At the January 17, 2019 Open Meeting, the Public Utility Commission of Texas (Commission) addressed several highly contested issues, including storage, Operating Reserve Demand Curve, Real-Time Co-optimization, and Marginal Losses. First, in Project No. 48023, Rulemaking to Address the Use of Non-Traditional Technologies in Electric Delivery Service (the Battery Project), dealing with utility ownership of battery storage, the Commission decided to defer further action until Texas Legislature’s regular session concludes. This decision comes after 63 comments were filed with the Commission, expressing widely varying views on whether a transmission and distribution utility within ERCOT may legally own and operate battery storage facilities. The Commission previously submitted through its Scope of Competition Report a request for the Legislature to enact legislation clarifying this legal point.
The Public Utility Commission of Texas has finalized the recommendations it will include in its upcoming 2019 Report on the Scope of Competition in Electric Markets in Texas to the 86th Texas Legislature, which goes into session January 8, 2019. The Commission voted on the recommendations at its December 20, 2018 meeting; the most significant inclusions involve a recommendation to increase the threshold for the review of mergers and acquisitions of power generation companies from 1% to 10% of installed generation capacity, and a request that the Legislature provide clarity on which entities may own and operate battery storage devices.
Review of Power Generation Mergers and Acquisitions
Under Texas Utilities Code § 39.158, the Commission is required to review mergers and acquisitions of entities if the newly merged companies will offer for sale more than 1% of the total electricity for sale in the state. The Commission is required to approve the merger or acquisition unless the new company exceeds a 20% installed generation capacity limit set by § 39.154. The Commission recommends increasing the threshold for the review of mergers and acquisitions of power generation companies from 1% of installed generation capacity to 10% of installed generation capacity. The Commission did not recommend changing the limit that prevents one company from owning more than 20% of installed generation capacity. Additionally, the Commission requested the Legislature clarify the meaning of the phrase “total electricity for sale,” which denotes the total regional capacity used in this calculation, and clarifying that the review under § 39.158 applies only in a power region open to customer choice.
The Commission reasoned that the current 1% threshold unnecessarily delays numerous transactions that have a negligible likelihood of breaching the 20% limit, noting the number of applications for review of these mergers and acquisitions has increased from five applications in 2015 to 26 in 2018, most of which came at the end of the year. Changing the threshold for review would avoid undue delays, and in effect avoid the regulatory uncertainty and impediments to business that current regulations cause.
Use of Battery Storage in ERCOT
Under Texas Utilities Code § 35.152, electric energy storage that is intended to be used to sell energy or ancillary services at wholesale are classified as generation assets, and the owner or operator is classified as a power generation company. Section 31.002(10) defines power generation company as a person that generates electricity that is intended to be sold at wholesale, does not own a transmission and distribution facility, and does not have a certificated service area. Section 39.105 states a transmission and distribution utility (TDU) may not sell electricity or otherwise participate in the market for electricity except for the purpose of buying electricity to serve its own needs.
These rules surrounding battery storage have been an issue since AEP Texas, a TDU operating in ERCOT, requested to install two utility-scale batteries to address reliability issues in its distribution system. The docket was dismissed by the Commission on grounds there was insufficient information for a decision to be made; the Commission subsequently opened a Project to further evaluate the possibility of an electric utility owning and operating an energy storage device. The argument made by AEP was that a TDU owning and operating a storage device on its system, that does not intend to sell power at wholesale or participate in the electric market, but only intends to support reliability, does not violate existing rules. Opponents argued TDUs are not able to own and operate storage devices, because they would be participating in the wholesale energy market through the charging and discharging process. The comments received in the Project have highlighted these two arguments, and are sharply contrasting.
The Commission is asking the Legislature for clarity on how these rules apply to battery storage, noting many options exist for TDUs, such as: prohibiting a TDU’s involvement with an energy storage device other than to provide transmission and distribution service to it; allowing a TDU to contract with a power generation company for reliability service from an energy storage device; and limiting a TDU’s ownership and operation of an energy storage device in circumstances where the TDU’s ownership and operation of the device would provide the lowest-cost transmission and distribution service.
