Energy Procurement Insights for June 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
Connecticut Passes Bill to Procure 2,000 MW of Offshore Wind by 2030

On June 5, 2019, Connecticut’s Senate unanimously approved an energy bill that mandates the largest procurement of renewable energy in Connecticut to date. The bill, H.7156, expected to be signed immediately by Gov. Ned Lamont, requires the state Department of Energy and Environmental Protection (DEEP) to solicit long-term (15-20 year) contracts for 2,000 MW of offshore wind capacity by 2030. This is in addition to the 300 MW of offshore wind capacity already procured by Connecticut in 2018, which is expected to come online in 2023. The legislation comes roughly a year after the state passed “An Act Concerning Connecticut’s Energy Future,” which requires that 40% of the state’s power come from renewable resources by 2030.

Between Massachusetts and Connecticut, the two states now have commitments to add 3,600 MW of offshore wind over the next decade, and that number is expected to soon grow. Massachusetts House Bill 4568, “An Act to Promote Energy Diversity,” which was signed into law in August 2016, requires the state to procure 1,600 MW offshore wind by June 30, 2027 and called on the Massachusetts Department of Energy Resources (DOER) to investigate adding an additional 1,600 MW. That study, concluded in the end of May, found that the additional 1,600 MW of wind would be cost-effective for ratepayers so long as the pricing came in similar to the first contract awarded to Vineyard Wind last year. Vineyard Wind, an 800-MW project, signed a 20-year power purchase agreement (PPA) for 8.9 cents/kWh, only a fraction of a cent higher than the PPA for the transmission of hydroelectricity from HydroQuebec and significantly lower than expected. The project has a commercial operation target of 2023, and the additional solicitations are slated to take place in 2022 and 2024, in order to provide a steady stream of incentives for offshore wind development, as well as capture any potential savings in falling technology costs.

As a region, New England is currently expected to contract nearly 5 GW of offshore wind over the next five years. For context, ISO-NE’s current installed capacity is roughly 32 GW, serving a summer peak demand of roughly 26 – 28 GW. In recent years, winter peak demand has been most responsible for straining the system because of its heavy reliance on natural gas. In 2018, natural gas accounted for nearly 50% of the region’s generated kilowatt-hours, with nuclear resources accounting for the next 30%. Offshore wind is expected to produce more in the winter compared to solar, which has greatly reduced output when there are fewer daylight hours. Offshore wind will also hopefully add much-needed fuel diversity during periods of extreme cold.  

Although acting to alleviate one system deficiency, the procurement may add a different kind of market strain as it is another in a string of subsidies for renewable resources, which is distorting price formation in New England’s wholesale energy and capacity markets. Since renewable resources do not have fuel costs, when they are available and producing power, they act to suppress prices, which traditional resources like nuclear and natural gas rely on in order to remain profitable. ISO-NE is currently rethinking how to accommodate states driving to green energy while maintaining a healthy market that provides the right price signals to ensure a reliable grid.

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

New York
New York Requests Reinstatement of Oversight Authority in Key Gas Pipeline Permits

Since 2016, New York has halted the construction of several natural gas pipelines seen as critical to meeting the state’s rising demand. The state has done so by denying the projects’ water quality permits under the Clean Water Act. However, in two recent cases, natural gas proponents are challenging New York’s jurisdiction, arguing that the state waived its Clean Water Act authority by failing to issue a water quality permit within one year of its application. In August 2018, FERC ruled in favor of National Fuel Gas, the company looking to build the 497 MMcf/d Northern Access Pipeline project, and plans to issue a decision regarding the 650 MMcf/d Constitution Pipeline project two months from now. In response, the New York Department of Environmental Conservation (DEC) recently requested that a federal court reinstate its permit authority. It remains to be seen whether or not the court will support New York’s rejection of these projects. Together, the Northern Access Pipeline, Constitution Pipeline, and recently-denied Northeast Supply Enhancement Pipeline would bring an additional 1,547 MMcf/d of capacity to New York, and would enable the development of new laterals to transport gas into other regions.

Last year, the Northern Access Pipeline requested FERC to rule that the New York Department of Environmental Conservation had waived its Clean Water Act authority by failing to provide permitting for the project within the one year deadline. The project had been approved by FERC in February 2017 but did not receive a water quality permit from the state of New York within one year. In August 2018, FERC found that the state of New York waived its Clean Water Act authority under the statutory deadline and denied the state its appeal in early February 2019. On May 30, the New York Department of Environmental Conservation requested a federal court reinstate its permit authority for the pipeline. This request came two weeks after the State used its Clean Water Act authority to deny water quality permits to Transcontinental Gas Pipe Line Co for the Northeast Supply Enhancement project, which was approved by FERC on May 3. On May 28, FERC informed the U.S. Court of Appeals that it will report a decision in two months on the same water quality permit rejection for the Williams Cos-led Constitution Pipeline. FERC originally approved the project in 2014, and the state of New York stopped the project in 2016. FERC initially denied Constitution’s request to hear the matter in early April, but has since opened the case after a federal court ruled that states cannot use Clean Water Act authority to stop hydropower licenses.

