Energy Procurement Insights for June 2017: 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.
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 EnerNOC's energy procurement services here, and talk to one of our experts here.
On June 1st, a 1,500 MW power plant located in the southeastern New England town of Somerset, Massachusetts, closed its doors for good. Energy Capital Partners (ECP), the plant’s former owner, had announced the closure of Brayton Point Power Station, New England’s largest remaining coal-fired generator, in January 2014. The current owner, Houston-based Dynegy Energy Inc., who purchased the plant from ECP in a deal with nine other generators, never showed any inclination to reverse the decision of their predecessor. During its retirement announcement, ECP noted the long-term economic challenges that lay ahead for the coal plant, which had been in service since 1963. Low natural gas prices, as well as increasing environmental compliance costs, have resulted in a growing trend of coal power plant closures across the US in recent years.
Although a significant power plant in regards to nameplate capacity, Brayton Point had been dispatched less and less to meet regional power demand since its retirement announcement in 2014. However, its importance lay in the fact that its fuel source, coal, added diversity to a region heavily reliant on natural gas. According to ISO-NE, while coal’s share of total kilowatt-hours generated barely reached 0.3% in May 2016, that figure climbed to 6.5% in December 2016 (or 11% of non-natural gas generation sources).
During 2016, Brayton Point had an average capacity factor (the ratio of kW output to nameplate capacity) of only 14%, but that figure reached nearly 35% in the winter. Cold temperatures in New England can put pressure on natural gas supplies, as gas is required for both home heating and for electricity generation. While natural gas is an abundant resource in the US, the current pipeline infrastructure in New England limits its availability to power plants under extreme cold conditions. In 2016, New England spot prices reached their lowest level in 13 years following the mildest winter on record—however, that’s not to say extreme weather isn’t likely to return in the future. If polar vortex-like conditions return, the absence of Brayton Point will lend upward pressure on spot prices next winter.
Read our full report for updates on electricity and natural gas prices this month.
In its New York 2017 Summer Preparedness Report, the NY Department of Public Services (NY DPS) declared that the grid has 41,013 MW of generating capacity ready to meet the forecasted 33,178 MW peak demand for this upcoming summer. The planned generation also fulfills the NYISO’s required Installed Reserve Margin (IRM) of 18%, which assures there is sufficient capacity in the case of unscheduled power plant outages or lost transmission lines.
While the NY DPS report does ease reliability concerns for the upcoming summer, it also signifies the likelihood that power prices will remain higher than the historically low levels seen on the market in 2016. NYISO’s forecasted peak of 33,178 MW for this summer would be the second highest peak in the past five years. The only peak higher in the past five years would be the one observed in the summer of 2013, which was the highest peak in New York’s history, measured at 33,956 MW. This summer’s forecast also represents a significant increase from last summer’s peak of 32,075 MW which was reached on August 11, 2016.
A positive note from the NY DPS report was that the updated long-term forecast shows peak demand stabilizing going out to 2027. In previous 10-year forecasts, peak demand showed a steady rise, which would require more generation resources. However, this latest forecast shows expectation for flat peak demand. This is mostly due to increased conservation and efficiency efforts in the state.
In addition to market demand, the price of fuel is a major driver for the cost of power. In New York, approximately one-third of the state’s generator fleet burns natural gas to produce power. Natural gas-fired power plants are also most often the market participants which set the price of electricity. Therefore, with higher natural gas prices being delivered to the Transco Zone 6 New York trading point, it is unsurprising that power prices have also been higher than the levels seen a year ago.
Read our full report for updates on electricity and natural gas pricing for this month.
Capacity prices in PJM's recent 2020/21 Base Residual Auction dropped for most of the RTO compared to the prior year, but cleared higher for Eastern Mid-Atlantic Area Council (EMAAC) (AE, DPL, JCPL, PECO, PSEG, RECO) and the DEOK zone. A lower overall load forecast, combined with nearly the same amount of available capacity, contributed to the drop in capacity prices for most of the RTO.