The Commission is also requesting that the Legislature provide clarity regarding whether electric cooperatives and municipally owned utilities, known as non opt-in entities, may own or operate batteries without registering as a power generation company. Sections 35.151 and 35.152 of the Texas Utilities Code requires an owner or operator of electric energy storage equipment (i.e. batteries) to register as a power generation company; however, electric cooperatives and municipally owned utilities cannot qualify as a power generation company, therefore it could be inferred they are not permitted to own or operate a battery. The Commission believes this would leave opt-in entities “in a precarious position,” and thus requested legislative guidance.
Registration of Retail Electric Brokers
The Commission is recommending the Legislature require retail electric brokers to register with the Commission in a manner similar to retail electric aggregators to ensure customers who use such brokers have adequate consumer protections. Retail electric brokers connect buyers with sellers of electricity, and many non-residential electric customers use brokers as an alternative to developing in-house expertise to negotiate retail electric contracts. Residential customers also use brokers, authorizing these brokers to make electricity contract decisions on the customer’s behalf. Whether a broker represents the customer or retail seller can vary from deal to deal, risking customer confusion and blurring the parties’ responsibilities. The Commission already regulates many market participants and has customer protection rules in place, including requirements that participants demonstrate industry expertise and financial stability. Electric aggregators perform many of the same functions as retail electric brokers and are required to register with the Commission under Texas Utilities Code § 29.353 of the Texas Utilities Code; the Commission believes brokers should be regulated as well to protect customers.
Electric Industry Security
The Commission is recommending the Legislature establish a collaborative cybersecurity outreach program to ensure the safety and reliability of electric service. The Commission envisions this program including regular meetings with utilities to identify best practices and emerging threats, coordination of workforce training and security exercises, and related research. Members introduced bills addressing these issues during the 2017 legislative session, but none were enacted.
Under Texas Utilities Code § 15.024(d), if a person that the Commission issues a Notice of Violation against does not respond within 20 days, the Commission considers the person to be in default, and § 15.024(f) requires the Executive Director of the Commission to set a hearing at the State Office of Administrative Hearings; after the hearing the violation is decided by the Commission. The Commission recommends § 15.024(f) be amended to remove the hearing requirement to allow default violations to move more quickly.
FERC recently issued a Notice of Proposed Rulemaking (NOPR) that would eliminate the need for electric power sellers with market-based rate authority who sell into certain independent system operator (ISO) and regional transmission organization (RTO) capacity markets to file two screens—the pivotal supplier screen and wholesale market-share screen—with FERC, which would simplify the horizontal market power analysis for sellers in those markets.
This proposed modification of the horizontal market power analysis would apply in any RTO/ISO market with RTO/ISO-administered energy, ancillary services, and capacity markets subject to FERC-approved RTO/ISO monitoring and mitigation. For RTOs and ISOs that do not have an RTO/ISO-administered capacity market, market-based rate sellers would be relieved of the requirement to submit indicative screens if their market-based rate authority is limited to sales of energy and/or ancillary services.
The NOPR, announced at FERC’s December 20, 2018 meeting, is a follow up to FERC’s Order No. 816 NOPR, and is aimed at relieving the filing burden on market-based rate sellers in RTO/ISO markets without compromising FERC’s ability to prevent the potential exercise of market power in those markets. If the NOPR were implemented, indicative screen failures in organized wholesale power markets where the grid operator does not administer a capacity market would no longer be presumed to be adequately addressed by the market monitoring and mitigation in those markets. If a screen failure were to occur, market-based sellers in those markets would be able to submit a delivered-price test or other evidence; sellers could also propose other mitigation or capacity sales. All market-based sellers would still be required to file a vertical market power analysis and an asset appendix which provides comprehensive information relevant to determining a seller’s market power. The appendix would be required to include generators owned or controlled by the seller and its affiliates, long-term firm power purchase agreements, electric transmission assets, and natural gas facilities.
The NOPR would simplify the horizontal market power analysis electric power sellers are required to complete to obtain market-based rate authority. The NOPR would apply to sellers doing business in ISO-NE, MISO, NYISO, and PJM, which all have a capacity market that includes market monitoring and mitigation. Entities in Cal-ISO and SPP would still need to file the screens, because the NOPR would not apply to them given the lack of central capacity market with monitoring and mitigation. Sellers in ERCOT would remain unaffected because the ERCOT market is not subject to FERC’s rules.
