Energy Procurement Insights for August 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, EnerNOC'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
Massachusetts SREC Costs Set to Decrease in 2019

The Massachusetts Department of Energy Resources (DOER) releases an annual mandate of what percentage of power supplied in the state must come from solar resources each summer. According to recent preliminary figures from the DOER, the solar carve-out program’s compliance requirement will decrease year-on-year in 2019 for the first time since its inception in 2010. Next year, electricity suppliers and utilities will be required to purchase Solar Renewable Energy Credits (I & II) to cover 5.75% of the electricity they serve, down from 6% this year. Based on current prices, the preliminary reduction will lower SREC costs under the state’s Renewable Portfolio Standard (RPS) by $0.0015/kWh in 2019. As a result, any customer with an SREC II expansion pass-through contract should see some price relief on that line item starting January 1, 2019.

The Massachusetts solar carve-out programs were designed to provide economic support to expand solar installations across the Commonwealth. The original program, referred to as SREC I, was initiated in January 2010 and targeted development of 400 MW of solar PV across the state. The second program, referred to as SREC II, was launched in 2014 with the goal of installing an additional 1,200 MW of solar by 2020. Due to the success of the second program, the cumulative 1,600 MW cap was reached three years ahead of schedule in early 2017, and the state was forced to expand the program through 2018 as it prepared to launch a new solar incentive program, the Solar Massachusetts Renewable Target (SMART).

Paying for the SREC programs has not come without controversy as electricity marketers, and in turn ratepayers, have had to purchase increasing amounts of expensive solar power credits over the last several years. As shown below, total RPS costs, which are bundled into electricity supply rates in Massachusetts, more than quadrupled between 2012 and 2018, increasing from roughly $0.005/kWh to $0.021/kWh.

While RPS costs on the supply bill are expected to plateau for a couple of years starting in 2019, the DOER is in the process of implementing its new solar incentive program, the cost of which will likely begin to be recovered from ratepayers next year. The new SMART program will differ from the current SREC program in that costs will be recovered via utility distribution charges instead of through RPS on the supply bill, which to date are unknown.

Please reach out to your Energy Advisor or Account Manager if you would like to better understand how these developments affect your supply costs or energy budget.

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

New York
Offshore Wind Moving Forward

New York Governor Andrew Cuomo announced earlier this month that he is authorizing New York State Energy Research and Development Authority (NYSERDA) to procure 800 MW of offshore wind. NYSERDA expects to release the RFP at the end of 2018 and award the project in 2019. The projects are anticipated to be online by 2024/2025.

NYSERDA will be responsible for the administration of Offshore Renewable Credits (OREC). NYSERDA will procure OREC from offshore wind resources and sell them to each utility and third-party supplier serving retail load in New York. This is the first step to achieving the state’s goal of 2,400 MW of offshore wind by 2030, and further validation that offshore wind is one of the key components of New York reaching its goal of having 50% renewable resources by 2030.

Beyond helping the state achieve Clean Energy Standard targets, the offshore wind project will provide several additional benefits. The integration of 2,400 MW by 2030 could account for nearly one-third of the carbon reduction New York is looking for. Additionally, by jump-starting the program, there are ancillary potential economic benefits, including job growth of a nascent industry and significant investments in coastal infrastructure and communities. Finally, due to its proximity and direct access to New York City and Long Island, the project should provide renewable energy and provide supply diversity to the region where demand in the state is highest.

Although highly supported, the proposed offshore wind projects are not without their detractors. The fishing industry is concerned that the projects will jeopardize their livelihood even though the affected area represents less than 5% of the area. Another party with objections to the project is the Independent Power Producers of New York (IPPNY), which prefer the offshore wind projects compete without the need for separate subsidies. They believe that wholesale prices incorporating carbon pricing (see July 2018 Commentary) should provide the incentives for new carbon-free projects. 

In addition, there is still some debate as to the procurement options for OREC. New York State’s Master Offshore Wind Master Plan highlights seven options. The two most likely procurement options are Market OREC and Fixed OREC. The Market OREC supporters favor a structure that sets the net payments to the offshore wind producers and adjusts the OREC based on wholesale energy and capacity prices. This method is what NYSERDA is using to administer the Zero Emission Credit program. On the other hand, Fixed supports are looking for price certainty in the OREC payments for the duration of the contract.

