Energy Procurement Insights for November 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
Connecticut Governor Signs Millstone Nuclear Bill

On October 31st, Connecticut Governor Dannel Malloy signed legislation that could provide financial assistance to the 2,194-megawatt Dominion Millstone nuclear power plant.

Senate Bill 1501, approved by the state’s General Assembly the week prior, would make Dominion Energy eligible to sell up to about half of Millstone’s output in a competitive solicitation with other higher-priced zero-emission resources, such as solar and wind, if it is determined to be in the best interest of ratepayers. Per an executive order from Malloy in July, the Connecticut Department of Energy and Environmental Protection (DEEP) and the Public Utilities Regulatory Authority (PURA) are responsible for carrying out an assessment of the current and future viability of continued operation at the Millstone plant, and are required to submit their appraisal to the General Assembly by February 1, 2018.

The Millstone plant is the largest single power source in New England, generating roughly 12% of the energy production in the region and about a third of Connecticut’s load. In total, there are three remaining nuclear facilities in New England: Millstone (2,194 MW), Seabrook (1,250 MW), and Pilgrim (685 MW). The owner of the Pilgrim Nuclear Power Station has announced it will permanently retire the facility as of June 1, 2019.

Together, nuclear power currently accounts for roughly 31% of New England’s energy production, and makes up the lion’s share of zero-carbon electricity in the region. As such, ensuring that the Millstone and Seabrook facilities remain economically viable is vital to the region’s ambitious greenhouse gas emissions reduction targets and maintaining diversity in baseload generation.

Dominion Energy has been lobbying Connecticut state legislators for out-of-market financial support for a couple of years in order to shore up its finances and prevent a possible early retirement. Nuclear power plants across the country have struggled to compete with cheap natural gas supplies in recent years, and states such as Illinois and New York have recently enacted zero emission credit programs to support financially stressed nuclear plants.

However, questions remain regarding whether the Millstone plant needs assistance in order to be profitable. According to a preliminary analysis conducted by consultant Levitan and Associates, working on behalf of DEEP and PURA, Millstone is expected to earn after-tax cash flows of about $2.3 billion between 2022 and 2035. However, Dominion has declined to provide proprietary cost data, including fuel costs, operations and maintenance, and capital investments, according to the consultant, making it difficult to accurately assess Millstone’s economics.

While Governor Malloy has noted that the state needs “significantly more engagement” from Dominion, it appears unlikely that the company will disclose this information given that this sensitive data could be shared with competitors. In the end, if DEEP and PURA’s appraisal due February 1st does not support government intervention, Dominion may still make credible moves to retire one of the plant’s units, which could still force the state’s hand. Based on this potential outcome, Bank of America Merrill Lynch believes that the implementation of a zero carbon procurement program is more likely than not.

If government action is deemed necessary in February, DEEP will be required to issue one or more solicitations for zero-carbon electricity by May 1, 2018. Under the law, nuclear facilities within ISO-NE, hydropower, Class I renewable energy sources such as wind and solar, and energy storage systems will be allowed to submit proposals. Under S.B. 1501, the total annual energy output of selected proposals must be no more than 12 million MWhs, and the length of the agreement to be 3- to 10-year contracts for nuclear and hydropower, and up to 20 years for Class I resources and storage. If a proposal is determined to be in the best interest of ratepayers and regional carbon goals, the state’s electric distribution companies (EDCs) will be required to enter into power purchase agreements (PPAs). The net costs of any PPA will be recovered though a non-bypassable charge on ratepayers’ utility distribution bills. It is difficult to project what the cost to ratepayers would be at this point, but if New York’s recently introduced zero emission credit program to aid struggling nuclear plants is any indication, costs could be in the range of $3 to $4/MWh.

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

New York
NYISO Approves New Transmission Line in Western New York

NYISO has approved a new $181M transmission line that was first proposed by the Public Service Commission in July 2015. The transmission line will run from Dysinger to Elma, New York, and is expected to address congestion and delivery restraints in Western New York due to the shutdown of the Huntley and Dunkirk coal power plants in early 2017. At times, Zone A (western NY) prices have been clearing at a premium to Zone G (Lower Hudson Valley) after the plant closures.

