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How California’s Gas Future is Shaping Up

April 26, 2018 | Kevin Adler & Barry Cassell

The state of California, once a prime location for greenfield and brownfield gas-fired power plant development, has lately become somewhat unfriendly to new gas-fired power as it pursues aggressive greenhouse-gas reduction and renewable energy goals.

Regulators there have been lately rejecting gas projects that they had once encouraged, and they have been promoting alternatives like battery storage, demand response, renewables and energy efficiency.

In this issue of Get the Point, we look at the current state of gas-fired power projects in California and how legislation and regulation are affecting the future outlook.

The future is flat

In 2017, natural gas deliveries to California end users averaged about 5.8 billion cubic feet per day (Bcf/d), of which about 1.85 Bcf/d (32%) flowed to power plants for electricity generation.

In February 2018, the California Energy Commission (CEC) issued its final report on the state’s energy trends for 2018-2028, forecasting that the state’s total natural gas demand will grow an average of 0.55% per year during the next decade. That’s a small enough gain. But due to renewables and the state’s ongoing emphasis on energy efficiency, California’s natural gas demand just in the electric generation sector is expected to decline by about 2.5% by 2028 (cumulative, not per-year basis).

At the most basic level, the power industry in California knows that it is being pushed to procure power from renewable sources more rapidly than almost any other part of the country.

Gov. Jerry Brown (D) signed the state’s Renewable Portfolio Standard in 2015 that requires retail sellers and publicly-owned utilities to procure 50% of their electricity from eligible renewable energy resources by 2030. Brown in 2015 also issued an executive order to establish a greenhouse gas reduction target of 40% below 1990 levels by 2030.

The impact of the RPS for California can be seen in the graph below (blue is gas and other non-renewable power sources; green is renewable power).

Source: California Energy Commission

Coal-fired power is all but absent in the state, with its only source being imported power produced by the Intermountain Power Plant in Utah. To indicate how much California wants to disincentivize the use of coal power, a fee of $15 per megawatt/hour (MWh) is levied on all coal-fired power that California utilities purchase.

The bottom line is that the existing gas-fired generation will operate “less frequently and at lower load factors,” said CEC. Despite a temporary rebound in gas demand in 2024-2026 that is linked to the anticipated retirement of the Utah Intermountain Power Plant coal plant (which is set to be replaced by a 1,200 MW gas-fired unit at the same site), the trend is clear (see graph). 


As power producers and utilities look at the trends, they must consider the timing of their investments. A gas-fired plant usually needs at least 30 years of operation to gain a return on the original construction investment. But if an electric utility is only offering, say, a 10-year power purchase agreement (PPA), and carbon constraints are only due to get tougher over time, where is the incentive right now to build a plant with a 30+-year lifespan? Much or all of that last 20 years will be in the post-2030 period, after the renewable energy and greenhouse-gas reduction targets are fully in force.

On top of those issues, California has enacted a once-through-cooling (OTC) policy, which mandates shutdowns, repowerings and/or retrofits of a series of power plants along the Pacific Coast. For each gas power plant in the state, the owner/operator must weigh the cost of complying with OTC with the anticipated revenue from providing power.

The California ISO (CAISO), which oversees the state’s energy grid and coordinates its operations with the Western Interconnection Power Grid, considered the impact of the OTC in its final "2018-2019 Transmission Planning Process Unified Planning Assumptions and Study Plan," which was published on March 30. CAISO wrote that various gas-fired plants covered by the OTC rule, like the 629-MW Pittsburg plant of GenOn Energy, have already been retired (in 2016). That same challenging cost structure led GenOn on Feb. 6 of this year to retire the 430-MW Mandalay plant, well ahead of a 2020 OTC compliance deadline. Indicative of the trend in the state, utility Southern California Edison (SCE) has said it will replace the power provided by the Mandalay plant with renewable energy and energy storage options. More is coming, GenOn’s Ormond Beach plant, 1,516 MW, will be retired as of Oct. 1 of this year with no on-site replacement capacity.

Another stealth issue for California gas-fired power is the growth of something called community choice aggregators (CCAs) in the state. These are organizations, usually sponsored by local governments, that gather together ratepayers that in many cases had been served by one of the big investor-owned utilities, then contract directly for power, pretty much always from a solar project. This means that the big investor-owned utilities – SCE, Pacific Gas & Electric (PG&E) and San Diego Gas & Electric (SDG&E) – are increasingly reluctant to sign long-term PPAs with gas-fired power developers, especially for large power projects, since their customer base is rapidly being eroded by the CCAs.

California power demand today

OPIS PointLogic tracks daily data on gas offtake by 31 power plants in the state, which gives a window into much of the current gas demand for the power sector.

The graph below shows the gas for power that is tracked for each pipeline (bars), as well as both the OPIS PointLogic and U.S. Energy Information Administration’s modeled total gas demand by the power sector (lines). The summer surge in power demand for air conditioning purposes is very apparent.


Given the headwinds described above, it wouldn’t be surprising if power providers cut back on their planned investments in expanded or new gas power to the state. Indeed, there has been some negative news lately, but some positive news as well. The new projects might incorporate features friendly towards renewables (such as storage) that could keep them viable even as the state moves towards its low-carbon goals.

The following is a summary of key project-related developments tracked by OPIS PointLogic since the start of 2018, identified as those that indicate cutbacks or cancellations of gas projects and those that indicate projects that might go forward.


