Energy Procurement Insights for May 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 C&I Customers Prepare to Manage Capacity Charges

Each summer starting on June 1, businesses and organizations located in New England have an opportunity to avoid thousands of dollars in capacity costs by strategically lowering site-level demand (also known as Installed Capacity Tag, or ICAP) during the grid’s annual coincident system peak. The ISO-NE grid operator allocates capacity costs based on a customer’s contribution to the grid’s single highest peak hour load.

Specifically, for each megawatt (MW) of demand reduction during the system peak this summer, customers will save more than $90K over the course of next year (June 2020 – May 2021), as long as they are under the correct supply contract structure.

Capitalizing on this opportunity requires knowing when to reduce consumption, and predicting system peak demand has become an increasingly complicated endeavor in the region. Increased deployment of behind-the-meter (BTM) solar and energy efficiency projects is fundamentally altering the traditional load shape of the system. Last year’s peak occurred on August 29, between 4:00 and 5:00 PM, with peak demand reaching 25,559 MW, representing a five-year high. Just the year prior, peak load had set a new 17-year low of 23,508 MW.

Historically speaking, New England peak demand occurs in the mid-to-late afternoon on the back end of a heat wave, when temperature and humidity are high and air-conditioning systems are running at full tilt. While high temperatures are still correlated strongly with high demand, multiple 90-degree days during the 2018 summer failed to push grid demand above 24,000 MW for the first time since 2004. By comparison, New England’s peak record was established in 2006, at 28,038 GW.

Enel X uses proprietary System Peak predictive modeling technology to assess the likelihood of a system peak each year between June 1 and September 30. Enel X advises enrolled facilities of the likelihood of a peak through daily email notifications sent each morning during the program period. Facilities that are able to reduce demand on a given day enact an energy reduction strategy by temporarily reducing non-essential site demand (i.e. lighting, HVAC, certain manufacturing equipment). 

System Peak Predictor 2019 starts in just a couple of weeks. Contact Enel X today to determine site eligibility and to assess your facility’s potential capacity cost avoidance. For more information on Enel X System Peak Predictor contact Enel X Support at +1 888 363 7662 or support.enelx@enel.com.

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

New York
2019/2020 State Budget Removes 4.375% Energy Distribution Sales Tax Exemption

On April 1, Governor Andrew Cuomo and the State Legislature enacted the New York State budget for Fiscal Year 2019/2020. The new budget disclosed the discontinuation of the Energy Services Sales Tax Exemption effective June 1, 2019. Previously, commercial and industrial customers outside of New York City who have contracted for natural gas or electricity supply from an Energy Service Company (ESCO) pay sales tax on the commodity (supply) but are exempt from paying sales tax on the transportation and distribution portion of their bill. All New York ratepayers currently on a third-party supply contract and subject to sales tax will see their tax charges on distribution charges increase by 4.375%.

Introduced in 2000, the Energy Service Sales Tax Exemption was designed to attract commercial and industrial (C&I) customers to third-party energy supply in order to increase pricing competition in New York. The State Legislature stated that the expansion of ESCOs over the past two decades has established a sufficiently competitive market for energy supply rates, citing that “New York utilities offer multiple alternative ESCO gas and electricity suppliers.” Prior to this change, customers that were using utility default service were believed to be unfairly taxed at a higher rate for their electricity and gas supply. Lawmakers estimate the discontinuation will increase state tax revenue by $96M for fiscal year 2020 and $128M in the years following.

The removal of the tax exemption will be applicable to all customers regardless of the date that their current supply contract was signed. In 2009, New York City enacted its own energy transmission and distribution tax at 4.5%. Customers in the city procuring gas or electricity from an energy services company will now see an additional 4.375% applied, bringing their total sales tax rate to 8.875% on all delivery charges.

The table to the right shows a sample electricity delivery bill for a Con Ed customer during the summer months under the General Service Large Rate class. With the discontinuation of the Energy Services Sales Tax Exemption, total electricity charges increased by over $2,500 per month. Annual impacts of the change in the tax code will vary depending on a facility’s demand profile, but will likely range from $20K to $30K for customers with average monthly demand of 1,500 kW. 