In January, Consolidated Edison issued a moratorium on new applications for natural gas connections in Westchester County. National Grid New York issued the same moratorium for new customers in New York City and Long Island on May 17. Both utilities cited concerns about their capacity to meet increasing demand. National Grid went a step further, specifying that the moratorium will remain in effect until the Northeast Supply Enhancement pipeline project receives the necessary permits to proceed. Consolidated Edison leveraged the moratorium on new gas applications to push state regulators to approve their $223M “Smart Solutions” program, which provides natural gas efficiency measures and alternatives to new and existing customers.

With the anticipated retirement of the Three Mile Island and Indian Point nuclear power plants and New York’s regulatory efforts to remove coal from the state’s generation mix, reliance on natural gas for heat and electricity continues to increase. Natural gas prices in the Northeast are extremely volatile during the winter months, as pipeline capacity is constrained during periods of extreme cold. Additional capacity from projects like the Constitution Pipeline could alleviate these winter spikes to wholesale energy prices, but appear to run afoul of New York’s long-term environmental objectives.

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

Updated PJM Network Integration Transmission Service Rates

On May 30, 2019, PJM posted transmission updates to Network Integration Transmission Service (NITS) prices as seen in the chart below. These charges are used to collect funds for transmission service from customers to reimburse PJM transmission owners for necessary upgrades and expansions to the system. The latest (NITS) updates are effective June 1, 2019 until changed again later in the year. NITS charges are paid by every customer in each respective zone based on their transmission tag. Transmission tags are calculated based on a customer’s demand during hours when the transmission zone experiences peak congestion. Customer transmission tags are reset at the beginning of each calendar year.

Customers should be aware of increasing or decreasing transmission costs beginning June 1 this year. Enel X customers can actively manage down peak loads throughout the year, effectively lowering their transmission tag for the next year.

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

MPSC Approves Consumers Energy Path to a Cleaner Energy Future

On June 7, the Michigan Public Service Commission (MPSC) approved Consumers Energy’s (CECO) integrated resource plan (IRP) required by the 2016 energy overhaul bill. While largely unchanged from the IRP CECO filed in June 2018, the utility that serves much of the Lower Peninsula has agreed to study early retirement of the remaining Campbell Coal Steam Plant units as early as 2025. In place of the coal, CECO has targeted additions of 6,500 MW of renewable energy capacity with roughly 77% of the additions through 2040 being solar power.

The adjacent table pulled from the IRP shows how the transition will change CECO’s generation mix in 2030 and 2040. CECO’s ultimate goal is to reduce carbon emissions by 90% to 2005 levels. This includes the retirement of all coal and nuclear generation, renewable additions, and no new natural gas or coal capacity. The renewable additions were originally proposed as fully-owned assets of CECO, but the MPSC-approved plan includes 3,250 MW of capacity owned by the utility and the remaining half owned by third-party generators.

The move away from conventional fossil fuel generation leads to questions about the impact on electricity bills. Based on the analysis put forth in their IRP, CECO notes that “projected annual rate increases in this plan through 2040 are well below the projected rate of inflation over that same time period.” Like many other utilities and other end users, CECO uses a competitive bid process to procure electric generation. CECO’s timing and incremental strategy allows for increased flexibility in technologies that are rapidly decreasing in cost, according to numerous studies. A deeper focus on demand management will also aid in the transition as more programs are rolled out to help customer manage their peak loads.

As demand management programs are rolled out behind CECO, Enel X can help customers navigate which programs would be a best fit and help prioritize participation to maximize benefits. Enel X can also assess tariff rates as they change to determine optimal delivery service. If you’d like to find out more, please contact Enel X Support at +1 888 363 7662 or

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

Customers in ERCOT Prepare to Manage Transmission Costs

Every summer, the system operator (ERCOT) in Texas rolls out a 4CP program to measure how much each customer contributes to the total peak load of the electric grid. The larger a customer’s contribution to that peak, the greater the charge applied to that customer’s bill each month of the next calendar year.