  • The Los Angeles Department of Water and Power (LADWP), while it reviews the prospects for going to 100% renewables by around 2050, has frozen plans for further repowerings of three aging gas-fired power plants -- Scattergood, Haynes and Harbor. LADWP had in recent years done two partial repowering projects at Haynes and Scattergood, to meet OTC rule requirements.
  • Calpine Corp.'s Mission Rock Energy Center LLC has asked the CEC to suspend a review for a 275-MW, gas-fired peaking project. "The Mission Rock Energy Center is intended to address the local reliability needs in the Moorpark Subarea of the Big Creek/Ventura local reliability area," the company wrote in the March 9 suspension request. "It is a modern, efficient, flexible and unique project, combining gas-fired generation peaking capacity with battery energy storage, voltage support, and black start capabilities. However, since the Mission Rock Energy Center was proposed, California policies and programs relating to grid reliability—particularly local reliability and procurement— have been in transition." As proposed, the Mission Rock combustion turbines would be co-located with battery units that could deliver an additional 25 MW/100MWh (25 MW for a period of four hours).
  • AltaGas Pomona Energy told the Energy Commission in March that it is terminating a proceeding for a 100-MW, gas-fired repower project. In June 2017, the Commission had suspended its review of this project, at the request of AltaGas. This was to be a simple-cycle facility to replace the existing San Gabriel facility in Pomona. The March 21 letter terminating the application didn't offer details on why the project was ended, but the May 2017 application for the review suspension said that SCE was interested in making the Pomona project site into an energy storage facility. (This plan is related to SCE's need to improve electrical reliability in the wake of the temporary closure of the Aliso Canyon gas storage facility after its major leak in October 2015—another challenge to the gas industry in the state.)
  • PG&E told the California ISO in March 14 comments that the organization needs to plan for the possible retirement of gas-fired capacity in northern California by in part developing new power transmission pathways into the region. "PG&E supports the CAISO’s effort for a review of existing local capacity areas in the 2018-2019 planning cycle to identify potential transmission upgrades that would economically lower gas-fired generation capacity requirements in the local capacity areas or sub-areas," said the utility.
  • NRG Energy said in March that it plans to retire over the course of the next year three gas-fired plants in California for economic reasons, including Ormond Beach. The 640-MW NRG Etiwanda Generating Station in Rancho Cucamonga, dating back to 1962, will be retired as of June 1. And the 54-MW NRG Ellwood Generating Station in Goleta will close on Jan. 1 of next year. All three plants are part of GenOn, which is being split off from NRG through a GenOn bankruptcy proceeding. In the case of Ellwood, SCE’s proposed PPA that would allow NRG to refurbish the aging station was denied by the CPUC in October 2017. "[We] reject the 54 megawatts, 10-year gas-fired generation, 30-year refurbishment Ellwood contract and 0.5 MW, energy storage contract (linked to the Ellwood contract) to give the Commission an opportunity to explore a more complete portfolio of resources to meet any identified need in the Santa Barbara/Goleta area," said the CPUC order.
  • In Feb. 22 comments, NRG Energy criticized the CAISO for a recent flip-flop on a transmission line project that has endangered the future of NRG's 262-MW, gas-fired Puente peaking project. NRG said that CAISO had previously rejected the Pardee-Moorpark 230 kV line 4 transmission project, and encouraged the construction of Puente to fill the local reliability need. Now, the agency is moving in the other direction.
  • Calpine Corp. has two gas-fired power plants in California that it has shut pending a review of the future of each plant, said the company in its Feb. 16 annual Form 10-K report. The two are: Wolfskill Energy Center, simple-cycle, 48 MW (net) peaking only; and King City Peaking Energy Center, simple-cycle, 44 MW (net) peaking only. These plants ran out of contracted sales at the end of 2017 and were unable to get reliability must-run deals that would have kept them running in 2018 to provide local transmission grid support.


However, some good news can be found in the last few months for gas-fired power in California.

  • First, a settlement judge at FERC on March 27 approved deals between subsidiaries of Calpine Corp. and CAISO related to reliability must-run (RMR) agreements covering three gas-fired power plants in Northern California. Calpine needed RMR deals for these plants in calendar 2018 due to a lack of power sales agreements, and CAISO needs the plants operating, at least for now, for transmission system reliability. The plants are: Yuba City and Feather River, each 47-MW plants owned by Calpine’s Gilroy Energy Center LLC. The third is Calpine’s Metcalf Energy Center, a 600-MW, combined-cycle facility in San Jose. The new deals allow the three plants to provide RMR service in calendar 2018, with options beyond that on a year-to-year basis.
  • SCE on April 4 filed with FERC a Large Generator Interconnection Agreement for the 700-MW, gas-fired, combined-cycle Palmdale Energy Project. The other party to the agreement is CAISO. The project's targeted commercial operation date under this agreement is April 1, 2022.
  • CEC is taking comment until April 30 on a Preliminary Staff Assessment covering the 98-MW gas turbine/battery project of Stanton Energy Reliability Center LLC. This is another example of a battery add-on to a gas project in California. The project would consist of two Hybrid EGT General Electric LM6000-based gas turbines. The EGT combines a combustion gas turbine with an integrated battery storage component operated by a proprietary software system and a clutch on each turbine/generator to allow operation as a synchronous condenser.


Summing up, it’s clear that California’s utilities are adjusting to the new reality that is arriving quickly. They are closing their least efficient gas-fired plants that can’t be cost-effectively upgraded to meet the OTC rule, and they are investing in renewable generation and storage. But at the same time, gas-fired power is hardly going away in the state, and gas for direct heating and industrial purposes also remains a substantial demand source.

OPIS PointLogic will continue to track the plans for expansion and closure of gas-fired power in California, as well as the pipelines and storage facilities to serve them.