Energy Procurement Insights for March 2018: 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 our weekly updates on the national energy markets and insights on energy management from throughout the industry—subscribe to the EnergySMART blog today. You can learn more about Enel X's energy procurement services here, and talk to one of our experts here.

For analysis of the major issues in the energy markets that could affect your energy costs for the year ahead, download the Energy Intelligence team's new whitepaper, What to Expect from Energy Markets in 2018.

New England
2021/22 Capacity Prices Fall to 5-year Low

Capacity prices fell to a five-year low in ISO New England’s 12th Forward Capacity Auction (FCA12) for 2021/22 delivery. Prices cleared at $4.63 per kW-month (~$55,000/MW-year) for all zones for the June 1, 2021 – May 31, 2022 delivery year, the lowest level since the 2013 auction. This is a nearly 13% drop from last year’s clearing price of $5.30/kW-month (~$64,000/MW-year) for 2020/21.

The decline in capacity prices was in line with market expectations, as a lower Installed Capacity Requirement (ICR) resulting from growth in behind-the-meter generation such as solar, the addition of new demand response resources, and the absence of any new significant generator retirements were expected to put downward pressure on prices.

Each year, the operator of the regional power grid holds a forward capacity auction to secure electricity supplies needed to meet predicted energy demand three years in the future. The auction sets the price generators receive for making a commitment to produce power when needed. In turn, these costs are recovered from electric consumers in New England based on their demand contribution to the ISO-NE system peak hour each summer.

This year, the FCA12 auction secured 34,828 MW of power capacity at a total cost of about $2.07 billion, which is about $330 million below last year's auction. While some resources elected to delist their capacity, no major power plant retirements were scheduled for the 2020/21 commitment year. The auction procured 174 MW of new power generation and 514 MW of new energy efficiency and demand response measures; otherwise, all other resources were previously operating.

The latest results mark the third consecutive year that capacity auction prices have fallen for all zones and the fourth year straight for Northeastern Massachusetts (NEMA). For NEMA customers, the recently released prices for 2021/22 represent a nearly 70% decrease, equivalent to ~$125,000/MW-year, compared to the current 2017/18 year. For an average commercial and industrial NEMA customer with a load factor of 60%, this will equate to a decrease of roughly ~$0.028/kWh. Capacity prices will peak for all other zones in 2018/19 and decline thereafter.

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

New York
Regulators Improve Energy Storage Opportunities

The New York Public Service Commission issued two orders this month to enable and accelerate the development of distributed energy resources in New York. The orders will make it easier for energy storage systems to interact with the utilities' distribution system. In addition, the Commission decided to expand the size eligibility to include projects between 2 MW and 5 MW. These projects will now be eligible to receive compensation based on actual calculable benefits rather than just net metering credit. This should further reduce costs and encourage development of solar power and energy storage. Currently, the 2-5 MW class represents around 2% of the total MW in queue and the changes should encourage larger-scale projects going forward.

In addition, regulators approved a plan for Consolidated Edison of New York to significantly expand the use of battery storage systems by simplifying the process. These amendments include expanding circumstances in which energy storage systems could export to its distribution system, as well as establishing a wider definition of storage technologies that expands beyond batteries. The new definition now includes flow batteries, fly wheels, and compressed air storage, among others. By allowing these storage systems to export power to the distribution system, they can now participate in demand response programs and other Non-Wire Alternative projects.

These new regulations will make it easier for New York to integrate battery technology to meet the changing needs of the distribution system, particularly as renewable resources fail to sync with system demands consistently. New York is targeting 1.5 GW of storage by 2025, and will likely use 2030 as a target year to align with the 50% renewable goal set in the state’s Clean Energy Standard.