The screens this NOPR would eliminate originated in Order No. 816 NOPR, which was issued in 2009, when ISO/RTO capacity markets had just begun operating. The three pivotal supplier test and market share screen (with a 20% threshold) serve as cross checks on each other to determine whether sellers may have market power and whether they should be more closely examined. If a seller passes both screens, a rebuttable presumption the seller did not possess horizontal market power is established. If a seller fails either screen, that failure establishes a rebuttable presumption that the seller has market power; the seller then has a chance to present evidence through a delivered price test analysis or other evidence to show the seller does not have market power, despite the screen failure.
No other market-based rate regulatory reporting requirements would be affected by the proposed order.
Comments on this NOPR are due 45 days after publication in the Federal Register, and may be filed in Docket No. RM19-2-000, Refinements to Horizontal Market Power Analysis for Sellers in Certain Regional Transmission Organization and Independent System Operator Markets.
Husch Blackwell partners with the Texas Renewable Energy Industries Alliance (TREIA) once again to present a five-part webinar series focused on the Texas renewable energy industry. The final installment in the New Directions webinar series will discuss the upcoming 2019 regular session of the Texas Legislature and what’s in store for renewable energy.
Register for the Texas Legislative Preview webinar to be held on Monday, December 17, 2018 at 12:00pm – 1:00pm CST.
If you missed the previous installments of the New Directions webinar series, the recording for each installment can be found here or you can download the podcast.
Potomac Economics, the Independent Market Monitor (IMM) for the ERCOT market, released its “2017 State of the Market Report for the ERCOT Electricity Markets,” which contains several important insights for market participants and offered seven recommendations for market improvements.
Prices and Demand Move Higher in 2017
First, the IMM found that energy prices increased 14.7% over 2016, to $28.25 per MWh. This price is still significantly less than 2011’s average annual price of $52.23 per MWh and even 2014’s average annual price of $40.64 per MWh. The 2017 price increase correlates with a 22% increase in the cost of natural gas, the most widely-used fuel in ERCOT, as fuel costs represent the majority of most suppliers’ marginal production costs. The IMM also found price convergence to be very good in 2017, with the day-ahead and real-time prices both averaging $26 per MWh. However, the absolute difference between day-ahead and real-time prices still increased from $7.44 per MWh in 2016 to $8.60 per MWh in 2017.
Average demand also increased, rising 1.9% from 2016, with demand in the West Zone seeing the largest average load increase at 8.3% (possibly due to oil and natural gas production activity in that zone). Despite this increase in average demand, peak demand in ERCOT reached 69,512 MW on July 28, 2017, which is lower than the ERCOT-wide coincident peak hourly demand record of 71,100 MW, set on August 11, 2016. Even with general price and demand increases, market conditions were rarely tight as real-time prices didn’t exceed $3,000 per MWh and exceeded $1,000 per MWh for just 3.5 hours in all of 2017.
Congestion Costs Skyrocket
Surprisingly, the IMM found congestion in the ERCOT real-time market increased considerably, contributing significantly to price increases in 2017 with total congestion costs equaling $967 million – a 95% increase from 2016. The IMM stated that this increase is due to three main factors: (1) limitations on export capacity from the Panhandle; (2) planned outages associated with the construction of the Houston Import Project; and (3) the aftermath of Hurricane Harvey.
While congestion was more frequent in 2017 than in 2016, congestion on the North to Houston constraint declined after June due to the completion of a new 1,200 MW combined cycle generator located in Houston. The completion of the Houston Import Project in 2018 should reduce congestion in this area even further. Continue Reading ERCOT’s State of the Market Report
It appears the Texas Legislature has taken note of the several news articles and industry insiders sounding the alarm bells for ratepayers to brace for record high electricity prices this summer in a market applauded for its consistently low prices. The Committee convened because the Lt. Governor charged it to study/respond to the reserve margin issue. Approximately 5,600 megawatts (MW) of electric generation have recently retired in Texas causing a concern over whether enough reserve capacity exits to avoid rolling blackouts during the peak summer heat. On May 1, 2018, the Texas Senate Committee on Business and Commerce (Committee) held a meeting to discuss concerns amongst the Senators whether the Electric Reliability Council of Texas (ERCOT) had all of the tools necessary to address the lower reserve margins. The speculation over what might occur this summer began with ERCOT’s Winter Capacity Demand Report estimated the reserve margins in ERCOT as 9.3% for the summer.
