Energy Procurement Insights for July 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
Maine Sets Target of 100% Renewables by 2050

Maine Governor Janet Mills signed a handful of climate and energy bills into law in late June, setting the state on a path to 100% renewable energy by 2050, including an 80% reduction in greenhouse gas emissions from 1990 levels.

Mills, a Democrat who assumed office this past January, and her administration have taken a markedly different tack from her predecessor, Republican Paul LePage. While the latter used his veto power extensively to quash many bills aimed at expanding the use of renewable energy resources in Maine, the former has wasted little time doing the opposite. Over the last two weeks of June, she signed six pieces of legislation supporting renewable energy and energy efficiency in the state, the most significant of which, LD 1494, mandates 80% of the state’s electricity be renewable-generated by 2030, doubling Maine’s existing renewable portfolio standard target of 40%.

Maine has long been rife with natural resources favorable for renewable energy development. In 2018, the EIA reported that 31% of Maine’s electricity generation came from hydroelectricity and another 21% from wind. It led all New England states in wind power and placed sixth in the nation for wind generation as a percentage of total generation. Under LePage, however, new wind projects were put under a moratorium, and incentives through net-metering were significantly diminished. Mills, in tandem with the Democrat-controlled legislature, has a set a course to reverse that trend. In only her first few months in office, Mills lifted the moratorium and reinstated the net-metering program to its former structure. The recent round of legislation adds 775 MWs of new solar commitments from a combination of distributed and grid-scale projects.

While Maine does appear well on its way to meeting its aggressive targets on the electricity side, the government recognizes the impact fossil fuels have in other sectors in Maine, and the new legislation allows for further electrification as part of its broader efficiency and energy reduction strategy. For instance, while the majority of the US has shifted away from oil heat, more than two-thirds of Mainers rely on fuel oil for heat in the winter. Transitioning away from oil to electric heat pumps, as well as supporting electrification in the transportation sector, are important features in the bills aimed at reducing the state’s total greenhouse gas emissions.

As with any round of green legislation, cost implications can be a significant concern. While at this early stage there is still a lot of uncertainty, Maine’s already significant portion of renewable resources, as well as the falling costs of wind and solar, should limit the impact. Programs to fund the efficiency projects will largely be reflected in distribution costs, while those impacting the state’s RPS will ultimately land on the supply side of the ledger.

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

New York
New York City Passes Local Law 97 to Reduce CO2 Emissions 80% by 2050

On May 18, the City of New York passed Local Law 97, putting in place the most aggressive carbon emission reduction law in the state’s history. The legislation is part of the city’s commitment to drive carbon emissions reductions by 40% by 2030 and 80% by 2050 compared to a 2005 baseline.

The law takes effect January 1, 2024, and is applicable to any commercial building that is 25,000 square feet or larger. The city has set forth two initial compliance periods, the first being 2024 to 2029, and the second being 2030 to 2034. While the 2024 emission limits are intended to affect the largest emitters, by 2030 most building owners will need to implement emissions reduction strategies to comply with the law. Those who report emission levels that do not satisfy the requirements will face steep penalties.

Local Law 97 is the next step in a series of laws passed by New York City over the past 15 years to reduce the city’s energy consumption and greenhouse gas emissions, an effort known as the Greener Greater Buildings Plan. These laws implemented auditing, reporting, retro commissioning, and lighting efficiency requirements for the city’s building owners. The new law goes beyond previous legislation by increasing the 2030 emissions goal from 30% to 40%, requiring annual reporting compared to every 10 years, and much larger fines for those failing to comply with the city’s legislation.

Building owners who fail to submit the required annual reporting will be fined $0.50 per square foot each month the report is not filed. Those who report emissions higher than the limits stated in the law will be fined $268 per square foot multiplied by the difference between the reported amount and the legal limit. An example of the potential fines can be found in the adjacent table. Building owners who are unable to meet the emission limits must implement all prescriptive energy conservation measures presented in LL 97 (Page 17 of Law).The law states that exceptions will be made for building owners who would be prevented from “earning a reasonable financial return” on the property due to the costs necessary for compliance.

Outside of curbing consumption and installing energy efficiency measures, building owners have the option to offset their emissions through the purchase of greenhouse gas offsets and renewable energy credits (RECs). For the first compliance period (2024-2029), up to 10% of total CO2 emissions can be deducted through purchased greenhouse gas offsets. While there are no limitations on deductions to total emissions through the purchase of RECs, the law states that the RECs must be procured from a generator located in Zone J or directly deliverable to Zone J. Presently, the availability of RECs from renewable power projects within or delivered to Zone J are limited, which poses a challenge for building owners looking to meet compliance through REC purchases. Rather, customers will likely have to evaluate the procurement of electricity from renewable generators within or adjacent to Zone J through Power Purchase Agreements (PPAs), and use the RECs produced from the agreement to offset their carbon emissions.