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

Block & Index and Index-Only Customers Experience Some Supply Rate Relief in February 2018 after an Expensive January

The Block & Index product allows customers to fix a portion of their future load with a supplier while allowing the balance of the load to settle at spot market rates. Index-only customers take a more risky approach and let their entire load settle at spot market rates without hedging into the future. Hedging is similar to buying insurance—customers who hedge can spread out known costs more evenly month-to-month, while not having to worry about market risk or power prices spiking.

PJM experienced extremely cold weather in January 2018, resulting in high demand and high prices across the region. February 2018 was the opposite. With mild weather throughout the month, Day Ahead Locational Marginal Prices (LMPs) averaged $27.61/MWh. This means Block & Index and Index-only customers would be paying high LMPs on the index portion for January and low LMPs for the index portion for February.

The example below shows a theoretical hedge price for January and February 2018 and corresponding average monthly LMPs. In this example, taking a Block & Index or Index-only approach would have been beneficial for the month of February, but would increase costs in January for the unhedged portion of the load. Historically, customers that take on more market risk will pay less for energy over the long term, but these customers must be able to withstand large cash withdrawals when LMPs spike and cause costs to increase substantially.

Customers should not let what happened this winter change their procurement strategies, but instead should be aware of the two extremes that we experienced over January and February 2018. There is no perfect way to approach electric energy risk management, but customers can begin exploring various options by speaking with an Energy Advisor at Enel X.

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

MISO South Forced Outages Cause High Prices

The cold snap in January revealed a number of generation and transmission issues in the MISO footprint. While system integrity was maintained throughout the event, forced outages and highly congested regions resulted in the highest electricity prices seen since the Polar Vortex in 2014.

The greatest impact was felt in the South Region, which includes Arkansas, Louisiana, as well as parts of eastern Texas and the western portion of Mississippi. Temperatures fell into the single digits in the South Region, forcing nearly 10 GW of generation offline. Prices across the total MISO footprint averaged approximately $40/MWh, while prices in the South Region alone averaged nearly $45/MWh. This increase is significant given that most of the RTO has seen monthly real-time averages below $30/MWh the last three years.

The lowest temperatures and highest system strain were experienced on January 17th and 18th, when the MISO peak load was 106 GW and the South Region set a new record of 32 GW. Platts reported nearly 10 GW of forced outages and 8 GW of additional outages during this time as the South Region’s load surpassed available generation capacity, requiring a number of actions from the system operator to maintain reliability. Max generation events were issued, demand was instructed to curtail, and emergency power imports were made from other MISO regions and RTOs. The South Region already faces transmission constraints, and these events only exacerbated congestion in the area. Additionally, the South Region is largely served by natural gas-fired generation, which, along with coal, made up the vast majority of outages.

MISO has begun to move on improvements to the reliability of its system, particularly in the South Region. FERC recently approved changes to the generation interconnection queue, which is designed to reduce the time required to connect by issuing fewer automatic restudies. The 500 kV Hartburg-Sabine transmission project has been approved by FERC, which will alleviate congestion in the South Region. However, the biggest issue may be flaws in MISO’s Planning Resource Auction or Capacity Market. As reported by RTO Insider, MISO’s Independent Market Monitor has repeatedly pushed for modifications to the methodology behind the clearing prices, which result in “inefficient, unjust and unreasonable prices.” The 2017-2018 Planning Resource Auction (PRA) resulted in a surprisingly low clearing price of $1.50/MW-day across the RTO. With the proposed changes, the clearing price is estimated to be closer to $115/MW-day. The next auction for the 2018-2019 planning year will be held this month and will use the current methodology.

While MISO is making improvements to improve reliability, none of these headlines are likely to have an impact in the immediate future. Customers should expect uncertainty in the upcoming Capacity Auction, which only sets prices one year in the future. It will take years for projects to be incentivized, approved, and built. Therefore, the South Region will continue to be constrained and at risk of price increases during unexpected cold weather.

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

ERCOT Wholesale Spot Power Prices Fall 42% Month-on-Month in February

Last month, day-ahead spot market power prices fell 42% compared to January as daily peak loads declined and average fuel prices fell.

