The Federal Housing Administration (FHA), part of the executive branch’s Department of Housing and Urban Development (HUD), recently issued guidance on PACE financing programs (read the full press release here). The FHA provides mortgage insurance on loans made by FHA-approved lenders that meet specific qualifications for single family and multifamily homes and hospitals. FHA insurance provides lenders with protection from losses resulting from a property owner defaulting on their mortgage. PACE financing uses voluntary special tax assessments to secure financing for improvements on residential and commercial properties, such as energy or water efficiency improvements or solar panels. PACE assessments are repaid through the property tax bill using the same collection mechanism as other special tax assessments (generally seen as a line item on your property tax bill).
This post follows the release of the first statewide assessment of AB 2188 in the form of a AB 2188 Implementation Report. This assessment provides a snap shot in time of AB 2188 implementation across the state of California based on an assessment of confirmed ordinance and process adoption.
The Energy Policy Initiatives Center (EPIC) developed this report in support of the Center for Sustainable Energy (CSE) under California’s Rooftop Solar Challenge program, called the Golden State Solar Impact program. This program supported the goals of the Department of Energy’s (DOE) Solar Energy Technologies Program and the SunShot Initiative to make solar electricity cost competitive without subsidies by the end of the decade by seeking to address and lower system costs for photovoltaics (PV). EPIC and CSE worked to encourage market transformation through expanding financing options for residential and commercial customers, streamlining permitting processes, and standardizing net metering and interconnection standards across investor-owned and municipally owned utilities in the region under this program. Previous work on AB 2188 included drafting of the AB 2188: Implementation of the Solar Rights Act at the Local Level document and AB 2188 Model Ordinance to implement the amendment to the Solar Rights Act (SRA) and the Governor’s California Solar Permitting Guidebook (Spring 2015 Second Edition). The assessment includes review of ordinance adoption, compliance with minimum statutory requirements under the SRA, and adopted permit application processes. Continue reading
This post will examine the California Independent System Operator’s (CAISO) June 9th, 2016 Proposed Principles for Governance of a Regional ISO. This document builds upon previous whitepapers, testimony, presentations, and comments addressing the governance structure of an expanded regional ISO in the west. It also serves as the focal point for the June 16th, 2016 joint stakeholder meeting between the CAISO and CEC. This post will lay out the proposed principles and examine other relevant regional transmission operator governance structures to inform the reader about the purpose and issues surrounding the proposed CAISO principles for governance. Continue reading
I have written about the importance of electric emissions factors to estimating greenhouse gas emissions in inventories and the impacts of policies to reduce emissions (see here, here, and here). This post discusses the issue of attributing emissions from electricity production to the customers who use it.
We began to think more about this issue during a project to develop a greenhouse gas inventory for an organization that receives its electricity from a direct access provider. We needed the annual average emissions rate (lbs of CO2 equivalent per MWh) of the electricity supply for the year in question. The direct access provider gave us an average emissions rate of 563 lbs CO2e/MWh. This value seemed low to us. It turns out that this value is the emissions rate for electricity included in the US Environmental Protection Agency’s eGrid database for plants located in the California Independent System Operator (CAISO) control area. The justification for using this value was the fact that all electricity is dispatched by the CAISO and there is effectively a large pool of electricity from which electricity is drawn, so the applicable emissions rate for electricity supplied by this provider should be the same.
By analogy, this would be like asking 10 people to put random drops of red, blue, and yellow dye into a pool of clear water and saying that each person contributed the same number and combination of drops. In the end the color of the pool will be the “average” of all the drops entering the pool. But it does not follow that each person entered the same number of drops from the same colors – they each entered a different amount and ratio of colors. Using the average greenhouse gas emissions intensity for an entire pool of electricity – like the CAISO – does not tell us the emissions rate of a particular load serving entity (e.g., utility or direct access provider). For this, it is necessary to determine the contribution of a particular load serving entity to the overall average.
This raised an important question for us: What is the best approach to attribute emissions from electricity production to those who consume it in a utility service territory, city, or specific company?
Recently, Legislative Counsel Dian F. Boyer wrote an opinion answering questions from State Senator Jean Fuller of California’s 16th Senate District regarding California Global Warming Solutions Act of 2006 (commonly known as AB 32) and Executive Branch Authority. The nonbinding opinion answered three questions:
- Does the act authorize the Governor or the ARB to establish a statewide GHG emissions limit that is below the state’s 1990 level of emissions and that would be applicable after 2020?
- Does the act authorize the Governor or the ARB to establish a system of market-based declining annual aggregate emissions limitations [i.e. cap-and -trade] for sources or categories of sources of GHGs that would be applicable after 2020?
- May the ARB increase the fee authorized under [Health and Safety Code] section 38597 in order to achieve a statewide emissions limit that is below the 1990 level and that would be applicable after 2020?
