Energy Procurement Insights for August 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.

To receive this update in your inbox every month—as well as insights on energy management from throughout the industry—subscribe to the EnergySMART blog today. You can learn more about Enel X's energy supply management services here, and talk to one of our experts here.

New England
Increase in Costs from Massachusetts’ SMART Program to Offset Price Relief from SREC Program

Each summer, the Massachusetts Department of Energy Resources (DOER) releases an annual mandate for the percentage of the state’s power supply that must come from solar sources. According to recent preliminary figures from the DOER, the solar carve-out program’s compliance requirement will decrease year-over-year in 2020 for the second consecutive year. Electricity suppliers and utilities will be required to purchase Solar Renewable Energy Credits (SREC I & II) to cover 5.45% of the electricity they serve in 2020, down from 5.66% this year. Based on current prices, Enel X estimates the preliminary reduction will lower SREC costs under the state’s Renewable Portfolio Standard (RPS) by roughly $0.001/kWh in 2020.

The expected decrease in SREC costs on the supply portion of customers’ bills in 2020 follows the implementation of the Solar Massachusetts Renewable Target (SMART) in November 2018, which replaces the nearly nine-year old SREC solar incentive program. Unlike its predecessor, utilities are now responsible for compensating solar developers with 20-year fixed incentive payments and then recovering the costs from ratepayers via a separate tariff line item. As a result, costs associated with new solar development in the state of Massachusetts will be recovered via utility distribution charges instead of through the state’s RPS on the supply bill.

The new tariff line item on customers bills, titled the “Distributed Solar Charge,” became effective January 1, 2019. For calendar year 2019, depending on the utility and rate class, the charge can be as low as $0.00017/kWh or as high as $0.00114/kWh. However, the charge typically exceeds $0.0005/kWh for most rate classes. For the common Eversource Boston T-2 and National Grid G-3 rate classes, the charge is $0.00063/kWh and $0.00053/kWh, respectively. While 2020 distribution rates are not yet known, utilities are expected to file proposed rates with the Massachusetts Department of Public Utilities (DPU) sometime in the next couple of months.

Looking forward, early data suggests that costs associated with the SMART program are poised to jump significantly year-over-year in 2020. Based on DPU filings, approved rates for calendar year 2019 were based on conservative estimates that just 175 MW and 156 MW of solar capacity would be installed in National Grid and Eversource territory, respectively, by end of 2019. As of August 8, 2019, with nearly five months left in the year, NGRID and Eversource have already issued statements of qualification for 576 MW and 254 MW, respectively, according to data from the Department of Energy Resources (DOER). While ratepayers should expect some price relief on SREC charges in 2020 and beyond, they should prepare for those savings to be offset via increased utility distribution charges.

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

New York
Climate Leadership and Community Protection Act Aims for 100% Carbon-free Electric Generation by 2040

On July 22, New York State Governor Andrew Cuomo signed the Climate Leadership and Community Protection Act (CLCPA) into law. The legislation is one of the most ambitious carbon emission reduction efforts in the US today, with goals of 100% carbon-free electric generation by 2040 and statewide net carbon emissions of zero by 2050. The CLCPA follows New York City’s own carbon emission law, Local Law 97, and other legislation from New Jersey, California, and Colorado. While the immediate pressure will be placed on New York electricity generators, the decrease in total net carbon emissions by 2050 will likely increase costs for residents and businesses alike.

This new legislation presents the following benchmarks:

  • 2025: 6 GW of distributed solar generation deployed
  • 2030: 70% of electricity generation produced from carbon-free resources
  • 2035: 9 GW of offshore wind generation deployed
  • 2040: 100% of electricity generation produced from carbon-free resources
  • 2050: 0% net carbon emissions for New York state economy by 2050
    • 85% reduction from 1990 emission levels, 15% carbon offsets through reforestation, restoring wetlands, carbon capture, and other green projects to be determined

While the law does not provide any concrete measures to meet the benchmarks set, it did establish the Climate Action Council. The council will be comprised of 22 members who are expected to be the head of New York state agencies. This group will be responsible for determining how the state’s goals will be met, in addition to consolidating New York’s previous carbon emission and renewable laws into the framework of the CLCPA moving forward. The legislation requires the Climate Action Council to report on the status and necessary adjustments for the CLCPA every four years. Governor Andrew Cuomo has taken steps to achieve the goals set in the new law, and it is expected that the plan will include the responsibilities and penalties for energy consumers. As of the signing date, the council will have three years to develop a plan for achieving the benchmarks set.

On July 18, the governor announced a commitment to 1,700 MW of offshore wind off the coast of Long Island. The project, slated for an in-service date of 2024, would be the largest in the nation, and is the first step toward meeting the state’s target of 9 GW of offshore wind by 2035. In May, New York’s electric grid operator, NYISO, reported in its Power Trends 2019 report that more than one-third of current statewide capacity comes from non-carbon emitting generation. If capacity requirements were to remain level, the grid would need to bring on more than 14 GW of additional renewable generation to meet the 2030 benchmark of 70% carbon-free generation.