Generating electricity with offshore wind turbines is not profitable under current market conditions. Therefore, New York’s effort to “jumpstart” will come at a cost. The exact costs for customers are still unknown until the state decides on the subsidies, but we can look at two recent procurements to get an idea of the magnitude. On the high side, Maryland recently approved offshore wind projects that will get $131.93 for each MWh generated, and that is in addition to the amount for which they can sell their power. More recently, a group of Massachusetts Electric Utilities filed long-term contracts to purchase 800 MW of offshore wind energy at a rate of $65/MWh for the energy and renewable credits, excluding capacity. Based on this information, we can conclude that the offshore project could add between $0.0012 and $0.0027/kWh to the electric bill when the projects come online in 2024/2025.

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

Mid-Atlantic
PJM System Peak Predictor 2018 Halftime Review

PJM calculates customers’ capacity tag charges based on a Summer (June – September) five coincident peak methodology, meaning that each customer’s load during the five periods when the system is at its highest levels of demand between June and September will determine their capacity tag.

On average, nearly 20% of a customer’s bill in PJM consists of the capacity charge component. This charge is calculated by taking an account’s capacity tag and multiplying against the predetermined PJM Zonal Net Price in $/MW-day and associated scaling factors. Local utilities will adjust customer capacity tags for weather normalization and other factors as needed.

EnerNOC manages a System Peak Predictor program that notifies customers in PJM to reduce demand when summer peaks occur, otherwise known as a capacity management program. By taking part in this program, customers lower their demand when the system is peaking and therefore reduce the capacity tag component of their cost. Through July 31, EnerNOC has called six red days and has caught the five highest PJM coincident peak days. The chart below shows EnerNOC’s performance based on PJM Peak Daily metered loads from June 1, 2018 through July 31, 2018. Note: the black vertical bars represent weekends or holidays, which are not included in PJM's 5 Coincident Peak day calculation.

The table below shows four years of history compared to the current year through July.

Weather is the largest driver of high electricity demand during the summer. The chart above shows the correlation between a warm weather pattern lasting two to three consecutive days and high peak loads recorded in PJM. For future reference, the National Weather Service’s Climate Prediction Center shows the second half of this summer’s temperatures in the PJM footprint to be slightly warmer than average in the 8-14 day, one-month, and three-month outlooks.

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

Midwest
Subsidized Generation Continues to Get Attention at State and Federal Levels

Over the last couple of years, as renewable capacity has grown within the PJM footprint and demand growth has been low, the wholesale markets have reacted accordingly. Wholesale energy prices are at historic lows, and capacity prices are significantly higher across much of the market. Unfortunately, renewable generation is making it harder for more capital-intensive generation (coal and nuclear) to compete, as energy market prices are driven lower. As more nuclear generation is at risk for shutting down, some states have taken measures to subsidize the generation—sparking fears of interfering with competitive market processes.

While subsidized generation is nothing new (Production Tax Credit – PTC; Investment Tax Credit – ITC), state-sponsored programs have been gaining more traction recently. New York paved the path for state-subsidized nuclear generation in 2015. “Renewing the Energy Vision,” or REV as it’s referred to, was implemented to support New York’s move to be a leader in carbon emission reduction. In 2016, Illinois became the first PJM state to pass legislation to subsidize several nuclear units and update state renewable portfolio standards (RPS). Most recently in 2018, New Jersey became the second PJM state to implement an overhaul to the state RPS that included zero emission credits (ZECs) to keep several nuclear units from retiring.

As more states move towards adopting ZEC programs and overhaul RPS requirements, court challenges are mounting. New York and Illinois both currently have court cases challenging the subsidies. However, as recently as May 2018, both the FERC and the Department of Justice issued a joint brief “in support of Illinois nuclear subsidies,” according to Utility Dive. The article also goes on to highlight that both FERC lawyers and the DOJ do not find that ZECs interfere with FERC’s ability to “regulated wholesale power markets” and that “the legal opinion will likely also apply to…New York nuclear subsidies, as well as a New Jersey subsidy program.”

It has been a tumultuous 18 months in wholesale energy markets as the federal government seems poised to introduce baseload generation subsidies. Although the Federal Energy Regulatory Commission (FERC) rejected the Department of Energy’s (DOE) Notice of Proposed Rulemaking earlier this year, the current executive administration has expressed interest in finding a way to support coal and nuclear units in the market. In preparation for the impact of additional subsidized generation in competitive markets, PJM submitted two proposals to FERC to offset market inefficiencies in March 2018. Both proposals were rejected outright by FERC—this included the revised price floor and two-part capacity auction. FERC suggested adding the ability for individual resources to opt out of participating in PJM’s capacity markets, a potentially detrimental rule revision that could lead to a less efficient market, according to Calpine.

