Energy Procurement Insights for January 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.

New England
Déjà Vu: Natural Gas Prices Surge Amidst Cold Spell

New England natural gas spot prices reached a new all-time high on January 5th, following a sustained cold spell and the forced shutdown of the 685 MW Pilgrim Nuclear power station the day prior. Spot gas daily prices at Algonquin City-Gates (AGT), which services the Boston metro area, settled at $78.88/MMBtu—more than $3 higher than the peak price seen during the Polar Vortex. The Pilgrim reactor shut down after one of two power lines that provide power to the facility went down. After two extremely mild winters, the recent spike in AGT prices serves as a reminder of the region’s continued vulnerability to severe cold weather conditions due to ongoing natural gas pipeline constraints.

Over the past 15 years, ISO-NE’s electricity generation mix has changed dramatically, with over 14,000 MW of new combined-cycle natural gas generation added to the grid. Last year, gas accounted for roughly half of the region’s generation mix, up from 15% at the beginning of the decade. However, the build out of pipeline infrastructure has not kept pace. During unseasonably cold days when heating demand is at its highest, insufficient natural gas supplies can lead to extreme spikes in regional gas and electricity prices.

Pipeline constraints in New England gained national attention during the Polar Vortex in 2013/14, when bitter cold temperatures almost led to rolling blackouts after much of the region’s gas-fired generation fleet was left idle due to insufficient gas supplies. AGT spot prices reached north of $70/MMBtu on two days, and averaged $16.09/MMBtu over the course of the winter. Addressing gas infrastructure constraints quickly became the region’s highest-priority challenge. However, efforts to construct significant new capacity took a major blow in August 2016 when the Massachusetts Judicial Court declared it illegal for electric utilities to contract for gas pipeline capacity for generators and pass those costs onto electric ratepayers. Without ratepayer financing or enough long-term shipper commitments, two large projects were suspended indefinitely. In their place, some smaller projects have moved forward.

Since the Polar Vortex, 454 MMcf/d of additional pipeline capacity has been put into service; the 342 MMcf/d Algonquin Incremental Market (AIM) expansion, the 72 MMcf/d Connecticut Expansion Project, and 40 MMcf/d of the 132 MMcf/d Atlantic Bridge project (the remaining 92 MMcf/d scheduled for late 2018). While notable, this only represents a 10% expansion to regional pipeline capacity. Meanwhile, demand for natural gas heating and generation continues to grow.

With no additional incremental capacity on the horizon, the region will have to continue to rely on duel-fuel capable power plants that can switch to fuel oil as well as liquefied natural gas (LNG) terminals to make up for whatever the current pipelines cannot support. The result will be continued seasonal price volatility and intermittent price spikes on cold winter days.

For further updates on natural gas and electricity prices, read our full report for this month.

New York
Indian Point Closure Not Expected to Impact Reliability

The New York Independent System Operator (NYISO) has determined that reliably will not be impacted by the retirement of Indian Point nuclear plant Units 2 and 3, which are set to close in 2020 and 2021 (see table below), as long as the planned natural gas and dual-fuel (natural gas/oil) resources come online as planned. Indian Point currently supplies approximately 25% of the electricity consumed in New York City and Westchester County.

Governor Cuomo and environmental groups have pressed to close Indian Point on safety grounds for years, as the risk of an accident of a nuclear power plant roughly 45 miles north of Times Square was determined unacceptable. Over the last 10 years, Indian Point has had several incidents, including a transformer explosion that resulted in oil spill into the Hudson River as well as 600,000 gallons of mildly radioactive steam, which was within allowable safety limits based on NRC standards, venting into the atmosphere.

Three “major generating facilities” currently under construction totaling over 1,800 MW will replace 79% of Indian Point nameplate capacity. These resources are not without complication, as the two large projects have run into permitting and environmental opposition. These issues will be discussed later in the monthly report. NYISO analyzed a scenario which removed all three of those plants and found a 100-megawatt need by 2021 and a 600-megawatt need by 2027.

Environmental groups and the Governor’s office both support replacing Indian Point through a combination of upstate renewables and Canadian hydropower imports, rather than building large conventional generators near New York City's electric load. The backbone of this plan is the 336-mile Champlain Hudson Power Express transmission line, which seeks to import 1000 MW of Canadian hydropower to serve the New York City area market. The proposed $2.2 billion project is expected to be in service in 2022.

If the transmission line and the natural gas projects come online as planned, the Lower Hudson Valley and New York City markets could see lower capacity prices and more stable power prices.

For further updates on natural gas and electricity prices, read our full report for this month.

Impact of Northeast Cold Snap

PJM customers on either a block-and-index or fully floating contract should be aware of high Locational Marginal Prices (LMPs) over the past few weeks. Unhedged customer volumes will be priced at higher-than-normal zonal LMPs. Already in 2018, West Hub saw around-the-clock day-ahead LMPs on January 2nd-4th average $139/MWh, $142/MWh, and $148/MWh, respectively, compared to the December monthly average of $36.7/MWh. Customers with any flexibility can try to mitigate a portion of these high costs by reducing usage as much as possible every hour—particularly during the peak hours in the afternoon.

