Energy Procurement Insights for April 2019: See What's Driving Prices in Your Region

Energy markets are complex, and it can be difficult to find useful information to inform the energy procurement strategy for your organization. What you need is detailed information on the factors driving prices in the region where your facilities are located.

Every month, Enel X's Energy Intelligence team develops in-depth reports on activity in individual energy markets. Here you can read the highlights for this month and access the full report for each region. Just click on one of the tabs above to jump directly to a specific region.

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New England
New England Solar Capacity Expected to More than Double Over Next Decade

On March 14, ISO New England (ISO-NE) released its finalized forecast for solar power capacity growth through 2028. The region is expected to bring on 463 MW in 2019, and 3,860 MW in total solar nameplate capacity over the next decade. The 143% increase over current capacity of 2,883 MW is primarily attributed to new installments in Massachusetts and Connecticut, as the two states are slated to hold 80% of the total solar market in New England. There is significant expected expansion in Rhode Island, which is projected to see year-over-year growth of 51.3 MW (44%) in 2019 and reach 564 MW of total solar nameplate capacity by 2028, almost 4 times the amount the capacity it held at the end of 2018. While growth estimates have increased from 2018’s forecast, the report indicates that expansion will begin to slow and total solar capacity will likely plateau within the next three years. While Massachusetts is currently the most mature solar market in the region and entering its 10th year of offering generous incentives to solar developers (SREC I/II & SMART), the regulatory outlook indicates that incentives for large-scale solar developments will decline over time, concentrating the majority of growth in the start of the decade.

Estimates for solar development in the region have increased in each year since ISO-NE first began releasing the annual report in 2014. In its 2016 report, the organization projected 3,272 MW of solar nameplate capacity to be incorporated into the grid by 2025, an addition of almost 2,000 MW. The latest report increased 2025 total capacity estimates to 5,843 MW, and expects more than 3,000 MW to be added in the next 6 years. Solar production in the region has continued to outperform forecasts by the regulatory authority, with 2018 realized solar capacity surpassing 2016 projections by almost 600 MW, 25%. If historical performance is any indicator, solar development may continue to outpace estimates over the next decade.

Although all forms of solar capacity are expected to show growth over the next 10 years, the largest segment continues to be behind-the-meter (BTM). Grid facing, Energy-Only Resources (EOR), and Forward Capacity Market (FCM) resources will make up the remainder of the additions. Since solar is an intermittent resource, it is limited in the amount of capacity obligation it can take on, especially under ISO-NE’s pay-for-performance regime, which requires generators with capacity obligations to generate power under scarcity conditions. However, the 2,362 MW of BTM solar could reduce summer peak demand by over 1,000 MW by 2028, which will decrease capacity requirements, eventually putting downward pressure on capacity prices. Since growth in solar is expected to be funded primarily by ratepayers in MA and CT, those customers will pay more on balance in the near term, either through increased RPS compliance costs or through distribution charges, like those aimed at funding the MA SMART program.

For further updates on the power and natural gas markets, read our full report for this month.

New York
NYISO 2019 Summer Capacity Auction Results Mixed

On April 2, the New York Independent System Operator (NYISO) released the results from its summer 2019 capacity Strip Auction, which covers the commitment period from May 1, 2019, through October 31, 2019. Capacity prices for New York City (Zone J) increased 26% year-over-year to reach a four-year high of $13.10/kW-month. In comparison, prices for the Lower Hudson Valley (Zones G-I) and Rest-of-State (Zones A-F) fell by 55% and 26%, respectively, to reach six-year lows for the two regions.

The NYISO runs two strip capacity auctions a year: one for the summer and one for the winter. In addition, monthly and spot auctions are held each month to allow load serving entities (LSEs), such as utilities or third-party suppliers, to procure capacity on behalf of their customers that did not clear in the seasonal strip auctions. While most of the state’s capacity is procured during the spot auction as well as bilaterally, the strip auctions are influential on forward capacity swap prices.