As the debate over subsidized generation evolves over the next few months and new market rules are established, customers should understand that certain decisions could lead to increased costs. Renewable energy will continue to stifle energy market prices in the interim and drive up capacity costs in the long term. Eventually, significant investment in demand management and distributed energy resources will likely become necessity to offset future increases in electricity costs.

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

Texas
July Real-Time Pricing Passes Resilience Test

July 2018 proved to be a real test for the resilience of the ERCOT grid and highlighted the ability for the RTO to respond to extreme weather across the region.

Demand in ERCOT started the month elevated as an extended period of above-average temperatures in the region came to an end after the Fourth of July holiday. The break in temperatures lasted roughly a week and a half until the week of July 15, when an extended period of extreme temperatures moved across Texas, hanging over the major load zones of Dallas, Austin, Houston, and San Antonio. A succession of days in excess of 100 degrees Fahrenheit created a climate of historic demand. A six-day period from July 18 to the 23 saw high cooling demand help achieve the largest and current system-wide peak demand of 73,259 MW on July 19, exceeding the previous system-wide peak record of 71,110 MW.

Spot market pricing in ERCOT, however, remained relatively contained compared to expectations. The ATC power forwards for July at North Hub entered the month around $57/MWh on fears of the grid being unable to respond to anticipated record demand. Daily LMPs, both day-ahead and real time, stayed below the $50/MWh level until the extreme temperature pattern in the back half of the month. During that time, day-ahead LMPs shot up as fears of grid resiliency likely worried market participants. However, by contrast, real-time LMPs over the same period rarely reached any emergency levels and averaged below $50/MWh a day for most of the days. Wrapping up the month, the monthly day-ahead average ATC LMP at North Hub is $78.97/MWh, while the real-time average is $41.47/MWh, a drastic departure from the day-ahead fears.

The August 2018 forward contract faced significant downward pressure throughout June and into July as real-time LMPs proved the grid could accommodate the record demand levels. The North Hub August monthly contract reached a top near $150/MWh for the ATC strip in early June before rolling off the board a few days ago at $70.22/MWh, a nearly 53% decline as the reality of the flexibility of the ERCOT grid sets in. Early temperature forecasts for August do not show any significant hot spells, but the August peak record is anticipated to be broken. While temperature forecasts drive worry and fear across the RTO, the grid has proven its resilience in the face of extreme demand.

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

California
High Temperatures Push California Grid and Pipelines to the Brink, Prices to New Heights

Peak temperatures in the Los Angeles area broke into triple-digit territory and sustained levels near 90 degrees for several days in a row. Due to high natural gas demand for gas-fired generators, gas prices at the SoCal city-gate soared to a new record high above $39/MMBtu, shattering the previous record set this past February of about $19.50/MMBtu. The demand for natural gas on the SoCal Gas system was similar to levels from this past winter around 3 Bcf/d; however, a number of pipelines on the system are out of service as the company performs maintenance. As a result, power prices also spiked. On-peak prices for southern California’s SP-15 pricing point moved above $80/MWh, with individual trades exceeding $300/MWh.

On Wednesday July 25, the SoCal Gas Company briefly issued a curtailment order to gas-fired generators and set the necessary pretense for a supply extraction from the Aliso Canyon storage facility—a resource that has been designated by the state as a resource-of-last-resort since its months-long leak in 2016. Ultimately, the company called off the curtailment order later that evening and no gas was extracted from Aliso Canyon.

Perhaps not coincidentally, the board of the California Independent System Operator (CAISO) signed off on the organization moving forward with talks on reliability designations for natural gas-fired power plants. The plants, the 54 MW Ellwood and 741 MW unit at Ormond Beach, will now begin negotiations with the ISO on Reliability Must Run (RMR) contracts, which will provide sufficient financial support to keep the units online when the ISO expects they will need the capacity as soon as 2020.

The recent stretch of high prices has had significant impacts on the rolling strip prices. While prices across contracts have climbed slowly from $30/MWh in February to the $34-$36 range, the recent heat wave sent the rolling strip prices above $38/MWh for the 24- and 36-month contracts and exceeded $42/MWh for the 12-month strip.

Customers with immediate needs to sign a power or gas contract should look to sign short-term agreements. Market prices are being heavily influenced by the near-term weather events and we expect prices to rebound lower over the next several weeks as moderating seasonal weather patterns return.