The opinion answers all these questions in the negative examining executive branch constitutional authority under Article V, Section 1 of the California Constitution, statutory construction under the specific language of AB 32 (Health and Safety Code section 38500 et seq.), the doctrine of separation of power under Article III, Section 3 of the California Constitution, and the sparse existing case law on executive orders. This blog post will examine this opinion and the future of GHG regulation in California. Continue reading
Many thanks to Cameron Berhardt for his research assistance for this post.
Although renewable energy credits (RECs) are primarily relevant for entities that must comply with the California Renewable Portfolio Standard (RPS), all types of RECs, whether bundled, unbundled or tradable, may have applications for city usage as well. Similarly, carbon offsets have a role in California’s cap and trade program (though only 8% of a regulated entities’ compliance obligation) but are largely used in the voluntary market. There is no statutory guidance as to the use of RECs and offsets in climate action plans (CAPs). However, a number of cities and counties within California have included the use of RECs and carbon offsets for two main purposes: either as part of procurement of alternative forms of renewable energy, or to directly reduce carbon emissions, or both. Any such use ultimately leads to GHG reduction, the main purpose of a CAP. Continue reading
Supreme Court Issues Hughes v. Talen Marketing Decision With Limited Effect on California and the West
Today, the U.S. Supreme Court issued a very narrow 8-0 decision in Hughes v. Talen Marketing finding that Maryland Public Service Commission’s program for in-state long-term capacity procurement set an interstate wholesale rate that interfered with the Federal Power Act’s (FPA) division of authority between state and federal regulators. The decision is limited to Maryland’s program that conditioned payment of funds for an in-state bilateral capacity contract on wholesale capacity clearing auctions in the PJM wholesale market. The decision does not address the permissibility of other State measures – such as clean energy procurement, tax incentives, land grants, direct subsidies, construction of state-owned generation facilities, or re-regulation of the energy sector – that are untethered to wholesale market participation.
This decision will have limited implications in the California Independent System Operator (CAISO) wholesale market and the west for several reasons.
First, the CAISO wholesale market does not use a comparable capacity auction as PJM. In PJM, a three-year ahead capacity auction is used to ensure that enough capacity exists to serve forecasted demand. PJM forecasts demand three years in advance and then assigns a share of that demand to each participating load serving entity (LSE). The auction accommodates long-term bilateral contracts for capacity to meet this forecasted demand. Owners of capacity to produce electricity in three years bid that capacity into the auction for sale to PJM at rates the sellers set in their bids. PJM accepts bids until it has purchased enough capacity to satisfy demand anticipated demand with all accepted capacity sellers receiving the highest accepted rate, or clearing price (just like the CAISO’s day-ahead market). LSEs then purchase requisite amounts of electricity from PJM to satisfy their assigned share of overall projected demand.
In California, electricity planning is accounted for by three long-term procurement planning processes:
- Long-term forecasts of energy demand produced by the CEC as part of its biennial Integrated Energy Policy Report (IEPR);
- Biennial Long-Term Procurement Plan proceedings (LTPP) conducted by the CPUC; and
- Annual Transmission Planning Process (TPP) performed by the CAISO.
These processes ensure that enough electric and transmission capacity exists to meet forecasted demand with procurement driven by California Public Utility procurement mechanisms as opposed to a wholesale capacity auction.
This also holds true in the west because the CAISO is the only wholesale market. All other balancing authorities remain integrated with individual utilities forecasting demand and procuring supply to meet future need without wholesale markets.
Second, because the west lacks a wholesale capacity auction, it is impossible for a western state to adjust a wholesale rate through bilateral contract regulation to facilitate in-state energy capacity. Maryland sought to develop additional in-state generation that it felt PJM’s capacity auction was failing to encourage. Maryland enacted a regulatory program that allowed LSEs to enter into a 20-year pricing contact (called a contract for differences) with petitioner CPV Maryland, LLC (CPV) at a rate CPV specified in its proposal to the Maryland Public Utilities Commission. CPV then sells its capacity to PJM through the auction instead of transferring the capacity rights to the LSE who would normally sell the capacity into the PJM auction. CPV would then receive the mandated payments from or to the LSE (depending on the clearing price) under the contract terms instead of the clearing price for the capacity sales in PJM. This guaranteed that CPV would receive a specific contracted for price not subject to the wholesale auction clearing price and why the U.S. Supreme Court found that the FPA preempts Maryland’s program because it adjusts a wholesale rate.
Third, the proposed CAISO regional expansion does not include a capacity market and will most likely integrate existing state procurement mechanisms in the same way that California procurement is integrated. This should not create a similar adjustment to wholesale rates because a capacity market will not exist and the power of procurement to meet future demand will remain with the individual states, untethered to a wholesale market.
Fourth, the decision is extremely narrow and only appears to apply to the specific Maryland regulatory program concerning in-state generation in PJM. This means that existing procurement mandates like California’s and Oregon’s 50% RPS programs are not subject to the decision. Additionally, other western state actions will not adjust wholesale rates where there are no wholesale markets.