Energy Procurement Insights for December 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,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
ISO-NE’s Regional Outlook: Confident on Reliability but Expecting Further Complexity

In early November, New England’s grid operator, ISO-NE, released its 2017 Regional System Plan (RSP17), which details current forecasts for load growth as well as resource and infrastructure requirements to meet expected demand for the coming 10-year period. The report outlines several key findings:

  • New England has procured sufficient resources to meet expected summer peak load through 2021. However, with over 1,500 MW of coal- and oil-fired generation retiring in the past year, in addition to the planned retirement of 600 MW of nuclear in 2019, fuel diversity in the generation mix is lacking. The availability of natural gas for electricity production remains a concern during extreme winter weather conditions.
  • While gross peak load is expected to climb by roughly 1% over the 10-year planning horizon, further expansion of behind-the-meter (BTM) solar and energy efficiency measures are forecasted to decrease net energy consumption by 0.6% every year over that same period.
  • Although increased development of intermittent renewable generating sources continues to lower emissions from electricity generation in New England, they pose new challenges for reliability.
  • ISO-NE is contemplating rule changes to accommodate state policies and reinforce the competitiveness of the wholesale energy and capacity markets.

Natural gas pipeline constraints are not a new problem for the New England region, which has become increasingly dependent on the fuel for both home heat and electricity generation (it accounted for over 50% of power production last year). When gas is in short supply, it can cause day-ahead and real-time power prices to spike. The threat of extreme cold continues to keep forward prices highest in the winter months in New England. As of December 6, the most expensive ATC Mass Hub forward in the next calendar year (January 2018) was $45/MWh greater than the least expensive (September 2018). The addition of new generation from natural gas-fired plants—particularly as traditional baseload sources of coal and nuclear are in line to retire—is likely to exacerbate the issue.

ISO-NE views the growth in BTM solar and energy efficiency measures as a major factor mitigating the on-going issues with natural gas. Growth in hydroelectric, as well as on- and off shore wind resources, will also act to temper the effects of gas shortages. However, further penetration of non-traditional intermittent resources will introduce additional costs on the system as balancing supply and demand becomes more challenging.

Further complicating issues are the recent spate of state policies aimed at incentivizing growth in certain renewable technologies, which may have some far-reaching consequences on the ability of the wholesale electricity market to function in New England. For instance, last year, a piece of Massachusetts legislation passed requiring electric distribution companies to solicit 10-year power purchase agreements with a variety of wind and hydroelectric power providers. Left unchecked, this would distort the market by including essentially subsidized resources. In hopes of addressing some of these problems, ISO-NE has put forth a framework for competitive auctions with “sponsored policy resources” (CASPR) to be discussed in 2018. The goal is to balance the desire of states to advance their policy objectives but also preserve the price signals needed to ensure that unsponsored resources would still enter the marketplace.

The findings in RSP17 indicate that while the grid continues to reduce emissions and improve reliability and resiliency, there is little to suggest that any major cost relief is on the horizon. If anything, it seems to hint at cost increases in order to manage and maintain an increasingly complex generation and transmission landscape.

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

Michigan Reliability Mechanism Price Released in Late November

In September, Enel X provided an in-depth analysis of Michigan Public Act 341 (PA 341) which alluded to significant market changes that could introduce additional procurement complexities for market participants and end users. PA 341 was instituted to ensure Michigan’s power reliability by requiring utilities and suppliers to demonstrate forward capacity for four years. The State Reliability Mechanism (SRM) provides the price at which customers who remain with or default back to the utility will pay. All end users who participate in the Retail Open Access (ROA), or “choice” program, will not be subject to the SRM charge as long as their supplier demonstrates on their behalf for the full four-year SRM term.

On November 21, Detroit Edison, Consumers Energy Company, and the smaller upper-peninsula co-operatives submitted SRM pricing to the Michigan Public Service Commission (MPSC). The chart below shows the SRM price submitted by each utility in Michigan. While the SRM has come out significantly below the Original Utility SRM request of $700/MW-Day in the Lower Michigan Peninsula, prices in the Upper Peninsula ended up much higher in some cases.

Although the SRM is now released, there is still some uncertainty around customer-switching rules. Customers that have only procured a portion of the first SRM period will need additional clarifications from suppliers and the MPSC on how the capacity demonstration period will be divided amongst the suppliers and customers’ obligations to former suppliers. PA 341 notes that the deadline for suppliers and utilities to demonstrate capacity occurs on the 7th business day of February, or February 8th, 2018. Enel X is expecting the MPSC to release additional details later in December to further clarify supplier and end-user responsibilities around mid-SRM period switching.