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

Mid-Atlantic
MD Clean Energy Jobs Act Pushes State Renewable Portfolio Standards to 50% by 2030

The Maryland Clean Energy Jobs Act has passed in the House and Senate and is now waiting for Governor Larry Hogan’s final blessing. This legislation would increase current MD Renewable Portfolio Standards (RPS) from 25% currently to 50% by 2030. In addition to a path towards clean energy, the Clean Energy Jobs Act is expected to create thousands of in state jobs over the next 10 years. The chart below details the new RPS schedule.

The proposed legislation caused a large jump in MD SREC prices (data from SNL) as seen in the chart below.  SREC prices for 2019 went from around $10/Credit from the beginning of the year to $60/Credit over the past few weeks.

If the bill becomes law, customers could see costs increase by about $1.50/MWh in 2020. While it remains unclear whether contracts will be grandfathered into the current RPS standards if signed before implementation, the belief is that they will, just as they were when the current legislation was signed. If Governor Hogan does sign the bill, the standards will become effective October 1, 2019.

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

Midwest
Ohio Legislature to Vote on Ohio Clean Air Program

On April 12, 2019 House Bill 6 (HB 6) was introduced to the Ohio Legislature which, if voted in favor, would create the Ohio Clean Air Program. The program aims to incentivize the maintenance of Ohio power generation units that are considered “clean air resources,” or electric generating facilities that emit zero carbon dioxide. This incentive would come in the form of a $9.25 payment for every megawatt-hour of zero-carbon-emissions electricity.

Supporters of HB6 claim that end-use consumers would see a benefit in pricing. Ohio Representative Jamie Callender stated, “The good news for electric customers is that for many, their bills will actually go down. This is because there are already charges on their bills in the form of a Renewal Portfolio Standard and Energy Efficiency Standard/Peak Demand. The new program seeks to offer an alternative way to encourage cleaner energy production in Ohio.”

Opponents of the bill claim that it is effectively a bailout for the state’s two nuclear reactors, the Davis Besse and Perry power stations, which FirstEnergy Corp.—which owns both stations—announced will shut down in 2020 and 2021 due to economic reasons. While HB6 would allow the two units to stay open, some have argued that it will increase wholesale electricity prices across all of PJM. As quoted by Power magazine, Stu Bresler of PJM claimed “efforts to subsidize less competitive plants will result in higher power prices for Ohioans. Such actions have the potential to roll back the progress and stability that the markets have facilitated. Such actions could prevent the building of more efficient and cost-effective plants, including cleaner technologies like solar and wind.”

While political battles and messaging rage on, the legislation itself is at risk based on one caveat tied to receiving the subsidy—required participation in wholesale electricity markets. The legal precedent set forth in the 2016 decision of Hughes v. Talen Energy Marketing stated that states can regulate within FERC’s boundaries, but not when state policies interfere on FERC’s purpose to regulate interstate energy markets. The Ohio bill’s language is an ideal target for litigation from the natural gas industry, which is set to lose ground if the legislation passes. The language in the New York and Illinois subsidy bills did not include the wholesale market participation requirement, and both have been upheld in court multiple times.

Customers should note that implementation of a nuclear subsidy program could lead to a lot of changes in Ohio. The legislation could impact existing riders and cost components, which in turn could lead to both increased and decreased cost. All retail contracts have provisions that allow suppliers to pass-through changes in cost, so the impacts could be felt by all customers. Enel X continues to monitor the legislation in Ohio as well as all deregulated markets across North America; if you have questions regarding this legislation or anything else related to your energy supply, please reach out to your account manager, or speak to one of our energy sourcing experts.

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

Texas
Mothballed 385-MW Plant on Texas Gulf Coast to Restart

In 2016, a 385 MW natural gas plant in Corpus Christi ceased operations when NRG’s cogeneration partner, Sherwin Alumina, filed for bankruptcy protection. According to the Houston Chronicle, the plant could power about 77,000 homes on the hottest days of the year. But much to the state’s relief, NRG announced earlier this month that it will restart the plant. The decision was made after Texas regulators gave generators the green light to charge higher prices during times of peak demand.

Texas’ target reserve margin is 13.75%, but as low-cost wind and natural gas plants carve existing fossil fuel generation that has conventionally served reliability out of the market, the reserve margins have dropped to an historic low of 7.4%. This announcement brought some relief in the generation capacity, and Texas will now enter summer 2019 with roughly 8% reserve margins. The reserve margins are still below the target of 13.75%, but an addition of 385 MW is enough to bring on-peak July-August forwards, which were trading at $88-$156/MWh until May 1, 2019, down by $5/MWh.

