Op-Ed: El Paso Electric’s Newman 6 chosen over Lower Cost Renewable Energy Mix

On November 16th, a Recommended Decision to deny the Newman 6 methane gas turbine was submitted by Hearing Examiner Elizabeth Hurst in the New Mexico Public Regulation Commission (NMPRC) case regarding the potential capacity addition.

This document and multiple testimonies from intervenors highlighted that EPE chose a more expensive mix of energy resources, which included Newman 6, rather than a portfolio with less methane gas capacity, and a larger share of solar, wind, and battery storage capacity. The 2017- 2018 planning process did not take into account the more recent 2019 New Mexico Renewable Energy Transition Act requirements.

The NMPRC Commissioners will vote and submit a Final Decision at some point between now and December 18 to approve or deny Newman 6.

On November 17th, the public health, environmental justice, and climate change concerns regarding Newman 6 were addressed at an online meeting of the Texas Commission on Environmental Quality (TCEQ). More than 100 residents of El Paso and Chaparral spoke and
submitted written comments, with many asking for a greater level of transparency in the selection of the resources for EPE, and the following intends to shed light on this process.

The Newman 6 gas facility was initially selected by EPE in the utility’s Integrated Resource Plan (IRP) submitted to the NMPRC in 2018. During the creation of an IRP, a utility makes a request for proposals (RFP) for more production capacity due to the utility’s projected future capacity requirements.

In the case of EPE, the utility projected the need for 370 MW of additional capacity by 2023 due to increases in system-wide demand for electricity, and the need to retire three aging methane gas facilities. These turbines, Rio Grande 7, Newman 1, and Newman 2, have a combined capacity of 198 MW and were built in 1957, 1690, and 1963 respectively.

The 2017 RFP resulted in 81 bids from 37 companies including bids for solar, wind, battery, methane gas combustion, and others. These proposals, with varying resource types, sizes, and prices, were then modelled by consulting firm E3, hired by the utility, to determine the low-cost portfolios.

During the course of evaluating the proposed mix of electricity generation types, EPE opted to choose a higher cost mix with less renewable energy capacity.

The ideal low-cost portfolio produced using RESOLVE modelling software included 103 MW solar, 200 MW solar coupled with 100 MW battery storage, a standalone 54 MW battery, 150 MW wind, and a 160 MW gas combustion turbine (CT). This “RESOLVE Select” scenario was considered hypothetical by EPE because the RFP did not produce a bid for a 160 MW methane gas combustion turbine.

Using the RESOLVE Select scenario as a guide, four portfolios with the actual RFP bids were then compared using net present value (NPV), which is a way to value future assets in today’s dollars, or in this case 2018 dollars.

Within the range of estimates received through the RFP, EPE opted to pass on the lowest cost portfolio, “Scenario 3,” that was $8 million dollars less in terms of NPV than the portfolio, “Scenario 1,” that included the 228 MW Newman methane gas turbine.

Scenario 3 proposed a new build 49 MW methane gas turbine addition and a life extension of the aging 76 MW Newman 1 gas turbine rather than the 228 MW Newman 6. This portfolio also featured 348 MW solar and 150 MW wind capacity, when by comparison the EPE bundle proposed to the NMPRC had 200 MW solar and no wind capacity.

EPE’s self-imposed assumptions and caps on renewable energy led the utility to select a higher cost bundle of resources with 148 MW less solar, 150 MW less wind (in fact no wind), less battery storage, and 179 MW more new methane gas capacity.

Graphic by Nate Huseby.

Additionally, Newman 6 is a self-built facility, meaning essentially EPE is hiring itself to construct the turbine addition. Unfortunately for ratepayers, no competing bid for a methane gas turbine in this size was submitted. The in-house estimate from EPE’s Power Generation Team was given an “exclusive invitation to submit a late bid option for Newman 6 after the bid deadline,” according to case documents.

The 160 MW methane gas addition, produced using the RESOLVE modelling software, was considered hypothetical, yet EPE had constructed the Montana 3 and 4 turbines in 2016, with a capacity of 88 MW each, for a total of 176 MW. The 49 MW new methane gas turbine plus life extension of Newman 1 option, or Scenario 3, was disregarded due to EPE’s self-imposed restrictions on renewable energy capacity additions.

When EPE plans for these additions its aim is to meet a projected summer peak demand event when air conditioning use and electricity demand are highest. The utility then allocates a percentage that a given energy source can be relied upon during a summer peak event.