In January, frigid temperatures contributed to record winter season peak loads and energy prices in the state of Texas. February saw much milder temperatures, resulting in the price decrease. In addition, delivered natural gas prices dropped 35% lower month-over-month. As a result of milder temperatures, the measured peak load of 55,343 MW was about 16% lower than January 2018. The monthly average day-ahead power price for February 2018 was $21.83/MWh across all hubs, whereas the average monthly spot price in January 2018 was $37.77/MWh.

Consumer demand and the cost of fuel used to produce electricity are the two primary drivers of spot market electricity prices. The central footprint of ERCOT saw average temperatures nearly in line with seasonal daytime averages for the duration of February. On balance, wholesale power prices were softened by lower delivered prices for natural gas when compared to last month. The monthly average natural gas price in February was $2.629/MMBtu at the Houston Ship Channel delivery point in Texas, about a 35% decline under the $4.060/MMBtu average seen in January 2018. The price of electricity is closely linked to the cost of natural gas in Texas since it is the predominant fuel used to generate power produced in the state. In fact, natural gas-fired power plants usually set the price of wholesale electricity in the region.

Power prices will generally react to electricity demand, which is driven by weather and economic factors. As mentioned above, the ERCOT system demand peaked at 55,343 MW in February 2018, which is about 16% lower than the January 2018 peak load of 65,731 MW. Aside from the observed temperatures and lower natural gas prices, power prices remained in check as a result of a balanced mix of generation resources.

For deeper insight into capitalizing on opportunities in the Texas energy market, register for this webinar hosted by Energy Manager Today on Wednesday, March 28th.

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

Community Choice Aggregation Program Seeks Dramatic Growth in San Francisco

Since the competitive retail market in California is largely limited to the Direct Access program, which permits just 10% of the state’s load to contract with a third-party supplier for power, most customers are left with few supply options. However, customers are permitted to receive third-party supply if they do so under the Community Choice Aggregation program, which allows counties and municipalities to aggregate their customers’ load and contract for supply that includes more renewable power than would be available from their default supplier.

Currently, there are nine Community Choice Aggregation (CCA) programs active in California, serving nearly 1 million customers. The program has been growing, and the California Public Utilities Commission (CPUC) is projecting that its popularity will continue to gain steam. In 2015, CCAs accounted for just 1% of the state’s total load; however, the CPUC projects that this number can grow to 20% of state load in the next two years. One of the CCA programs is now outlining its plan for growth.

The San Francisco CCA program, CleanPowerSF, has outlined its plan for aggressive customer expansion over the next two years. CleanPowerSF began customer enrollments in 2016 and currently serves about 80,000 customers in the San Francisco area. The San Francisco Public Utilities Commission (SFPUC), which oversees the program, has approved the expansion to enroll an additional 100,000 customers by the summer of 2018, followed by an additional 60,000 in the second half of 2018, and a further 100,000-to-150,000 new customers in 2019, bringing total expected enrollment to nearly 400,000. The expansion anticipates the enrollment of all customers in San Francisco that are eligible to participate. The SFPUC has granted the program the right to sign additional long-term contracts for renewable supply with providers, which will serve as the generation base for their customers.

Customers in California that are eager to get access to third-party supply but are not enrolled in the Direct Access program may leverage a Community Choice Aggregation program. This would be of particular interest to customers that have sustainability goals and are seeking third-party options that provide additional renewable power.

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

Turbulent Start to the Unbundled Tariff; CRE Reviews and Revises Methodology

Beginning in December 2017, the Mexican utility, Comision Federal de Energia (CFE), was directed to publish unbundled tariff rates by the regulatory body, CRE. Under the previous regime, the CFE published only monthly demand charges and base, intermediate, and peak energy charges, which baked together other transmission and distribution charges, ancillaries, ISO charges, and other fees. This made it impossible to compare the CFEs utility rates to competitive market rates with third-party suppliers. The unbundling of the tariff provided transparency, as the various distribution, ISO charges, and fees were broken out individually from supply charges for energy and capacity. Customers saw a new CFE bill format beginning in December 2017, breaking out each of these components.