New York’s Renewable Portfolio Standard (RPS) is believed to be the mechanism for implementing the carbon-free electricity generation benchmarks of 70% by 2030 and 100% by 2040, as well as carbon tax policies to further nudge the market toward carbon-free resources.

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

PJM 2022/2023 Base Residual Auction Delayed Again

FERC issued an Order on July 25 which effectively cancelled PJM’s planned 2022/2023 Base Residual Auction (BRA). The BRA, previously scheduled to occur between August 14 and August 28, will be postponed until FERC can rule on PJM’s Resource-Specific Carve-out (RCO) proposal

For background, FERC found PJM’s capacity pricing rules “unjust and unreasonable” because they did not account for resources being subsidized by state governments. PJM submitted its RCO proposal to “carve-out” generation resources receiving a “material” subsidy to avoid artificially depressing capacity market offers. FERC was not able to rule on PJM’s RCO proposal before the regularly scheduled May BRA, and still has not ruled on the proposal. PJM and its stakeholders are reluctant to hold the BRA only to see FERC reject PJM’s new rules, which would require PJM to conduct another BRA.

Until FERC rules on PJM’s RCO proposal, the 2022/2023 BRA remains in limbo.

The uncertainty around this particular auction could affect suppliers’ ability to price deals that run past June 2022. Deals with shorter terms or with capacity pass-thru clauses covering months beyond June 2022 may be necessary. Buyers will need to incorporate these products into future purchasing strategies as appropriate.

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

MPSC to Settle PURPA Battle between Developers and Consumers Energy

On June 7, the Michigan Public Service Commission (MPSC) approved Consumers Energy Company’s Clean Energy Plan. The plan included a target to meet 90% of electric load with clean resources; goals for energy efficiency, and storage resources; carbon reduction goals ending dependence on coal and other emitting resources; and investment in infrastructure and demand management programs. Nearly a month and a half later, Consumers Energy took a step towards meeting that goal as it proposed a settlement for the PURPA interconnection queue.

PURPA is the Public Utility Regulatory Policies Act created in 1978. This regulatory act was passed during the infamous energy crises in the late 1970’s. The purpose of the act was to reduce US dependence on foreign oil, incentivize investment in alternative energy resources such as solar and wind, and increase the diversity of the electric power grid. One of the most important provisions of PURPA was to create a market for independent power producers (who are not associated with the utility) where resources would be paid an “avoided cost” determined by the utility.

Since the natural gas renaissance in the Marcellus Shale region, power prices across the country have fallen near all-time lows. Greater penetration of renewable technology and subsidized resources are artificially causing energy prices to go lower. As prices have fallen, the rate at which new resources are compensated under PURPA has fallen along with market prices. The MPSC implemented updates to the PURPA program in 2017 and determined avoided cost rates, but was met with resistance from Consumers Energy due to its capacity position at the time – it didn’t need any new generation for 10 years. The issue remained a political volley between the utility and the MPSC until it was settled in August 2019.

The settlement, as proposed on August 9, states that Consumers Energy will “use ‘commercially reasonable efforts’ to interconnect 584 MW of solar by Sept 2023.” The changes come at a time when a greater focus on a clean energy future is laid out by the MPSC. Ultimately, the 548 MW new capacity added under PURPA will more than likely result in substantial savings for customers when compared to other market alternatives. It will also play a vital part in Consumers Energy’s contribution to the energy future of Michigan.

As the utility tariffs evolve from the Michigan Clean Energy Plan, Enel X anticipates opportunities for customers to take advantage of demand management and other market opportunities. Along with the complex capacity market and Retail Open Access program for customers, these changes could be complicated and opaque. If questions arise, please reach out to your Enel X Account Manager or contact

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

Data Anomaly Causes Texas Prices to Soar Up to $9000/MWh

On May 30, real-time energy prices in Texas averaged up to $360/MWh for 16 hours, compared to about $40/MWh for the entire day. The spike was caused by an error at Calpine, a power company in Houston, which sent the wholesale prices soaring to $9000/MWh.

The error was accidental and Calpine admitted that the data it sent to the state’s grid manager incorrectly showed 4 GW of generation coming offline during late afternoon on May 30. The error was corrected in three minutes, but within those moments the energy prices climbed up by 24000% and ended up costing consumers, industrial customers, power traders, and retail electric providers more than $18M.

Calpine called ERCOT to reprice the 15-minute interval during which the spike occurred, a move that would essentially lead to refunds from the generators, which are paid on the average price during each 15-minute interval. The Electric Reliability Council of Texas, however, has rejected repricing the 15-minute interval and it is unclear at the moment if the customers will be reimbursed for the error.

Consumers on Provider of Last Resort (POLR) or floating at wholesale market rates are advised to get in touch with advisors at Enel X to explore various products such as fixed-price agreements that ensure budget certainty and provide a safety net against such price volatility.