For customers who have not previously locked in their capacity obligation through a third-party supplier for the summer term, the year-over-year price changes will be realized on their bills starting in May through October 2019, whether through utility default service, a third-party capacity pass-through, or a freshly quoted fixed price. The impact to customers will depend on their installed capacity tag (ICAP), which is determined by their load during the New York system peak hour (for the upcoming capability year starting in May, preliminary estimates forecast that 8/29/2018 hour beginning 4:00 PM ET will be the system peak hour). On an annual average, capacity costs have represented roughly 15% to 20% of New York City supply costs, with that figure dropping precipitously further Upstate. Forward capacity prices by zone are indicating a slight erosion of the status quo, as capacity prices are increasing in Lower Hudson Valley (Zones G, H, & I) in the next few years, while they decrease in Zone J.

For further updates on the power and natural gas markets, read our full report for this month.

Mid-Atlantic
PJM 2022/2023 Base Residual Auction Still Faces Delays

FERC’s ruling that PJM’s Minimum Offer Price Rule (MOPR) is unjust and unreasonable has already led PJM to postpone the 2022/2023 Base Residual Auction (BRA) from its traditional May schedule to August 2019.  Complicating matters, FERC has not approved new rules for this key component of the auction process.

The uncertainty around this particular auction could affect suppliers’ ability to price deals that run past June 2022.  Shorter-term deals or deals with capacity pass-thru clauses covering any months June 2022 and beyond may be necessary, and buyers should incorporate these products into future purchasing strategies as appropriate. This delay will also make it more difficult to project ROI for DER projects like solar and batteries with unknown capacity impacts past June 2022. 

At PJM’s March 21 meeting, PJM discussed four potential options as to how to handle the next BRA:

  1. Proceed with the August BRA knowing it is possible a FERC order will require PJM to re-run the auction
  2. File a waiver to further delay the auction
  3. Request FERC to confirm that PJM should run an auction under the current Tariff, or
  4. File an alternative rate that FERC could approve or use to delay the auction until May 2020

Stakeholders at the meeting stated that they would prefer a further delay in the BRA to the potential of running the auction more than once. At this time, FERC has still left PJM in limbo as to how it can or should proceed.

For further updates on the power and natural gas markets, read our full report for this month.

Midwest
Illinois Continues Move to 100% Renewable Energy

In a March 26 house committee hearing, Illinois continued its move toward 100% renewable energy by advancing the Clean Energy Jobs Act (SB2132/HB3624). This bill builds upon the Future Energy Jobs Act passed in 2016 to fill in gaps identified over the last few years.

A summary of the bill is below:

  • Expands clean energy entrepreneurship act to reduce emissions, promote renewable energy sources, improve energy efficiency, and reduce carbon pollution related to transportation
  • Provides for the creation of a clean jobs curriculum to increase workforce skills
  • Provides promotion of opportunities for small and disadvantaged businesses in clean energy development
  • Establishes framework to achieve 100% reliance on renewable energy
  • Amends EV act, the IPA Act, School code, the public utilities act, and the Environmental Protections Act

HB 3624 aims to further cut carbon emissions, create more clean energy jobs, and remove Northern Illinois from the PJM capacity market, thereby putting capacity procurement in the hands of the state. It would increase the renewable portfolio standard (RPS) percentages to 45% by 2030 and 100% by 2050. This requirement is up significantly from the original goal of 25% by 2025. Typically, end users will see a cost increase in markets that raise RPS percentages; however, changes in the RPS should not affect customers’ supply bills, as those charges are covered by the distribution side of the bill.

In order to create more renewable energy jobs for local workers, HB 3624 would create tax incentives as well as low-cost lending programs to help businesses transition to a renewable focus. Furthermore, there will be an emphasis to procure renewable energy credits for RPS standards from projects operated within the state, which would be a catalyst for more development of renewable projects in Illinois.