Under the new tariff regime, some customers reported dramatic increases in their energy costs in December. Customers in Baja California were particularly affected, reporting November to December cost increases of as much as 60%, with roughly constant usage across the periods. After significant outcry from consumer groups and industrial organizations, the CRE took a closer look at the tariff methodology and directed the CFE to revise their tariffs. The publication of the February tariff rates was delayed until almost halfway through the month, finally appearing on February 12. The CFE actually went back and retroactively revised its prices for energy and capacity, with capacity seemingly most affected. In the table below, prices for capacity in Baja California registered at 282 MXP/kW in December and more than doubled to 572 MXP/kW in January. After the tariff was revised, December prices decreased by 52% to 136 MXP/kW, and January prices decreased by more than 70% to 164 MXP/kW. Capacity prices in Aguascalientes also saw a decrease as a result of the revision, though not to the same extent.

Customers should take care to review their February and March statements and compare them against the latest published CFE tariffs. Due to the retroactive tariff price revisions for capacity effectively lowering prices for many, customers should see credits on their bill for overcharges incurred and paid during December and January. Under both the previous and current tariff structure, prices are updated monthly and unknown ahead of time. This price uncertainty can make energy spend budgeting impossible, which is why many customers are taking advantage of third-party supply contracts that can provide fixed prices over established periods.

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

Henry Hub
As Winter 2018 Nears End, NYMEX Pricing Near Pivotal Support Level

The natural gas supply and demand market experienced a significant change over the past decade. The shale revolution led to historical production levels, and the gas demand market is in the process of responding with an infrastructure revamp. Currently, the market finds itself at a point where the new infrastructure is having an increased level of impact on the physical gas market, allowing for supply to be more nimble and easier to transport from region to region. The market changes are creating parity between basis points in the Marcellus shale gas production region and Midwest markets by reducing the discounted basis in shale region for points such as Dominion South and TetCo M-3, while simultaneously increasing the discount to NYMEX in Midwest for points like Chicago and MichCon.

As shoulder season begins to usher out winter and welcome in spring, gas fundamental and technical factors are also reaching an inflection point, with the end-of-March storage level becoming more likely to enter injection season at a healthy level of 1.4 Tcf. The bearish pressures that the production increases and natural gas storage levels bring will be compounded by the new era of infrastructure expected to begin commercial operations later this year. The Rover Pipeline, being constructed by Energy Transfer Partners, is expected to begin service by the end of March, adding over 3 Bcf of capacity to get Northeast shale production to the upper-Midwest and Ontario, Canada.

The rolling prompt NYMEX price is trading near technical support around $2.55/MMBtu, a level not breached since June 2016, as depicted in the graph below. The technical support will likely attract a fair amount of buying. A consistent trade below this technical support level would be interpreted as bearish and would likely lead to further downside price exploration below that level. Based on the significance of the technical support level of $2.55/MMBtu, a customer with 2018 NYMEX exposure should consider delaying hedging NYMEX until the start of shoulder season in April.

Adding further supportive data into the market, temperature forecasts from NOAA are calling for a colder-than-average start to March for much of the gas-consuming region in the East and Midwest. The colder-than-normal temperatures will likely prevent any significant downside movement in NYMEX pricing for the early part of March. Looking toward the second half of March and into shoulder season, NOAA is calling for temperatures to come in above historical norms, likely to exert moderate bullish pressure. Although the current fundamental factors are exerting short-term upward pressure on NYMEX, overall the supply-heavy nature of the current market will ultimately prevail, and lower NYMEX pricing is probable this summer.

For further updates on the 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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