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

California Legislature Establishes $21B Wildfire Insurance Fund for Utilities

On July 12, the California State Assembly passed Assembly Bill (AB) 1054 in an effort to provide financial stability to the state’s largest Publicly Owned Utilities (POUs) as potential wildfire liabilities put their financial solvency at risk. The legislation will create funds that will be financed by both ratepayers and the state’s utilities, and will be made available to pay out liabilities to utilities in good safety standing that are held responsible for future wildfires. AB 1054 is the state’s first attempt to restructure who ultimately pays for civil liabilities after catastrophic wildfires and avoid shifting the costs from customers to the utilities.

In January, California’s largest utility, Pacific Gas and Electric (PG&E), filed for chapter 11 bankruptcy as it faced impending civil liabilities valued in the tens of billions of dollars for its role in starting wildfires in 2017 and 2018.

Creditors and ratings agencies acknowledged California’s utilities’ potential bankruptcy risk by downgrading bonds issued by Southern California Edison (SCE) and San Diego Gas and Electric (SDG&E) to near junk status. The drop in credit ratings fed a downward spiral of lessening a utility’s ability to secure financing for wildfire safety investments, increasing the likelihood that wildfire damages could result in ratepayers bearing the brunt of utility bankruptcy costs.

AB 1054 establishes two wildfire liabilities funds for utilities valued at a cumulative $21B. The first $10.5B will be paid for through the existing “DWR Bond Charge” that was originally established after the California Electricity Crisis. Prior to new legislation the charge was slated to be removed by the end of 2020, but it is now expected that customers will continue to see the line item on their bills until at least 2035. Currently, the “DWR Bond Charge” rate is $0.00525/kWh, and for a small commercial/industrial customer with 1,000,000 kWh annual usage, this charge amounts to $52,500 per year. The remaining $10.5B will be funded through contributions from the participating utilities proportionate to their size. The legislation outlines conditions that must be met in order to participate, which include $5B of wildfire safety investments across the three largest utilities that cannot be funded through rate hikes (among other requirements). The governor’s office has estimated that, once fully financed, the fund will be able to provide financial security to the utilities for 10 to 15 years.

Immediate participation in the funds will only be made available to SCE and SDG&E. PG&E will not be allowed to cooperate until it has completed its bankruptcy restructuring to the standards of California’s legislature, for which the utility has been given a deadline of June 30, 2020. Both SCE and SDG&E have announced their decision to join the wildfire fund and will be responsible for contributing $2.4B and $450M, respectively, in the first year, as well as annual contributions in the future. PG&E will need to contribute $4.8B to participate in the fund once it meets the law’s criteria for eligibility.

In addition to the funds, AB 1054 establishes the California Wildfire Safety Advisory Board. Comprised of seven state-appointed members, the board will work with the Wildfire Safety Division and the Office of Energy Infrastructure Safety to review and provide feedback on the wildfire mitigation plans required of California public utilities. The board will also be responsible for accepting applications for cost recovery assistance from the newly established funds, as a result of costs incurred by wildfire liabilities that were unavoidable by a utility in good standing.

Prior to the law, California’s publicly owned utilities each filed cost of capital applications with the California Public Utilities Commission (CPUC) requesting approval for rate increases effective January 2020 through December 2022. Each utility requested an increase of at least 4% in projected equity return that would be financed by ratepayers in an effort to increase financial stability through equity investments. All three companies cited increased wildfire risk and impending liability as reasons for their requests. The CPUC has yet to announce any official rulings as proceedings have been under protest from community interest groups, and it is unclear when rulings will be made.

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

CFE Rates Down ~0.70% in August, 8% to 10% Lower than Last Year

The CFE published its rates for their Basic Service customers for August. Rates moved slightly lower by about 0.80% for capacity and 0.70% for energy. The July to August decrease was drastic compared to the increase that was seen a year ago, when prices began their dramatic escalation that continued until September 2018. While the lower seasonal demand has kept the rates constant during the winter and the first months of spring, commercial and industrial customers began paying lower rates this month compared to the CFE rate a year ago. For this month, the decrease in costs year after year in August is almost 10% for the capacity component of the bill and about 8% for energy.

The chart on the right shows the capacity prices in the Monterrey region for the GDMTH tariff, where prices for August 2019 are just under $362 MXN/kW-month. This represents a 0.80% decrease compared to the July rates, and a 10% decrease relative to last August’s rates, which registered at just $401 MXN/kW-month. The capacity component accounts for roughly 15% to 25% of overall energy costs.                                                                                                            

Energy rates showed a similar slight downward movement in August. The chart below shows energy prices for the Aguascalientes region of the GDMTH tariff, load-weighted for each tranche assuming an average of 30% base consumption, 60% intermediate consumption, and 10% peak consumption. August energy prices decreased by about 0.70% in most regions compared to the previous month, roughly 8% compared to August 2018. Load-weighted prices in Aguascalientes have decreased from $1.632 MXN/kWh in August 2018 to $1.496 MXN/kWh in August 2019, an 8% decrease over that period. The energy component of customers’ bills usually makes up 50% to 70% of total costs.

In December 2017, the Energy Regulatory Commission 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.

More about the author