La Capra said. “If the Company waits until after the 2016 IRP process and the PTC is not renewed, there is a very real risk that few, if any, of the bidders will be able to take advantage of the PTC and the pricing may not be as attractive. At this time, it is unclear whether the PTC will be renewed or, if it is renewed, what the terms of the PTC will be at that time.
“The Clean Power Plan is a new EPA regulation which is still a proposed and not a final regulation. The Clean Power Plan aims to reduce carbon emissions from the power sector by 30% below 2005 levels with state-specific goals. Each state or multi-state collaborators must develop a plan to meet individual carbon intensity reduction through combination of: plant efficiency improvements; shifting generation from higher to lower-emitting resources; maintaining and expanding nuclear and renewable generation; and energy efficiency.
“Procuring wind power will likely be a method of compliance for the Company to meet Georgia’s goals under the Clean Power Plan. It is also likely that other states will be using wind power for compliance with Clean Power Plan goals which would increase competition for wind power. This means that waiting to issue an RFP risks increased competition for wind resources which would lead to higher prices for Georgia ratepayers. Given that most of the indicative pricing included in the RFI responses are below the Company’s avoided energy costs, an RFP would afford the Company an opportunity to consider actual proposals now that could lower costs of energy in any circumstance and also provide potential added benefits if such purchases also aide in the compliance with the Clean Power Plan if enacted.
“There is a real opportunity for Georgia Power to pursue wind power now. Given the large number and competitive pricing of responses to Georgia Power’s RFI, responses to an RFP are likely to be robust and competitive. Also issuing an RFP now will allow Georgia Power to take advantage of the PTC and to get ahead of the increased competition for wind resources that could result from the Clean Power Plan.
“If the Company does issue an RFP, it should ask for both firm and non-firm transmission options from bidders. That will allow the Company to determine which option would create the largest benefits to ratepayers. It’s possible that the best option may be to start with non-firm transmission wind projects and firm up transmission as new transmission resources are built to accommodate the wind power.”
Accion Group writes its own report on the wind RFI
Also filed with the commission on May 26 was a report from Accion Group LLC, which was selected with the approval of the Georgia PSC to serve as the Independent Monitor (IM) for the wind RFI. “From the start Georgia Power recognized there was little incentive for wind developers to, in effect, donate their time to provide Georgia Power with market information,” the report noted. “Accordingly, the IM and [commission] Staff worked closely with GPC to design the RFI so that the firms volunteering information could do so quickly, while still providing relevant information.”
Renewable resources will continue to be a necessary component in the generation mix of utilities, including Georgia Power, Accion said. “While the market continues to seek opportunities, should GPC seek additional wind resources standards should be such that respondents have both a proven record of development, and established siting and firm transmission from the project to the GPC system,” it wrote. “The siting and reliability of wind projects comes with unique challenges, and they need to be incorporated when establishing criteria for bidders and projects. Unlike solar projects, the ability to reasonably forecast output from wind projects is far more speculative, and frequently can only be established after a period of operation.
“We recommend exploring ways to encourage developers to be ‘shovel ready’ when they submit a Response. As this RFI established, existing projects are, for the vast majority, committed. It would, we believe, be appropriate to have the risk of development and performance remain with developers, and not be assumed by ratepayers of Georgia Power. Having firm ‘shovel ready’ standards is one way to avoid shifting the risk of non-performance from the developer to ratepayers.”