Project T014, or "Empire State Line," will feature a 20-mile, 345kV line along with two new 345kV substations. The Dysinger substation will become the new transmission hub in Western New York, connecting seven 345kV lines. Alleviating the associated constraints could result in cost savings of as much as $274M over the first 20 years of operation.

With an expected in-service date of June 2022, the Empire State Line will provide the infrastructure for future renewable energy integration to the region, coinciding with the state’s push for renewable energy growth. The line will allow for hydroelectric power from the Robert Moses Niagara Power Station and further imports of hydropower from Ontario, Canada. The ability to import more hydropower from Ontario will help reduce peak volatility and stabilize prices in the region. Consumers will benefit by having greater access to a low-cost energy source while reducing emissions.

Zone A pricing for October 2017 averaged $20.55, about 9% lower than in October 2016. This also represents a 27% decrease in price when compared to the five-year average. The current state of the market represents an attractive opportunity to take advantage of these historically low energy prices before the winter hits.

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

PJM Releases Summer 2017 RTO Coincident Peaks

On October 17th, PJM released the five summer 2017 RTO Coincident Peaks (5CP) as seen in the graphic below. These five demand readings represent the top five hourly demands on separate days for the entire PJM grid. The 5CP hourly readings are also used to compute customers’ Capacity Tags for the next delivery year (Jun-May). Distribution companies will compute utility zone capacity tags by averaging a customer’s demand on the five dates and hours listed, then adjusting up or down for weather normalization and other factors. Capacity tags are then charged against a regional capacity price and can account for 25% to 30% of a customers’ electric supply bill.

Enel X operates a PJM Peak Predictor program that helps to reduce demand during potential 5CP hours. Reducing demand during these hours will help lower a customer’s tag, thereby reducing this part of the electric supply expense.

You can learn more about how your organization can reduce capacity charges in PJM here.

PJM Authorizes $1 Billion in Transmission Upgrades

On October 18th, the PJM board approved $1B in transmission projects that cover reliability and market efficiency improvements. The majority of these projects are aimed at improving aging infrastructure, but there are a handful of new construction projects targeting congestion issues in New Jersey and the Western region of the RTO.

Costs for these improvements will impact the transmission component of customers’ supply bills, either as transmission service charges or transmission enhancement credits, depending on the location and financing of the projects. Customers in PJM, especially the western region and New Jersey, should expect to see an increase in their electricity costs and should plan their budgets accordingly.

PA General Assembly Changes Solar Rules

On October 30th, the General Assembly of Pennsylvania passed House Bill 118, implementing a wholesale change of the solar market in the Commonwealth.

Pennsylvania regulators have noticed that, due to the abundance of cheap solar arrays in Virginia and North Carolina, the rate of new projects in the Commonwealth had slowed. Localized SRECs were making up a lower percentage of the RPS requirement year-on-year. Specifically, the bill enforces that any solar project, as well as their associated SRECs, must be constructed and operational within the boundaries of the Commonwealth in order to qualify for the Commonwealth’s renewable portfolio standards. The bill’s provision allows for a grandfathering period, allowing previously signed deals to meet the RPS standards. This bill follows similar legislation in Maryland and Washington DC, which placed regional limits on the qualification of SRECs for RPS calculations.

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

MISO has 45 GW of Renewable Generation in Queue

The stage has been set for the continuing shift in MISO’s generation mix. Despite the Department of Energy’s recent Notice of Proposed Rulemaking (NOPR), which presents a directive in support of coal and nuclear generation, MISO’s generation mix is poised to shift to a greater percentage of renewable and natural gas fired generation.

As presented in MISO’s most recent Informational Forum, a total of 57 GW of generation is in the interconnection queue. The fuel mix in the queue is approximately 53% wind, 26% solar, and 20% natural gas. Given that MISO’s current market generation totals nearly 175 GW of capacity with a fuel mix consisting of 41% gas, 35% coal and 13% renewables, the current interconnection queue shows a definitive change in the number and size of upcoming projects, as well as the fuel types represented. Even with recent federal policy initiatives from the Department of Energy supporting coal generators and the Trump administration’s proposal to repeal the Clean Power Plan, the generation mix in MISO will continue to evolve.