PJM releases updated NITS (Transmission) Rates effective January 1, 2018

On December 18th, PJM posted Transmission updates to Network Integration Transmission Service (NITS prices as seen in the chart below). The rates are used to collect funds for Transmission service from customers, which are used to reimburse PJM transmission owners for necessary upgrades and expansions to the system. 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 system experiences peak congestion. These hours typically coincide with the periods of highest demand.

The latest (NITS) updates are effective January 1, 2018 until changed again, usually in June or July. The Ohio region (AEP and ATSI) saw more than a 20% increase in NITS costs, and the congested part of New Jersey (PSEG and JCPL) saw similar increases. Pennsylvania customers in METED and PENELEC will see increases of nearly 15%, and Dominion, covering most of Virginia, will also see Transmission costs increase by about 11%.

Customers in the aforementioned PJM zones should be aware of increasing Transmission costs beginning January 1st this year. Our customers can actively manage down peak loads throughout the year, which could effectively lower the Transmission tag for the next year. Customer Transmission tags are reset at the beginning of each calendar year.

For further updates on natural gas and electricity prices, read our full report for this month.

Real-time LMPs Spike, Exposing Risks

Record-breaking cold weather in the Midwest last week demonstrated the risk of being exposed to market prices (LMPs) even for brief periods during the winter season. As heating demand reaches the highest levels seen in five years and natural gas supply has slowed due to the cold weather, real-time LMPs have remained far higher than the average around-the-clock prices for the first week of 2018. Customers exposed to real-time LMPs—either by being on default service in zones such as ComEd or contracted under an indexed product with exposed positions—will see a significant rise in their electricity supply costs this January.

The first scenario has been common in ComEd, where the last three winters have brought historically low average LMPs under a utility tariff based on an hourly pricing mechanism. Decreasing natural gas prices, a significant increase in wind generation, and a lack of prolonged system strains have pushed hourly LMPs to all-time lows in ComEd. Customers with some or all of their electricity supply fixed under a third-party contract over this period may not have realized some of the downside gains of these historically low LMPs. When viewed purely from a price perspective, the benefits of third-party supply may become muted, causing customers to return to the utility default rate.

The Basic Electric Service Hourly Pricing (BESH) tariff structure is the default utility rate for some customers in ComEd, which is determined by prevailing real-time LMPs in the zone. Customers are charged an Hourly Energy Charge and charges are trued up through an Hourly Purchased Electricity Adjustment. While downside gains are realized when LMPs decrease, the risk of a price increase in real-time hourly LMPs is passed onto the customer entirely. While price increases are typically much larger than price decreases, under normal circumstances they are short in duration and present minimal impact when averaged over a monthly billing period. However, when real-time LMPs remain elevated for a period of a few days, the average monthly supply rate increases substantially.

As PJM saw top-10 winter days set new records for gas demand last week, real-time hourly LMPs in ComEd were significantly higher than the average hourly LMPs over the past three winters. For the last three December-to-January periods, the average around-the-clock hourly LMP has been $26.77/MWh in ComEd. Assuming the current year reverts to this average for the remainder of the period, the average around-the-clock hourly LMP in ComEd will have increased $6.64/MWh to $33.42/MWh as a result of the adverse weather last week.

Customers exposed to real-time LMPs through an hourly priced utility default rate or through an indexed product with exposed positions wear the risk of a price increase during prolonged periods of system strain. For customers on an hourly priced default rate, all of their usage is exposed to the real-time LMP, and therefore all of the risk. Customers under a block-and-index contract may be less exposed depending on how much of their usage is hedged. In either case, these customers should be aware of the increase in LMPs during the first week of 2018 and the potential impact on their electricity supply cost.

For further updates on natural gas and electricity prices, read our full report for this month.

ERCOT Wholesale Spot Power Prices Down 16% Year-on-Year in December

Last month, natural gas fuel prices plummeted more than 20% year-over-year. In addition, the recorded share of gas-fired generation increased approximately 26% over last year due to fuel switching against the backdrop of lower gas prices. Thus, December day-ahead spot market power prices fell 16% lower than this time a year ago. Aside from the observed natural gas prices and increases in gas-fired output, temperatures for the month were cooler than last year and against historic averages. As a result of mild temperatures, the measured peak load of 54,474 MW was about 6% lower than in December 2016. The monthly average day-ahead power price for December 2017 was $21.21/MWh across all hubs, whereas the average monthly spot price in December 2016 was $25.36/MWh.