The final aspect of HB 3624 is to move the responsibility of procuring capacity from PJM to the Illinois Commerce Commission and Illinois Power Agency. Advocates say this move would allow the state to grow its renewable energy supply while keeping costs low. The thought process behind this is that, rather than being at the mercy of PJM’s capacity auctions—in which PJM procures more capacity than is typically needed (reserve margin)—Illinois could purchase only enough capacity needed for the state. So while pricing per MW may be higher, the overall amount of capacity procured will be lower, ultimately leading to lower energy costs.

However, this proposal doesn’t come without opposition. In a March 26 Herald & Review news article, David Kraft, director of the Nuclear Energy Information Service, an anti-nuclear power environmental organization, said the bill “disguises another bailout” for uneconomic nuclear reactors in “the language of a pseudo-market based capacity reform.”

Customers should take note of the lofty goals that the state is imposing on the wholesale electric industry. While promoting renewable energy, stimulating green job growth, and cutting emissions are responsible moves, removing Northern Illinois from the PJM capacity market would equate to re-regulation of the wholesale power industry. Although re-regulation could potentially be less costly to consumers initially, there is risk of higher future costs due to less efficient capacity procurement in future periods.

For further updates on the power and natural gas markets, read our full report for this month.

Texas
AEP Seeking Approval of Additional $4M from PUCT

Retail customers served under the American Electric Power (AEP) Texas central region should anticipate an increase in the supply portion of their energy bills as AEP seeks approval of additional $4M to meet the costs to reconstruct transmission and distribution following a major event, like Hurricane Harvey. AEP, a utility in central and north division of Texas, filed an application with the Public Utility Commission of Texas (PUCT) seeking approval to secure $229M in distribution-related costs. The application was filed after the PUCT approved $225M to restore distribution services.

In its earlier filings, AEP Texas submitted a request with FERC seeking approval of $415M as a reasonable and necessary cost to restore the transmission and distribution system following Hurricane Harvey and other weather events. The $225M will go toward carrying costs, insurance proceeds, and tax offsets. When the qualified costs of issuing, servicing, and administering the securitization bond issuance and repayment are considered, the total amount estimated is $229M, $4M higher than the approved costs.

If approved as requested, AEP Texas estimates that the amount charged to Retail Electric Providers would be $1.33 for every 1000 kWh that their customers use over a 10- to 15-year period. This claim will only impact customers in the AEP Texas central division territory, which has 240 miles of coastal exposure, as depicted in the graphic to the right. The central division territory covers regions along the Gulf coast, south to the Rio Grande valley, along the border with Mexico and westward through Laredo to Eagle Pass and Del Rio.

If approved, customers in the AEP Texas central region should expect an increase of $0.0013/kWh to $0.00133/kWh on the supply side of their bills going forward.

For further updates on the power and natural gas markets, read our full report for this month.

California
Solar Sets Record Generation and Curtailments in Q1 2019

March 2019 brought two record-setting days for renewable energy within the CAISO footprint. On March 16, California front-of-the-meter (FTM) solar generation peaked at 10,765 MW—a level not reached since generation peaked at 10,740 MW in June 2018. One week later, on March 25, FTM solar set another all-time record at 10,818 MW.

Record generation days typically occur early in the summer when daylight hours are the longest, so their occurrence during the shoulder season this year comes as a surprise.

California continues to forge its way towards the state target of meeting 33% of retail sales with renewable energy resources (solar, wind, geothermal, biomass, and <30 MW hydroelectric) by 2020. According to a report updated earlier this year by the California Energy Commission, 34% of all retail sales in 2018 were already met by renewables. The next target comes in 2030, when the state mandates that 60% of all retail electricity sales come from renewable energy; this would require an average annual increase of 3% per year.