During summer 2018, when demand hit record spikes with 11% reserve margin, the day-ahead market reached as high as $2,000/MWh for a brief period and averaged $79.03/MWh during the month of July. During summer 2019, in order to tackle the problem of low reserve margins, the Public Utilities Commission of Texas directed ERCOT to adjust the Operating Demand Reserve Curve. This will raise the likelihood that the systemwide scarcity price adder would be used, thus raising the real-time prices. If peak load approaches ERCOT’s forecast of 74,853 MW, it is expected that systemwide on-peak prices could average $217/MWh in August.

Twelve-month contracts starting Jun’19, July’19 and Aus’19 are down by $1/MWh. Customers with an open position for summer 2019 are advised to get in touch with their account and procurement managers at Enel X North America and explore various hedge options to cover themselves from the price volatility that summer 2019 may offer.

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

California
Senate Bill 237 to Add 4,000 GWh to Direct Access Program through 2021

As highlighted earlier this year in the Enel X 2019 Energy Market Outlook, California passed Senate Bill 237 (SB 237) in September 2018 to expand California’s Direct Access (DA) program by 4,000 GWh, or roughly 3% of the state’s peak load. The DA program, regulated by the California Public Utilities Commission (CPUC), allows a limited number of commercial and industrial customers to purchase electricity from competitive third-party electricity suppliers. The CPUC is required to issue an order by June 1, 2019 to determine how the 4,000 GWh expansion will occur, and to make a recommendation on opening the DA program to all non-residential customers on or before June 1, 2020.

A proposed decision (R.19-03-009) issued by the CPUC on April 29 recommends the 4,000 GWh expansion to occur in two phases. During Phase 1, utilities would see their DA caps expanded proportionally by 2,000 GWh in 2020, and the remaining 2,000 GWh during Phase 2 of implementation in 2021. The adjacent table highlights each utility’s apportioned DA load before and after the expansion.

The commission will use the current 2019 DA waitlist to determine which customers are accepted into the Phase 1 expansion starting January 1, 2020, and a new waitlist will be created through the 2019 lottery to determine approval for Phase 2 starting January 1, 2021. Customers who are on the 2019 waitlist will be notified of their ability to participate in DA by June 14, 2019. If accepted, customers have until July 8, 2019 to notify the utility of their intent to participate in DA. Similarly, the deadline for customers to apply and join the 2020 waitlist is also June 14, 2019, with a notification date of August 12, 2019 for their eligibility in 2021, and must notify their EDC of their intent to participate in DA by September 3, 2019.

Customers looking to take a more active strategy in their energy management should consider applying for the 2020 waitlist even if they are already on the 2019 waitlist. Gaining access to the DA program can not only lower supply costs, but can enable customers to take advantage of demand management strategies. If you have any questions regarding the DA program and how to register your load for the lottery, contact your Enel X Account Manager or speak to one of our energy sourcing experts.

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

Mexico
CFE Rates Up ~2% in May, 26% to 29% Year-to-Year

The CFE published its rates for Basic Service customers for May. Rates moved slightly higher by about 1.92% for capacity and 1.69% for energy. The April-to-May increase was much more modest than the same increase a year ago, when prices began their dramatic escalation that continued through September of 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 rate from one year ago. In many cases, year-over-year cost increases of the bill in May are near 29% for the capacity component of the bill and about 26% for energy.

The chart on the right shows the capacity prices in the Monterrey region for the GDMTH tariff, where prices for May 2019 are just under $363 MXN/kW-month. This represents a 1.92% increase compared to the April rates, and a 29% increase relative to last May’s rates, which registered at just $281 MXN/kW-month. The capacity component accounts for roughly 15% to 25% of overall energy costs.                                                                                                    

Energy rates showed a similar slight upward movement in May. 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. May energy prices increased by about 1.69% in most regions compared to the previous month, roughly 20% to 25% compared to April 2018. Load-weighted prices in Aguascalientes have increased from $1.193 MXN/kWh in May 2018 to $1.499 MXN/kWh in May 2019, a 26% 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 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.

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