During MISO’s Informational Forum, senior leadership highlighted significant changes to the current and future generation mix. Pointing toward economic factors, such as the reduced cost of natural gas and renewables, as well as state renewable and tax policies, MISO’s Vice President of Systems Planning & Seams Coordination said at the forum, "these factors are going to continue to shape the generation fleet regardless of what the EPA does regarding the Clean Power Plan." The number of active and completed projects in the interconnection queue indicates that the shift in fuel mix is slated to come online in the next two years.

The Definitive Planning Phase (DPP) is the year in which a project enters MISO’s interconnection queue process. The process is estimated to take approximately a year and a half. The projects entering the queue in 2017 are expected to begin service in 2019, ahead of the expiration of the Production Tax Credit (PTC) and the Investment Tax Credit (ITC). Leading up to the expiration of the tax credits, wind and solar projects have increased substantially to take advantage of the incentive.

In nearby markets, FirstEnergy, whose fuel mix is primarily coal and nuclear, has restated its position to completely exit the merchant generation business, no matter the outcome of the DOE's proposal. Even though implementation of the NOPR would benefit FirstEnergy's generation fleet, the move further highlights the tough situation that uneconomic coal and nuclear generation face in the current competitive environment. Of the current projects in MISO's interconnection queue, the remaining 11.5 GW of generation is natural gas, which is largely driving the low wholesale power prices seen across most RTOs. None of the projects entered in the MISO interconnection queue between 2015 and 2017 represent coal, nuclear, or hydro fuel sources.

While recent federal policy initiatives have received much attention in the news, customers can be assured that much of the recent policy uncertainty is unlikely to have an impact on Midwest electricity prices in the near term. In a scenario where the DOE’s proposal is adopted in a final rule and cost recovery for coal and nuclear generation is granted through out-of-market subsidies, rates are expected to rise. However, the proposal remains far from approval in its current form.

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

Generation Retirement Announcements Ignite Forward Power Prices

New plans to shut down several coal generation facilities in the state were announced last month.

On Friday, October 6th, Luminant Generation Co LLC, a subsidiary of Vistra Energy Corp, announced plans to retire its 1,800 MW Monticello plant in January 2018. One week later, on October 13th, the company announced planned closures of its Sandow and Big Brown plants, with combined generation capacity of 2,400 MW. Sandow is expected to close in January 2018, while Big Brown is expected in February 2018. Combined, the closure announcements represent 4,200 MWs of coal-burning capacity that will be unavailable to the market for 2018 and beyond. The planned retirements are now under review by the grid operator in order to determine whether they are needed for grid reliability.

Regardless, the market reacted swiftly, as forward pricing climbed higher following the news. The perception is that ERCOT’s reserve margin, or the cushion of excess generation above and beyond forecasted peak loads, will be tighter than initially imagined. As reserve margins shrink, the possibility of scarcity pricing during the critical summer months come into play. Under extreme conditions, scarcity pricing may add up to $9,000 per megawatt-hour in the spot market. The high prices are designed to encourage investment in new generation to meet future grid demands.

Yet, over the last couple of years, spot prices in ERCOT have been historically low. Scarcity pricing has been rare due to the abundance of cheap natural gas and renewable wind power. As a result, coal units have been edged out of the market due to their higher costs to produce energy. If they can no longer produce energy profitably, then over time the units must consider closure.

Below is an illustration of the rapid movements that have occurred in the market place in recent months. In the days following the retirement announcements, the market for the calendar 2018 around-the-clock energy strip spiked by more than 10%. The extent to which the market has overreacted remains unknown. The observed risk premium may endure through the upcoming summer season as the market evaluates whether the possibility of scarcity pricing, if any, may in fact be a real phenomenon.

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

High Temperatures, Plant Outages Result in Price Spikes

Unseasonably high temperatures and a combination of planned maintenance and forced power generation outages led to electric and natural gas price spikes in October. Given the weather outlook and expectations of strong domestic gas production over the winter, we do not believe the trend will persist, and prices are already returning to seasonal averages. Customers with market exposure may see higher-than-anticipated electricity bills for October, as the electric spot prices were 25% to 50% higher year-over-year, while natural gas prices at SoCal Citygate reached a record high of $11.83 per MMBtu on October 24th, according to a report by Platts. However, we encourage buyers to take a longer view and not be swayed by short-term temperature anomalies.