For customers that do not have their energy procured beyond June 2018, Enel X recommends going to auction in the first two weeks of December, or immediately after the beginning of 2018. Suppliers might need additional lead-time to settle and determine capacity obligations with their generation sources. The risk associated with waiting until the latter half of January is centered on capacity price volatility and supplier liquidity. If a customer does not contract before the demonstration date of February 8th, then they could be labeled as “non-compliant” and be forced to pay the SRM price for their respective utility, as well as lose the ability to participate in the ROA choice pool.

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

ERCOT Wholesale Spot Power Prices up 19% Year-on-Year in November

Last month, natural gas fuel prices rose nearly 19% year-over-year. In addition, recorded coal generation increased approximately 10% over last year due to fuel switching against the backdrop of higher gas prices. As a result, November day-ahead spot market power prices were 19% higher than prices at this time a year ago.

Aside from the observed natural gas prices and increases in coal output, temperatures for the month were slightly warmer than historic averages. As a result of mild temperatures, the measured peak load of 50,689 MW was just 1% higher than in November 2016. The monthly average day-ahead power price for November 2017 was $23.16/MWh across all hubs, whereas the average monthly spot price in November 2016 was $19.48/MWh.

Consumer demand and the cost of fuel used to produce electricity are the two primary drivers of spot market electricity prices. This past November, temperatures around the central footprint of ERCOT generally followed their seasonal daytime averages for the duration of the month. On balance, the wholesale power prices were driven by higher delivered prices for natural gas when compared to last year. The monthly average natural gas price in November was $2.935/MMBtu at the Houston Ship Channel delivery point in Texas, about 19% higher than the $2.471/MMBtu average seen in November 2016. 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 50,689 MW in November 2017, which is about 1% higher than the November 2016 peak load of 50,026 MW. The average daytime high temperature for Austin, TX in November 2017 was 77 degrees Fahrenheit, which is slightly warmer than historical averages. Aside from the observed temperatures and higher natural gas prices, power prices remained in check as a result of increased 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 and natural gas pricing, read our full report for this month.

Energy Regulatory Commission (CRE) Publishes Basic Service Tariff

On December 1, the Energy Regulatory Commission (CRE) released its new methodology for the basic service tariff for power. The tariff is broken down into the following cost components: transmission charges, distribution charges, ISO charges (CENACE), connection services, generation charges, and charges for the operation of the supplier of basic service. The new methodology consolidates the previous CFE customer rate class definitions into 12 new rate classes. Notably, the methodology makes the supplier of basic service charge a monthly value as opposed to a rate that varies with demand or usage. The new methodology unbundles the tariff rates previously charged to all customers with the default utility company, CFE.

The publication of the basic service tariff marks an important step in the ongoing deregulation of the country’s energy market. Customers will benefit from the increasing transparency in the rate calculations, and suppliers will now be able to offer competitive third-party alternatives that can be benchmarked against the default utility rates. Supplier of Basic Service rates have been published for the remainder of the year and for 2018. Most commercial and industrial customers will fall into the rate classes in the chart below.

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

PJM Releases Proposal on Energy Price Formation

On November 15, PJM released a proposal for a revision to energy price formation that suggests some major enhancements to the electric system. PJM believes that in this evolving market, changes need to be made to price formation in order to ensure “prices reflect the cost of serving load today” by trying to incent more flexible or load-following resources into the grid.

The first enhancement represents a change to the manner in which LMPs are calculated by allowing both flexible and inflexible units to set marginal price. Under the current rules, inflexible units are not able to set marginal price due to their order in the supply stack. Inflexible assets are price takes, and are therefore unable to set an incremental price. In the example below, LMPs could potentially stay at zero, severely undervaluing an inflexible unit's cost to operate.

Under the proposed solution, inflexible units would be able to set marginal price. PJM believes that these changes will “produce prices that more accurately reflect the true costs to serve load and value flexibility for following load.” The second topic considers opportunities for enhancement related to shortage pricing and better integration of shortage pricing into the overall market construct. Shortage pricing is a PJM tool used to reflect the price of energy when reserves are limited in supply. Although PJM did not provide an estimate for the impact of shortage pricing revisions, the RTO did estimate an overall increase of 2% to 5% for combined Energy and Capacity costs under the new LMP price formation.

Forward markets reacted to the proposal with strong belief that these changes may be approved by FERC next year. We do not expect PJM price formation to change any fixed commitments for our customers under existing contracts. However, individual suppliers have voiced concerns about potential market impacts and have suggested using “change in law” provisions to avoid energy pricing moving against them. PJM expects to meet with FERC on this issue in the second half of 2018.

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

Pipeline Outages, Storage, and Shifting Weather Plague California Gas Market

Two weeks ago, the California Energy Commission and the California Public Utilities Commission (CPUC) issued a joint statement raising their concerns over the recent outages of three pipelines and reduced capabilities of the Aliso Canyon natural gas storage facility. According to the LA Times, the three lines represent, “42 percent of the natural gas transmission capacity into the Los Angeles region.” If conditions permit, utilities may be forced to curtail “noncore” gas customers more frequently than they did a year ago. Only one of the pipelines is expected to be operational by the end of December. Based on current weather conditions and spikes in the SoCal basis, customers should expect a volatile winter season. If you are able to take advantage of the dips quickly, it could be an opportunity. However, expect conditions to change rapidly with the weather forecast.