EMAAC and DEOK cleared higher due to locational constraints (transmission facility limitations or voltage limitations) and retiring generation. The 2020/21 Capacity year is the first where all assets are under the Capacity Performance initiative. This initiative brings forward steep penalties for non-performance and resources are expected to be available all year long.
Read our full report for updates on regional electricity and natural gas basis pricing.
In recent years, the ComEd capacity clearing price has been among the highest in PJM, implying a need for new and lower-cost generation in the zone. Capacity charges make up approximately 25% of the total cost of electricity supply.
However, in the recent Base Residual Auction for 2020/2021, the ComEd zone cleared 139% over the RTO rate of $76.53/MW-Day. A typical 1 MW ComEd customer consuming roughly 9,000,000 kWh annually will spend about $80K on capacity costs in the 2020/2021 delivery year, compared to about $28K in other areas of PJM. The costs are included in the overall rate you receive from your supplier or the utility. The results from PJM’s annual Base Residual Auction underscore the challenges that high-cost, baseload generators face in the realm of persistent low-power prices across PJM. For example, Exelon’s Quad Cities Nuclear Generation Station, located in the ComEd zone of PJM, did not clear a capacity auction price of $183.14/MW day for the 2020-2021 delivery year.
The ComEd zone is the western-most region of PJM, covering most of northern Illinois from Chicago to the Mississippi River. The zone has an overwhelmingly large number of aging nuclear facilities compared to the rest of PJM. As depicted in the charts below, nuclear generation represents over twice the amount of capacity in ComEd compared to the rest of PJM. In addition to a large aging nuclear fleet, ComEd’s generation mix also contains a larger number of low-cost natural gas and three-times the amount of wind generation.
Low natural gas prices and cheap wind resources have kept power prices low in the ComEd zone. Meanwhile, the operating costs of older sources of generation continue to be high, and these generators have found it increasingly difficult to operate profitably without additional income. The result is higher prices in the zone’s capacity market, as the large number of financially stressed generators bid up the cost of providing reliable capacity.
The capacity market is a mechanism that sends long-term price signals to generators that new generation may be needed in a particular zone. The high capacity prices in ComEd have indicated this need in recent years. However, the most recent PJM capacity auction illustrates how even high capacity prices may not be enough to aid existing high-cost generation. Exelon’s Quad Cities supplies 1,364 MW of capacity to PJM, 4.5% of ComEd’s total capacity. Quad Cities not clearing the capacity auction means the generator needed more than $183.14/MW day of income, a cost paid directly by consumers for reliability, to operate profitably in the zone. As a result, Quad Cities will not receive capacity payments, potentially forcing the unit to close in the future, but it is able to bid into the energy markets and receive energy payments.
Customers can mitigate the increasing costs over the next few years by participating in programs like Demand Response and/or System Peak Predictor through EnerNOC. Through a combination of proper supply contract structuring and demand management, customers in ComEd stand to avoid up to $90,000/MW-Year.
Read our full report to learn how a delay on construction of the Rover pipeline could affect energy prices in the region.
Last month, stronger demand and higher natural gas prices drove day-ahead spot market power prices for May 42% higher than in the same month last year.
Aside from the rebound in natural gas prices, which were at historic lows last year, warmer weather played a key role in driving higher grid demand and spot prices. In fact, due to the warmer weather, the measured peak load of 59,327 MW was more than 2,100 MW higher than in May 2016 and the highest monthly peak demand seen since 2011. The monthly average day-ahead power price was $25.90/MWh across all hubs, whereas the average monthly spot price in May 2016 was $18.25/MWh.