During the hearing, both the Public Utility Commission of Texas (PUCT) Chairman Walker and ERCOT representatives promoted ERCOT’s preparation for the summer and insisted ERCOT had all of the tools necessary to respond to system shortages. PUCT Chairman Walker specifically pointed to ERCOT’s demand response tool, where large customers come offline at times of high system demand. In addition the low reserve margin reported at 9.3% a few months ago resulted in 525MW of generation coming back online. The current reserve margin going into summer is now approximately 11%. ERCOT stated that most of the megawatts coming back online were from mothballed units and that it is likely the possibility of higher prices this summer has made these units economical to run, and can be viewed as an indication the market is functioning as expected.
While the primary concern of the Committee was the potential for record high electricity prices, the Committee also discussed capacity markets more generally and what has changed in the market since the last time the topic of a capacity market was brought up in the Texas Legislature. To respond, PUCT Chairman Walker emphasized her strong belief in the ERCOT market and any changes regarding price fluctuations are merely a result of the cyclical nature of the market. Chairman Walker pointed to the high prices and low capacity experienced by the market in 2005 and 2006 that encouraged more generation investment was made as a response to these price signals. PUCT Chairman Walker also reiterated her support of the energy only market and her belief that it will work this summer.
The Committee also spent time discussed the impacts of the Federal Production Tax Credit (PTC) on the ERCOT system, the transparency of the prices in the Texas Government Land Office (GLO) contracts, and presentations from Austin Energy and CPS Energy on successes and failures for both of these municipally owned utilities. From the broad discussions taking place at the meeting it is safe to assume the Texas Legislature will be watching the ERCOT market this summer and energy is likely to be a topic of debate in the coming legislative session.
The Texas Commission on Environmental Quality (TCEQ) is in the process of renewing its General Permit to Discharge under the Texas Pollutant Discharge Elimination System Permit, Permit No. TXR150000, issued on February 19, 2013 and effective on March 5, 2013, which authorizes discharges from construction sites into surface water in the state. The new permit will go into effect March 5, 2018 and will expire five years from the effective date.
Developers and other parties that currently hold an authorization to discharge stormwater under the existing permit will want to take note of the provisions in the new permit for obtaining renewed authorization to discharge; for large construction activities: Continue Reading Texas Developers, Mark Your Calendars for March: Changes Coming for Texas Stormwater Permit
On October 25, 2017, Commissioner Keith Anderson of the Texas Public Utility Commission (PUCT) released a memo regarding the draft Preliminary Order in which he expresses concerns over the application submitted by Sempra Energy to purchase Oncor Electric Delivery (the state’s largest utility) for $9.45 billion. The memo, which results from Commissioner Anderson’s continued concern regarding the financing of the deal, requested that the Commission add to their preliminary order in order to require Sempra to clarify several issues during the hearing on the merits.
In the memo, Commissioner Anderson states Continue Reading Texas Regulators Seek Additional Clarification on Sempra/Oncor Deal
On September 1, 2017, after two years of extensive studies conducted by multiple stakeholders, Lubbock Power & Light (“LP&L”) submitted its formal application to the Public Utility Commission of Texas (“PUCT”) requesting to leave the Southwest Power Pool (“SPP”) and join the Electric Reliability Council of Texas (“ERCOT”). Because the City of Lubbock is one of the largest municipalities ever to leave another power region and attempt to join ERCOT, the transition has been an important topic in Texas since its introduction in 2015. Continue Reading LP&L Files Formal Application to Join ERCOT
As you are all aware, hurricane Harvey had a major impact on Texas and has left many residents without power. On August 28th, in order to facilitate the monitoring of the effects of the hurricane, the PUCT opened PUC Project 47552 – Issues Related to the Disaster Resulting From Hurricane Harvey. At today’s open meeting, PUC commissioners discussed this project as well as impacts the hurricane has had on central and southeast Texas. During this discussion, Commissioner Anderson noted that he would like more detailed information from every entity affected by the hurricane. Because of this statement, we urge you to maintain detailed information as to how the hurricane might have affected you and your provision of service. Also, be prepared to answer questions from the commission and possibly ERCOT/TRE detailing any storm related damages or outages as well as how you have handled any damages.