The situation is tenuous, as weather will dictate the severity of the issue this winter. Earlier in November, the National Weather Service released a statement that said, “The outlooks generally favor above-average temperatures and below-median precipitation across the southern tier of the United States, and below-average temperatures and above-median precipitation across the northern tier of the United States,” otherwise known as a La Niña pattern. The timing of the forecast and the timing of the statement by the CPUC and California Energy Commission resulted in a spike in SoCal basis pricing for the calendar year 2018 strip pricing, depicted in the figure below. Colder temperatures in the Northern parts of the US can lead to more demand for natural gas, raising prices in Southern California even though temperatures are expected to be warmer.

According to the National Weather Service, a weak La Niña pattern is already present in December and there is potential for the pattern to persist through the remainder of the winter. However, temperatures have shifted to a much warmer western US and much colder eastern US. The drop in price for calendar year 2018 is seen in Figure 1 above. The drop is the result of a decreased likelihood for the curtailment of gas for the remainder of December. Figure 2 is a recent update from the National Weather Service on December 5th.

Because of the shifting weather patterns and general uncertainty with this winter, the general sentiment is to hold off locking in basis contracts unless there is a sudden drop in pricing, which means monitoring price movements frequently. This winter is likely to be turbulent and subject to a lot of volatility. For customers requiring more budget certainty and on a tight timeline, locking in a contract could be difficult, and you should expect prices to shift dramatically day-over-day. Conversely, the forecast has had mild volatility with calendar year strip prices at the Henry Hub, signaling that production and storage are strong even with a colder overall forecast in the horizon. Thus, overall pricing could still be favorable.

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

New York
Battery Storage Approved for Deployment in New York

The New York Independent System Operator (NYISO) has approved the usage of battery storage or other energy storage resources to participate in wholesale energy, capacity, and ancillary service markets if they can follow the guidelines of the grid operator. This measure promotes wholesale market competition, which will benefit end users. Prices and offers can be submitted either in the day-ahead or real-time market, helping to balance supply and demand. The energy storage resource will charge when the market price is equal or below the resource’s bid to purchase energy. When the market rate is equal or higher than the resource’s bid to sell energy, it will act as a generator.

Over the long-term, battery storage can help mitigate price volatility in electricity markets by reducing pressure on the grid during peak demand hours and consuming when prices are low.

Following in the footsteps of California, Oregon, and Massachusetts, New York becomes the fourth state to adopt an energy storage target or mandate. The Energy Storage Deployment Program bill was officially signed by Gov. Andrew Cuomo on November 29th in alignment with the state’s goal to be 50% green by the year 2030 as part of the Clean Energy Standard. With the combination of solar, wind, and other renewable energy sources, this system is capable of preventing the production of greenhouse gases or harmful emissions. For example, battery storage facilities will be able to purchase energy from a wind power source during its highest production time, typically overnight, for use during peak demand periods in the day.

This program will be overseen by the New York Energy Research and Development Authority (NYSERDA) and the Long Island Power Authority (LIPA). About 240 MW of storage capacity is ready to come online before 2020, with the goal of 1-1.6 GW of storage by 2030.

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

Henry Hub
December Storage Injection Forces End to Price Consolidation

The breach of the technical support level in the 2018 calendar year strip for Henry Hub gas on December 7 was significant because it forced the end of the price consolidation seen throughout 2017. In addition, it opened the door for volatility to reemerge in 2018 gas pricing. The injection into gas storage announced on December 7 increased storage by 2 Bcf during the previous week. The injection was an important deviation from the five-year historical average for this week, which is typically a withdrawal of 69 Bcf. Furthermore, the injection reduced the deficit to the five-year average, from 107 Bcf last week to 36 Bcf this week (a deficit decrease of 1.8% in one week). The catch-up in storage to historical benchmarks, in conjunction with daily production setting multiple daily records in late November, added enough bearish sentiment in the market to facilitate a break below technical support levels that held for 2017 until the storage announcement on December 7.

This downward move in NYMEX pricing creates a risk mitigation opportunity for customers with open 2018 NYMEX positions.

The chart above shows the downside breakout for the NYMEX 2018 calendar year strip price, and thus muting the forward market backwardation seen throughout 2017. Advancing into the new year, there will likely be volatility along the forward curve as the physical market seeks balance between supply and demand. The NYMEX trading throughout 2018 will go a long way in determining if the forward curve backwardation will remain, or if the curve will begin to flatten out and eventually return to a contango forward market.

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.

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