Heat-induced price spikes are not unusual in California. What is unusual is the time of the year in which these most recent price spikes occurred. October is considered a shoulder season with lower demand, where generation units will come offline for refueling and routine maintenance. The graph below provided by AccuWeather is a depiction of temperatures in Los Angeles last month relative to historical average highs and lows for the month of October. The daily high temperatures in the latter half of the month are well above the historical average high temperatures for the month. On October 24th, the California ISO (CAISO) reported over 8 GWs of generation offline, which is 1.5 GW more than the same day a year ago and almost twice the amount of generation offline from the same period in September.

As a result, Southern California (SP15) Day Ahead prices spiked to a high of $498.92 per megawatt hour (MWh) from 5 to 6 pm PDT on October 24th. The graph below is a visual of how volatile prices were in the latter half of the month.

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

Electricity Transmission Line from Arizona to Mexico Gets Green Light

An Arizona utility company and a private developer have received approval from state regulators to proceed with the construction of a transmission project that will connect the state's power system to Mexico.

UNS Electric is an Arizona utility company and plans to construct the infrastructure project along with Hunt Consolidated, a private investor. Since the project crosses a national border, it still requires federal approval. A final decision from FERC will likely be delayed after the current administration failed to re-establish the quorum necessary to rule on these proposals. After nearly six months without the necessary appointments, FERC will be working through a lengthy backlog.

The first phase of the project will allow for as much as 150 MW of transfer capacity between Arizona and Sonora, and is estimated to cost about $100M. This will include the construction of a new substation in Nogales, Arizona. The first phase of the project would be in operation as soon as 2019. A second proposed phase would upgrade nearly 30 miles of existing lines and provide for an additional 150 MW of transfer capability, totaling 300 MW between the two phases.

Customers in the state of Sonora will benefit from the increased interconnection between the two countries, as power produced on the US side of the border is generally lower-cost than power produced in Mexico. The developers of the project sought a few anchor customers via an open season process when initially announced. The energy linkage between the two countries continues to grow, and for mutual benefit. As these connections deepen, there is less of a chance they will be reversed by any renegotiation of NAFTA.

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

Henry Hub
Natural Gas Production Soars, Futures Prices Sink

In late October, dry natural gas production soared to over 75 Bcf/day and maintained that level for a total of six days to close out the month. These significant daily production numbers proved to be the catalyst for a significant downward move in forward NYMEX pricing, specifically the November 2017 futures contract, which dropped almost $0.25/MMBtu from $3.00/MMBtu on October 13th to expire at $2.752/MMBtu just two weeks later.

The recent price action in the rolling prompt contract has not been enough to end the technical price consolidation seen over the past several months. The trading range in the past five months has been $0.37/MMBtu ($2.75-$3.12). This price stability around $2.95/MMBtu is unlikely to continue throughout winter 2017/18. Upcoming temperatures and the trickle down impact to gas power generation and the magnitude of storage withdrawals will ultimately drive the direction of pricing throughout the forthcoming five-month period.

NYMEX Volatility Likely to Emerge This Winter

With the December 2017 NYMEX gas futures contract assuming the prompt position on October 28, 2017, there was a gap up in the rolling prompt NYMEX pricing. However, the bearish price action quickly resumed and continued into November, which is keeping the price consolidation intact. NOAA November temperature forecasts moderated calling for above-normal temperatures in the Northeast, Southeast, and Southwest, and average temps in the Midwest. A breakout from this price consolidation is eminent as the winter supply/demand fundamentals take effect.

Significant gas pipeline infrastructure projects have been delayed as the market awaits flow start on Leach Express and Rover phase two, which will add a cumulative 5 Bcf/day of capacity. As the calendar turned to November, multiple pipeline infrastructure projects were expected to begin flow on November 1st, with the goal of relieving the gas glut in the Marcellus/Utica region. According to Platts, this infrastructure will allow for an additional 2.6 Bcf/day of northeast gas production to come online by the end of 2018. With FERC approvals becoming more regular, it seems that only government or judicial intersection can alter this healthy supply picture, with northeast dry gas projections through 2023 calling for steady growth in shale production.

For further updates on electricity and natural gas pricing, 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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