Battery, nuclear, and methane gas capacity are considered “firm resources” meaning that the full capacity is assumed to be available during a peak demand summer event so they received a 100% peak “capacity factor.” The variable resources, such as solar and wind, are given a capacity factor based upon the statistical availability of the resources during a peak event and the subjective decision-making of the utility.

Prior to the 2018 IRP, EPE had given its existing solar resources a 70% capacity factor, meaning that EPE felt that 70% of its 115 MW of solar, or roughly 81 MW, could be relied upon in a peak event. This assumption makes sense, peak events happen on hot summer days when A/C demand is high, the sun is shining, and solar production is high, but a utility must also plan for cloudy summer days, so solar was not given a 100% capacity factor.

Surprisingly, the solar capacity to be added in the EPE-selected 2018 IRP portfolio, 200 MW, was only given a capacity factor of 25%, rather than the previously used 70%. The utility justified this dramatic drop because variable resources, such as solar or wind, can be relied upon less to meet peak as more renewables are integrated.

This is a concern at much higher levels of solar and wind penetration, but EPE currently has less than 3% renewables in its portfolio.

Further, 40% of EPE’s electricity comes from the Palo Verde nuclear facility. This baseload capacity reduces the need for drastic reductions in the capacity factor for solar, especially at this low penetration level. To cut the capacity factors this low is at best a very conservative estimate of solar availability, and at worst, a skewing of data to promote a methane gas capacity addition.

If EPE was making a conservative estimate for all of its resources, it should have also given a lower capacity factor for its methane gas capacity due to the statistical possibility for shutdowns or malfunction during peak events. The Newman 4 and 5 turbines were down during the peak summer season in 2016, yet still given a 100% capacity factor for peak.

Even with this low and conservative capacity factor, EPE further constrained the addition of solar capacity by imposing 300 MW total limit on solar additions and a 100 MW limit per facility though EPE had received bids for world record low priced solar farms at 1.5 cents per kWh.

EPE justified the cap claiming that additional solar additions past 400 MW total (including 115 MW existing solar capacity) would create a new evening daily peak when solar production drops off dramatically at sundown. This is true, but the 300 MW cap was not necessary given the already conservative 25% capacity factor attributed to solar.

EPE’s own witness from E3 testified that the capacity factor reduction for solar to 25% should not be applied until after EPE surpassed this 400 MW solar benchmark.

The Scenario 3 portfolio included 150 MW wind capacity, but EPE gave wind a 0-10% capacity factor because EPE claimed these facilities could not be relied upon to meet a summer peak event. The models for wind did justify a low capacity factor for wind during the summer peak, but not zero.

E3 estimated 26 MW of wind could be devoted to EPE’s peak, a 17% capacity factor. Wind generally produces electricity late at night and could be used to charge batteries for use during a peak event, or to reduce methane gas combustion at night.

In closing, the Newman 6 methane gas capacity addition was justified due to EPE’s self-imposed and conservative assumptions regarding the effectiveness of renewable energy to meet peak summer demand. Solar was given an unreasonably low capacity factor and its total capacity was capped.

Wind showed a lower reliability to meeting a peak hour than solar, but its additional benefits were minimized, and the 150 MW of wind was disregarded.

The 228 MW Newman 6 turbine, justified by debatable self-imposed EPE assumptions, did not receive any competing bids. The lack of competitive bids for Newman 6 casts a shadow on the whole approval process.

EPE made a $157M decision on Newman 6 without competition. The turbine will be paid for by ratepayers but owned by EPE and its parent company JP Morgan-affiliate Infrastructure Investment Fund 2.

EPE is currently working through the process of its 2020-2021 IRP for capacity additions past 2023 and EPE ratepayers should have a larger influence on how EPE selects its resources.

The New Mexico Energy Transition Act has guided EPE in a sustainable renewable direction for the one-fifth of ratepayers in New Mexico, but the remaining 80% of EPE’s electricity generation for Texas still requires a path toward increased renewable power generation.

In 2017-2018, Newman 6 was chosen over a lower cost portfolio that would result in less air pollution, less carbon emissions, and less Permian fracking.

El Paso cannot let its utility make the same mistake twice.

Author: Ryan Brown

Ryan is an independent energy and climate policy consultant and project manager who is an intervenor in NMPRC proceedings regarding the Newman 6 capacity addition. He has previously worked with the UN Economic Commission for Europe Sustainable Energy Division and the EU Energy Community, He is graduate of the Jackson School of Geosciences at The University of Texas at Austin.


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