Following the passing of Local Law 97, New York State Governor Andrew Cuomo signed the Climate and Communities Protection Act (CCPA). The act aims to reduce statewide carbon emissions 40% by 2025 and 85% by 2050, with plans to offset the remaining 15%.

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

Mid-Atlantic
Draft of New Jersey Energy Master Plan Released

New Jersey is taking a large step forward towards clean energy and emissions reductions. Governor Murphy’s draft of the 2019 Energy Master Plan (EMP) focuses on reaching 100% carbon-neutral electricity generation along with at least an 80% reduction in greenhouse gas emissions (below 2006 levels) by the year 2050. The New Jersey Energy Master Plan defines seven steps to reach these goals:

  1. Reduce Energy Consumption and Emissions from the Transportation Sector
  2. Accelerate Deployment of Renewable Energy and Distributed Energy Resources
  3. Maximize Energy Efficiency and Conservation, and Reduce Peak Demand
  4. Reduce Energy Use and Emissions from the Building Sector
  5. Modernize the Grid and Utility Infrastructure
  6. Support Community Energy Planning and Action in Low and Moderate Income and Environmental Justice Communities
  7. Expand the Clean Energy Innovation Economy

The current roadmap toward achieving these aggressive goals has been summarized in the Clean Energy Act of 2018, in which the Murphy administration included:

  1. Increasing the Renewable Portfolio Standard to 50% by 2030
  2. Generating 3,500 MW of offshore wind by 2030
  3. Installing 2,000 MW of energy storage by 2030
  4. Increasing energy efficiency standards by at least 2% in the electric sector and at least 0.75% in the natural gas sector by 2024
  5. Transitioning to a new solar incentive program
  6. Developing a community solar program that allows more state residents to benefit from solar energy, especially low and moderate income families
  7. Putting 330,000 Zero Emission Vehicles on the road by 2025 through the State Zero Emission Vehicles Memorandum of Understanding

Combatting the threat of climate change is the main goal of the EMP, although an added benefit would be the creation of new jobs across many sectors and government agencies. Specific dates have not been outlined in this draft of the EMP, but the final EMP will include dates and metrics.

Enel X customers along with all power consumers in New Jersey should be aware of the transition toward clean energy. These outlined goals could cause the price of energy to rise, so please speak with an Energy Advisor about steps to attain your corporate energy goals.

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

Midwest
Ohio Supreme Court Deems FirstEnergy DMR Unjust

On June 19, the Ohio Supreme Court ruled that FirstEnergy can no longer charge Ohio customers a Distribution Modernization Rider (DMR) that has been in place since January 2017.

The DMR was approved by the Public Utilities Commission of Ohio (PUCO) on the basis that the money collected would be used to upgrade the utility distribution system. However, PUCO never placed any restrictions on the rider that would guarantee the money collected would be used for distribution system enhancements, which technically allowed FirstEnergy to spend the money however they choose. Critics of the rider have pointed out that the utility has not made any distribution enhancements while collecting the DMR, and that FirstEnergy has been requesting a bailout for their underperforming nuclear and coal plants during this same time.

While the Ohio Supreme Court has demanded that FirstEnergy immediately stops collecting the DMR, customers will not be entitled to a refund for payments made over the last two years. According to Utility Dive, the costs incurred by customers over the last two years are between $168M to $204M per year. The DMR per kWh cost for General Service customers has been ~$0.0015, or about $1,500 for every 1 million kWh of annual usage.

This latest blow to FirstEnergy occurred as the utility generator is requesting subsidies for underperforming nuclear and coal plants. These subsidies are part of House Bill 6 (HB6) which was introduced into the Ohio Legislature in April of this year. The program aims to incentivize the maintenance of Ohio generation units that are considered “clean air resources” or electric generating facilities that emit zero carbon dioxide. Unlike other states like California and New York, which have established goals to purchase 100% clean power in the future, HB6 includes a move to reduce state Renewable Portfolio Standard (RPS) charges from 12.5% by 2026 to 8.5% of total power sales by 2026.

The Ohio Senate was scheduled to vote on HB6 by June 30 but are still debating whether to approve the bill. While approval seems likely, as of July 1 the Ohio Senate was still working on revisions to the bill. The Ohio Manufacturers’ Association claims HB6 will raise electricity prices and push manufacturing companies to southern states where electricity rates are lower, which will negatively impact the state’s ability to attract new load into the region. The anticipated deadline for voting on HB6 is July 17, 2019.

Customers should take note of the final revisions to HB6 as it will more than likely impact their bills. Although PUCO is requiring the controversial charge to stop, the net impact to customer bills is expected to increase delivered electricity cost. HB6 will stand a test in court if participation in wholesale markets remains required.

If you have questions regarding a site behind any of Ohio’s utilities, please reach out to your Enel X Account Manager, or contact support@enelxnorthamerica.com.