4CP stands for Four Co-Incidental Peaks, or the peak hour on the grid for the four summer months of June, July, August, and September. At the end of the summer, each customer is assigned a tag based on their usage during peak hours. This tag is found by multiplying the customer’s demand during each peak hour by 25% and adding up the results for all four months. Customers in the ERCOT footprint have an opportunity to avoid thousands of dollars in transmission costs by strategically lowering site-level demand during these four 15-minute intervals.

Enel X analysts use proprietary predictive modeling technology to assess the likelihood of system peaks every day between June 1 and September 30 and advise 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, and certain manufacturing equipment) to reduce their peak load contribution (PLC), which is used to calculate transmission charges. These practices can deliver as much as $50k in annual savings per one megawatt of demand reduction.

Enel X’s System Peak Predictor program for 2019 started earlier this month. Contact Enel X today to determine site eligibility and to assess your facility’s potential cost avoidance. For more information on Enel X System Peak Predictor, contact Enel X Support at +1 888 363 7662 or

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

2018 Wildfire Season Will Impact California Ratepayers Well Into the Future

In September 2018, the California state legislature created the Commission on Catastrophic Wildfire Cost and Recovery (CCWCR) through Senate Bill 901 (SB 901) in response to the devastating wildfires that occurred in the state. The committee was tasked with examining “issues related to wildfires associated with utility infrastructure, and to produce recommendations on changes to law that would ensure equitable distribution of costs” to those impacted. While CCWCR works on consumer protections, SB 901 also requires utilities to submit wildfire mitigation plans focused on increased vegetation management practices, infrastructure improvements, and better transmission line inspection and monitoring programs. The key takeaway from this will be increased bills to end-use customers.

In January 2019, credit rating agencies S&P and Moody’s downgraded Pacific Gas & Electric (PG&E)’s credit rating from “B” to “BBB” over liabilities related to the 2017 and 2018 wildfires. This caused the utility to plunge into Chapter 11 bankruptcy. San Diego Gas & Electric (SDG&E) and Southern California Edison (SCE) were soon to follow, with ratings dropping from “A-“ to “BBB+” and “BBB+” to “BBB,” respectively. Credit ratings are important to track because as ratings drop, the cost of the debt increases, which is directly recovered through the rate base. After PG&E’s credit downgrade in early January, bonds with a term ending in 2034 saw a 100-basis-point move from 6.01% yield to ~7%.

As credit ratings move down, total System Average Rates (SAR) are increasing at all three utilities. Total SAR is the individual utility’s total authorized revenue requirement divided by kilowatt-hour sales. The May 2019 release of the CPUC’s “Actions to Limit Utility Cost and Rate Increases” report highlighted the following:

  • Total SAR tracked in tandem with inflation until 2013. Total SAR from 2013 to 2019 outpaced average inflation figures, with SDG&E setting the highest increases out of the three investor-owned utilities (IOUs) in California.
  • Rising SAR rates are attributable to increases in revenue requirements and declining utility sales, i.e., fixed costs are socialized across a lower customer base.
  • Wildfire Mitigation Plans, legislatively required by SB 901, estimate substantial increases in cost for residential customers, which could translate over to commercial and industrial customers as well.
  • Costs related to wildfires occurring in past years have not been determined and could continue to push rates higher.

Customers should take note of all of the legislation surrounding wildfires and the financial health of their utility or utilities. SB 901 is likely the first of many legislative implementations to determine how utilities and regulators will work to mitigate wildfires and socialize costs across customer bases. At this point, the chance of utility bills increasing throughout the future due to wildfires and declining utility sales is a certainty.

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

CFE Rates Up ~0.35% in June, 16% to 18% Higher than Last Year

The CFE published its rates for their Basic Service customers for June. Rates moved slightly higher, by about 0.39% for capacity and 0.35% for energy. The May-to-June increase 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 rate from one year ago. In many cases, year-over-year cost increases of the bill in June are nearly 18% for the capacity component of the bill and about 16% for energy.

The chart on the right shows the capacity prices in the Monterrey region for the GDMTH tariff, where prices for June 2019 are just under $364 MXN/kW-month. This represents a 0.39% increase compared to the May rates, and a 17.71% increase relative to last June’s rates, which registered at just $309 MXN/kW-month. The capacity component accounts for roughly 15-25% of overall energy costs.

Energy rates showed a similar slight upward movement in June. 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. June energy prices increased by about 0.35% in most regions compared to the previous month, roughly 15-20% compared to May 2018. Load-weighted prices in Aguascalientes have increased from $1.295 MXN/kWh in June 2018 to $1.504 MXN/kWh in June 2019, a 16% increase over that period. The energy component of customers’ bills usually makes up 50-70% 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, a trend 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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