Consumer demand and the cost of fuel used to produce electricity are the two primary drivers of spot market electricity prices. This past December, temperatures around the central footprint of ERCOT were overall cooler than their seasonal daytime averages for the duration of the month. On balance, the wholesale power prices were driven by lower delivered prices for natural gas when compared to last year. The monthly average natural gas price in December was $2.757/MMBtu at the Houston Ship Channel delivery point in Texas, about 20% lower than the $3.474/MMBtu average seen in December 2016. Since natural gas is the predominant fuel used to generate power in the state, electricity prices are linked closely to gas prices. 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 54,475 MW in December 2017, which is about 6% lower than the December 2016 peak load of 57,968 MW. The average daytime high temperature for Austin, TX in December 2017 was 62 degrees Fahrenheit, which is slightly cooler than historical averages. Aside from the observed temperatures and lower natural gas prices, power prices remained in check as a result of stable wind generation year-over-year.

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.

For further updates on electricity prices, read our full report for this month.

Production Freeze-offs in Texas Could Mean Higher Gas Prices for Southern California

While California’s temperatures remain above-normal for this time of the year, the rest of the country endures much colder temperatures, which can test energy infrastructure. Cross-state natural gas pipelines make California susceptible to these issues. In particular, natural gas production and transportation from Texas to California via the El Paso and Transwestern pipelines, as well as production in the Permian Basin, can lead to price spikes in the gas market in California. However, the long-term forecast indicates that basis pricing in the region could come down as spring approaches.

The figure below represents major interstate and gas resource areas for California. SoCalGas and PG&E connect to El Paso and Transwestern pipelines at the southeastern tip of California. The gas traveling along these pipelines primarily originates from the Permian and Anardarko basins in Texas. As a result, upstream price spikes at these basins or along the routes can have downstream implications for the California market. The severe cold in Texas seen last week can lead to production freeze-offs or periods in which temperatures at production sites dip below freezing, potentially causing a loss of production on those days. In addition, pipeline pressure can drop below operational minimums from the cold. Midland, Texas, saw a low of 11 degrees, when seasonal averages call for a low tend to be around 30 degrees.

However, despite the bullish indicators, prices have not moved up due to the recent cold temperatures. The rolling strips for SoCal Citygate are close to the lows seen last winter. In addition, the rolling strips at the Transwestern pipeline near the Permian basin dropped significantly over the holidays. The result is likely due to the extended forecast switching to above-normal temperatures for the region in the next several weeks, and long-term forecasts predicting a milder second half of the winter season.

Basis pricing in California could continue to slide if the forecast holds up. Customers will likely benefit from holding off on purchasing basis contracts. However, long-term weather forecasts can be unreliable. Risk-averse customers may want to considering locking in basis and avoiding the weather speculation.

For further updates on electricity prices, read our full report for this month.

Regulators Establish Rules Around ‘Self-Supply’ Generation

The Energy Regulatory Commission (CRE) has set forth its rules around self-supply for large industrial customers, which will allow them to operate behind-the-meter generators to serve their own load and also to sell any excess generation back to the grid or to specific third-party off takers. The publishing of these rules helps flesh out necessary details under the new deregulated market and provides assurance to customers that have invested in self-supply generation or intend to do so. The CRE to date has already issued 45 self-supply permits totaling over 600 MW of capacity.

Customer with significant load may consider self-supply as an alternative energy solution to power their sites instead of relying on default service with the CFE, short-term third-party supply contracts, or PPAs. Given the long-term nature and large capital requirement of self-supply, customers should carefully weigh the pros and cons of the self-supply option compared with the many other options currently available.

A long-term view of future electricity and fuel prices is essential to evaluating energy supply options. Self-supply may make sense for specific customers under some circumstances, but it is important to take full survey of all options now available under the newly deregulated market.

For further updates on electricity prices, read our full report for this month.

Henry Hub
Volatility Reigns with Strong Supply, but Winter Risk Lingers

2018 is expected to be a critical year for gas pipeline infrastructure construction and the elimination of the gas glut from the Marcellus shale. In total, 2018 is scheduled for 27 infrastructure projects moving low-priced shale gas to higher-priced markets in the Midwest, Northeast, and Southeast. Simultaneously, daily gas production is expected to continue to set records throughout 2018, likely eclipsing 80 Bcf/day, according to several prognostications from Platts. The market needs to balance the upward trend in production with the new demand sources. As a result, NYMEX pricing has rediscovered volatility, with the prompt February contract showing a recent range from $2.56-$3.10 as it rolled to the prompt position. The current situation is proving to be unique compared to the market reaction seen in the previous two years, and likely calls for a reevaluation of supply contracting strategy as a result of the shift in the forward curve.

The dynamic nature of the current forward market has allowed for the breakout of the price consolidation seen throughout 2017, and will likely continue to allow for volatility throughout 2018. With such a supply-heavy equation, it is difficult to justify paying even a small premium for the out years. It is possible this curve will once again backwardate, similar to the previous few years, which would again make longer-term supply deals a logical choice. In the meantime, gas consumers should be looking for a dip in forward pricing with a minimal year-over-year risk premium. In addition, shorter-term supply contracts may be prudent so long as there is a premium in pricing farther down the curve.

For further updates on the natural gas market, 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