Currently, FTM solar capacity dominates the renewables market in California, comprising 36%, or 11,117 MW, of all renewable capacity in the state. In addition, behind-the-meter (BTM) solar installations account for 26% of all renewable capacity. Since the record-setting June 2018 peak, approximately 600 MW of solar capacity has been added, with more than 3,500 MW planned to come online before the end of 2019. While the increased solar capacity does not guarantee record production will continue to grow, it increases the probability that it will occur. Solar production is highly weather-dependent, with particular sensitivity to cloud cover. According to NREL, “Local geographical features, such as mountains, oceans, and large lakes, influence the formation of clouds; therefore, the amount of solar radiation received for these areas may be different from that received by adjacent land areas.”

As spring transitions into summer, the increased daylight hours tend to yield greater amounts of generation. The increased solar generation contributes to a phenomenon known commonly as the “Duck Curve” and also tends to lead to increased renewable generation curtailments. Renewable generation curtailments occur when solar generation in the middle of the day exceeds hourly demand on the CAISO grid. As of April 2, 2019, year-to-date renewable curtailments have aggregated up to 227,111 MWh. In a document released by CAISO in May 2017, proposed solutions to oversupply and curtailment include energy storage, demand response (up and down), TOU rates, increased flexibility of existing generators, Western Energy Imbalance Market expansion, increased regional coordination, electric vehicles, and fast-response resources.

As solar generation increases both behind and in front of the meter, customers should be wary of the cost implications of curtailing generation and the price volatility that occurs as solar generation decreases late in the day. The increasing ramp-rate of supply resources late in the day could increase real-time pricing during times of peak demand. Customers with significant exposure to real-time prices should consider layering in additional positions to avoid volatility during the late afternoon hours. Restrictions on the Aliso Canyon natural gas storage facility and other infrastructure supporting fast-response generation will exacerbate volatility during the summer.

For further updates on the power and natural gas markets, read our full report for this month.

Mexico
CFE Rates Up ~0.3% in March, 35% to 40% Higher than Last Year

The CFE has published its tariff for Basic Service customers for April. Rates moved slightly lower, by about 0.36% for capacity and 0.32% for energy. The March-to-April decrease was much more modest than the same increase a year ago, when prices began their dramatic escalation that continued through September 2018. While lower seasonal demand has kept rates steady through the winter and early spring months, commercial and industrial customers are still paying substantially higher prices compared to the CFE tariff from one year ago. In many cases, year-over-year cost increases of the bill in April are near 40% for the capacity component and about 35% for energy.

The chart on the right shows the capacity prices in the Monterrey region for the GDMTH tariff, where prices for April 2019 are just under $356 MXN/kW-month. This represents a 0.36% increase compared to the March rates, and a 40% increase relative to last April’s rates, which registered at just $253 MXN/kW-month. The capacity component accounts for roughly 10% to 20% of overall energy costs.

Energy rates showed a similar slight downward movement in April. The chart below shows energy prices for the Aguascalientes region and GDMTH tariff, load-weighted for each tranche assuming an average of 30% base consumption, 60% intermediate consumption, and 10% peak consumption. April energy prices decreased by about 0.32% in most regions compared to the previous month, roughly 30% to 35% compared to April 2018. Load-weighted prices in Aguascalientes have increased from $1.092 MXN/kWh in April 2018 to $1.473 MXN/kWh in April 2019, a 35% increase over that period. The energy component of customers’ bills usually makes up 50% to 70% of total costs.

In December 2017, the Energy Regulatory Comission in Mexico (CRE) forced the default utility company CFE to unbundle their power rates, breaking out supply components such as energy and capacity from regulated components including distribution, transmission, and ISO charges. This unbundling would increase transparency and make it easier to compare pricing offers from third-party suppliers, which can now provide alternatives to the supply part of the bill.

All over the country, customers have had to face the price growth experienced throughout 2018 that has not pulled back so far in 2019. Leaving the CFE Basic service tariff in favor of third-party supply can be an attractive alternative. More than two dozen qualified suppliers now operate in the market and offer a range of products to achieve greater budget certainty and lower costs.

For further updates on the power and natural gas markets, read our full report for this month.

Authored By The Enel X Energy Intelligence Team

The Energy Intelligence team provides talent and knowledge to our customers by making the complexity of energy management simple.

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