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

Mexico
CFE Capacity Prices Have Grown as Much as 138% Since December

The Mexican electric utility, CFE, was required to unbundle the components of its tariff under the market deregulation law. The first such unbundled tariff was published in December 2017, though the transition to the new tariff faced challenges in the first few billing cycles. After significant price jumps in the January tariffs, the national energy secretary (SENER) sent the CFE back to the rate-making drawing board, and in February the December and January tariffs were retroactively revised downward.

CFE capacity rates under the two main industrial rate classes (DIST and GDMTH) have more than doubled since December in certain cases and increased more than $100 MXN/kW-month in all cases. In December, capacity prices with the CFE ranged from about $130 to almost $200 MXN/kW-month across regions and rate classes. Since then, prices have increased nearly monotonically with prices in all regions and rate classes eclipsing the $300 MXN/kW-month mark.

To some extent, we expect this price climb to be driven in part by seasonal demand patterns. In that context, we would expect some price softening to begin in August or September. The true test will be to see the year-over-year price change. Without insight into how the CFE is calculating these prices, it is difficult to forecast prices for the next six months.

These rates are published each month with no forward insight into prices. The uncertainty means that customers do not know what they will pay until the month already begins, and there is no way to budget in advance for the changes. Customers exploring third-party contracts have had success mitigating both the soaring capacity prices and price uncertainty. Many suppliers are able to offer capacity prices well below posted utility rates, and contract structures can lock-in and guarantee those prices for terms ranging from one to five years. Customers requiring budget certainty or looking for price relief from the tariff rates should consider third-party supply.

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

Henry Hub
Gas Supply, Demand Near Record Levels; Growth Expected to Continue

Natural gas production kicked into another gear in July 2018. The record daily production applied downward pressure to NYMEX and upward pressure to many Northeast and Midwest basis points. The inverse relationship between NYMEX and Northeast basis pricing is related to the build-up of the pipeline infrastructure. The elimination of the gas glut in the Northeast applies upward pressure to regional basis. Simultaneously, this makes room for additional supply to come from the Northeast, which applies downward pressure to NYMEX pricing. Midwest basis pricing is up because of power generation growth and low storage levels. Dry gas supply across the lower-48 states averaged 80.6 Bcf/day for July 2018, an increase of around 1.7Bcf/day versus June and up 2.4 Bcf/day from May 2018. Production growth has been consistent throughout 2018 and is projected to continue for several years. During the next 12 months, this additional supply will be necessary to refill storage closer to historical benchmarks. 

Additional sources of demand growth will come from gas-fired power generation and growing LNG exports and pipeline exports to Mexico. Current gas storage trails last year by around 688 Bcf (23%) and the five-year average by around 565 Bcf (20%). Record-level production is bearish for NYMEX forward pricing. However, pricing may turn upward if gas storage does not close the gap with last year and the five-year average by this time in 2019. Temperature forecasts for winter 2018/19 and summer 2019 will be crucial. If the upcoming winter and summer have extended periods of extreme weather, NYMEX pricing is more likely to rise. Current forecasts for winter 2018/19 do not call for extremely cold temperatures. The graph below shows dry gas production in the lower 48 states from May 1, 2018-July 31, 2018.

Demand for natural gas this summer has trended above normal since early May, and forecasts call for the growth trend to continue. Through July 31, 2018, this summer has proven to be the hottest since 1950, based on data from NOAA. Temperatures only briefly dipped below normal from May 1-July 31, 2018. The hot temperatures magnified the migration toward natural gas from coal for power generation over the past five years. S&P Global calculates that sample burn per degree is up 1.2 Bcf/day versus last summer as a result of the switch to natural gas for generation. The increased burn per degree means that even if temperatures were equal to last summer, demand for gas power generation would exceed last year by 1.2 Bcf/day. The increase in burn per degree will likely accelerate due to the growing reliance on natural gas for power generation in next 1-5 years. The fundamental factor behind the move to gas is economics; gas is cheaper than coal in almost all regions except for ERCOT North. This trend will likely continue once the pipeline infrastructure is built to alleviate the current gas glut.

Power generation from natural gas continues to exceed expectations and lead the demand growth. Summer 2016 saw record levels for power generation. Since May 1, 2018, gas consumption for power generation in 2018 is slightly outpacing the same period in 2016. The chart and table below show the average daily power burn from May through July from 2015 to 2018.

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

Authored By The EnerNOC 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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