Consumer demand and the cost of fuel used to produce electricity are the two primary drivers of spot market electricity prices. In May, temperatures in the central footprint of ERCOT were generally above seasonal daytime averages, featuring a number of days in excess of 90 degrees Fahrenheit. On balance, the wholesale power prices were propelled higher by delivered prices for natural gas. The monthly average natural gas price in May was $3.241/MMBtu at the Houston Ship Channel delivery point in Texas, about 75% higher than the $1.855/MMBtu average seen in May 2016. Since natural gas is the predominant fuel used to generate a significant share of power in Texas, the price of electricity is closely linked to the cost of natural gas. 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. ERCOT system demand peaked at 59,327 MW in May 2017, which is 4% higher than the May 2016 peak load of 57,210 MW. The average daytime high temperature for Austin, TX last month was 88 degrees Fahrenheit, which is three degrees warmer than historical averages. Aside from the observed temperatures and higher natural gas prices, power prices remained in check as a result of increased nuclear and wind generation year-over-year. Nuclear generators increased generation share by 29% and wind generation’s portion grew by 30% when compared to the same month last year, while coal generation’s share fell 1%.
ERCOT’s sufficient generation reserve margins continue to provide adequate resources to produce low-cost energy generated by a diverse portfolio of renewables, natural gas, coal, and nuclear units.
Read our full report for this month to learn how Lubbock Power and Light's integration will impact the ERCOT grid, as well as updates on electricity and natural gas prices in the state.
Breaking a two-month streak of price decreases, the Mexican utility, the Comisión Federal de Electricidad (CFE), announced that the default rates for users of more than 25 kW will see an increase in electricity prices in June. Residential and smaller customers, however, will see a slight decrease in rates for the same time period.
Industrial customers will see a tariff rate increase between 0.5% and 1.1%, while commercial customers will see an increase of about 0.3% relative to the tariff rates in May. As is the formula for the CFE default tariff rates, the prices are determined based on commodities prices, which are the main cost for electricity generating units. The small price increase to large customers and small price decrease for residential customers reflect the small change in commodity prices between April and May.
CFE’s monthly updates to the tariffs can be problematic for power customers that require more budget transparency and certainty—particularly when prices are increasing. The growing stable of third-party suppliers is offering increasingly competitive rates that can provide both cost relief and greater budget certainty. EnerNOC is actively working to vet new entrants to the supplier market and can assist customers in finding and choosing the best independent contract to manage their costs and risk at the most competitive price.
To learn more about navigating the Mexico’s newly competitive energy markets, register for this upcoming webinar at Energy Manager Today.
And check out our full report for this month for predictions on electricity price trends in Mexico this summer.
Currently, the key market fundamental to watch in the natural gas market is the status of the storage inventory, specifically as it compares to the five-year average. Over the course of the last year, the amount of available natural gas has been in a state of oversupply. This is due to both last year’s mild temperatures, which kept both heating and cooling demand low, and the continued strong production from the shale basin region. As a result, excess natural gas has been injected into storage facilities across the county. With the amount of natural gas in storage over 2016 at all-time high, natural gas prices have been significantly suppressed.
Due to the cheap natural gas prices, power generation resources have begun to rely on natural gas as the primary input fuel for meeting electricity needs. Therefore, as we move into the summer season, we would expect to see cooling demand have a large impact on natural gas consumption and cause summer injections into natural gas reserves to be smaller.
However, this phenomenon is not a given. Last summer, we witnessed relatively low levels of demand and historically high levels of natural gas reserves. And currently, as of the storage data report on June 8, the storage level is 2,631 Bcf, which is 237 Bcf (9.9%) above the five-year average. This indicates that we’re still facing an oversupplied market.
Going forward, though, the current natural gas surplus against the five-year average is expected to erode by late August 2017. The timing of this development, if it does occur, will have a major impact on not only summer gas pricing, but all the way through winter 2018.
On the other hand, if the market is able to increase production as expected, then perhaps the surplus can be maintained. This would likely keep near-term gas pricing in the low $3/MMBtu range, which we have seen in early 2017. A production increase of around 3 Bcf/day is likely needed to safeguard the surplus to the five-year average.
Ultimately, a state of surplus is a good thing for our customers, as it ensures low natural gas pricing and favorable market conditions for all end-users.
Read our full report for this month to see how weather forecasts are affecting natural gas prices.