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

Texas
Recent Price Spike Highlights Potential Exposure to Risk for Industrial Customers

In Texas, the Provider of Last Resort (POLR) becomes a facility’s energy provider when their chosen Retail Electric Provider (REP) is unable to continue service. If a customer’s REP were to go out of business, the POLR becomes their temporary REP to avoid interruption in service. The POLR for any area is determined by the Public Utility Commission of Texas.

The energy charges offered by these providers float on real-time settlement prices, determined on the basis of 15-minute intervals and multiplied by 125% to get the final $/kWh value.

For instance, if the real-time energy price is $0.07/kWh, a customer on POLR will end up paying $0.0875/kWh ($0.07 x 1.25).

Recently in June, due to high demand and low wind energy production, real-time prices reached as high as $1.1/kWh or $1100/MWh. During such instances, a customer with POLR services would end up paying hefty amounts for their energy usage, which can be avoided.

Also, depending upon the customer size and area, minimum $/kWh energy charges can vary. For large non-residential customers, the floor price is $0.00725/kWh, while for medium non-residential customers, the minimum price varies between $0.04/kWh and $0.043/kWh. This means that even if real-time prices are trading at $0.001/kWh, a medium non-residential customer will still have to pay $0.04 for each kWh they use.

Industrial facilities currently served by a Provider of Last Resort are advised to explore various strategies such as Fixed Price, Block, and Index, which can ensure more budget certainty and manage risk compared to an Indexed product offered by POLRs. Enel X, through its competitive platform which holds a reverse auction among suppliers, has helped customers across the Texas region find optimum rates for their energy.

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

California
Community Choice Aggregators to Play Vital Part in California’s Renewable Future, but not Without Challenges

In California, large commercial and industrial customers have a multitude of ways of purchasing power—through municipal utilities, regional utilities such as Southern California Edison (SCE), suppliers through the California Public Utilities Commission (CPUC)-limited Direct Access (DA) program, and Community Choice Aggregators (CCAs). Each option has its benefits and drawbacks, but the growing popularity and necessity of CCAs in the mix will help lead the charge towards zero-carbon emissions by 2045.

CCAs are load-serving entities (LSEs) that typically operate similarly to utilities on an opt-out structure. They purchase power from the grid and through power purchase agreements (PPAs) with renewable generators and offer customers discount prices to the default utility rate. Customers who receive generation service from a CCA or DA are subject to the Power Charge Indifference Adjustment (PCIA) charge. The PCIA accounts for the difference between the “actual portfolio cost” and the “market value” of the portfolio at the time the customer switches to alternative supply. PCIA charges are regulated by the CPUC, recalculated annually, and are one of many utility cost recovery mechanisms that remain applicable to load that switches from a utility to a CCA.

With California’s investor-owned utilities suffering financial turmoil, load decay, or insufficient demand to procure more renewable capacity, CCAs will play a large role in the state’s renewable future. In a statement given to Utility Dive, Large-scale Solar Associate Executive Director Shannon Eddy said that CCAs will procure more renewable capacity “because they need about four GWs of long-term renewable contracts by the end of 2023 to meet their RPS obligations.”

Challenges surrounding the lack of established credit ratings could make achieving compliance with RPS goals difficult. Moody’s Investors Service has begun to establish credit ratings with stable outlooks for some CCAs, which will aid in establishing credit with larger developers seeking to expand their foothold in the renewables market; however, many CCAs have already closed on long-term competitive PPAs. As the CCA model matures and establishes a dominant presence, investor-owned utilities could see a substantial portion of their load moving to alternative supply.

Customers with a desire to add more green energy into their energy portfolio should consider CCA options in their area as an easy first step, if DA is not an option. The move doesn’t come without its risks, especially as more load moves away from investor-owned utilities and PCIA charges increase due to lower rate bases. If you have more questions regarding the evolving California market and all options available to your operations, contact your Enel X Account Manager, or email support@enelxnorthamerica.com.

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

Mexico
CFE Rates Up ~0.18% in July, 3% to 4% Higher than Last Year

The CFE published its rates for their Basic Service customers for July. Rates moved slightly higher by about 0.20% for capacity and 0.18% for energy. The June to July 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 in July are nearly 3% for the capacity component of the bill and about 4% for energy.        

The chart on the right shows the capacity prices in the Monterrey region for the GDMTH tariff, where prices for July 2019 are just under $365 MXN/kW-month. This represents a 0.20% increase compared to the June rates, and a 3.49% increase relative to last July’s rates, which registered at just $353 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 July. 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. July energy prices increased by about 0.18% in most regions compared to the previous month, roughly 3% to 4% compared to June 2018. Load-weighted prices in Aguascalientes have increased from $1.452 MXN/kWh in June 2018 to $1.506 MXN/kWh in July 2019, a 4% 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.

More about the author