Energy Procurement Insights for November 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 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
National Weather Service’s Mild Winter Projections Do Little to Allay Concerns for Fuel Scarcity

The National Weather Service’s Three-Month Outlook for December–February calls for a greater than 50% likelihood of warmer-than-normal conditions for most of the Northeast region. However, that projection provides little comfort to Peter Brandien, ISO-NE’s Vice President of System Operations.

Last winter, monthly average temperatures for December through February all finished above seasonally normal levels. However, the extreme cold experienced in the two-week period from December 26 to January 8 pushed the electric system to the brink, and Brandien expressed similar concerns for this upcoming season at FERC’s technical conference on winter preparedness. Responding to Brandien, FERC Commissioner Cheryl LaFleur remarked, “every fall you come and say, ‘We have plenty of capacity, we might not have enough gas, I’m cautiously optimistic we can make it through” (as reported by RTO Insider). It appears this winter will be déjà vu, all over again.

While available generating capacity is more than sufficient to meet summer demand, New England’s dependence on natural gas for both electricity generation and heating means that under prolonged periods of extreme cold, the current pipeline infrastructure is unable to comfortably support the system’s needs for heat and electricity. During last year’s polar vortex conditions, New England turned to oil for electric power. As a result, oil—a resource which typically accounts for less than 1% of electricity generation—made up more than 35% of total power production in the first week of January 2018. However, oil-fired electricity is limited by the amount of oil that is available (typically stored onsite), and under cold spells it can be difficult to replenish oil reserves. ISO-NE reported that it was prepared to roll blackouts if last year’s severe cold had lasted much longer or if there had been an issue with any other non-gas-fired source of power. Given that the region continues to pursue greater adoption of renewable energy in addition to the opposition to new pipelines out of safety and environmental concerns, ISO-NE has been forced to seek other avenues for shoring up fuel security.

For the past five years, ISO-NE had turned to the Winter Reliability Program (WRP), which provided out-of-market payments to incent dual-fired resources to maintain alternate fuels onsite as well as recruited a handful of demand response assets to supplement resources acquired through the forward capacity auction. FERC temporarily allowed the WRP, but instructed ISO-NE to come up with a more permanent market-based solution to ensure generators’ availability. Therefore, ISO-NE retired the WRP following last winter and in June 2018 implemented the “pay-for-performance” (PFP) system, which introduces steep penalties for non-performance during scarcity conditions. The penalties are designed to motivate generators to take measures to ensure their ability to provide electricity to the fullest extent of their obligation under any circumstance. Funds created through the penalties will be redistributed as a reward for resources that go beyond their capacity commitment under scarcity conditions.

PFP in and of itself will not have a direct monetary impact on consumers this winter. However, because under PFP taking capacity obligations becomes more risky, the new scheme will likely put upward pressure on capacity markets. On the other hand, customers will see some relief from the end of the WRP, which typically cost between $1.25 and $1.50/MWh from December through February.

While there haven’t been major infrastructural improvements to address fuel concerns, it remains to be seen how effective PFP has been at encouraging generators to purchase and store alternate resources on-site for the coming winter.

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

New York
NYISO Adjusts REC Contracts with Carbon Pricing

NYISO is taking steps to prevent certain wholesale market suppliers, designated as carbon-free in the New York Clean Energy Standard (CES), from collecting double payments for carbon emission reductions that are already compensated by the renewable energy credits (REC). The proposal would apply a carbon charge to the wholesale market supplier with an active fixed-price REC contract with the New York State Energy Research and Development Authority (NYSERDA) from REC solicitations that were completed before the carbon pricing rules took effect.

For those affected, NYISO will deduct the carbon charge from the supplier’s settlement based on the social cost of carbon and the real-time marginal emission rate for the supplier’s zone. The treatment of RECs under the emerging carbon-pricing world has been brewing for a few months.  Those who have opposed exemptions for a certain class of generators claim that an apparent willingness among regulators to alter agreed-upon contracts would send negative signs to potential green investors.

This proposal is limited to NYSERDA contracts, as the ISO believes it has no authority to put conditions on out-of-state REC contracts. The adjustment would not apply to those suppliers/generators, including upstate nuclear facilities, who are receiving Zero Emission Credits (ZEC) and the Offshore Renewable Energy Credits (OREC).

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

Two New Mid-Atlantic Pipelines in Service October 2018

Two new pipelines in the Marcellus/Utica basin regions were placed in service in the month of October. The US Energy Information Administration (EIA) reports that 3.2 Bcf/day of new capacity from the region has been scheduled, with 1.85 Bcf/day coming from the Atlantic Sunrise Phase II (0.85 Bcf/day) and NEXUS (1.0 of 1.5 total project Bcf/day) pipelines. The Atlantic Sunrise pipeline is projected to add 1.7 Bcf/day of capacity from the Marcellus/Utica region to the Transco pipeline, shifting gas supply to regions further south. This could potentially alleviate some of the stress on the Transco pipelines, which transport natural gas to the northeast where demands are highest during the heating months.

Enel X customers should be aware of the developing natural gas pipeline infrastructure and the backwardating effect to basis forwards, as seen in the chart below.

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

Tight Governor’s Race has Implications on Ohio’s Energy Future

The 2018 Ohio gubernatorial race is one many people in the state should pay attention to this year, as it could have an impact on the state’s energy future.

Two candidates, Richard Cordray (D) and Mike DeWine (R), are fighting to replace Governor John Kasich. As of November 5, RealClear Politics shows Cordray with a slight edge of about 4.7%.

Before highlighting the candidates’ position on energy, it’s important to review some history on Ohio’s Renewable Portfolio Standards (RPS), as its future could be in question. The state’s current RPS, enacted in 2008, requires utilities to derive a growing percentage, currently 12.5%, of retail electric supply from renewable sources like solar, wind, biomass, geothermal, and nuclear by 2027, with a solar carve out of 0.5%. On the efficiency side, the RPS calls for annual reductions for a cumulative electricity savings of 22% by 2027. According to the Ohio Economic Development Association, in 2014, the RPS was temporarily “frozen” for two years with the passing of Senate Bill 310 in order to study the standards and their potential economic impacts more closely. At the conclusion of the “freeze” period, House bill 554 was passed by the Ohio Legislature, proposing voluntary participation in the RPS until 2021; however, the bill was quickly vetoed by Governor Kasich. A new bill, House Bill 114, proposed a voluntary participation goal for the RPS’s entire lifetime in 2017, but was vetoed by Governor Kasich after being passed by the House. Now, a new iteration of House Bill 114, which proposes a complete reduction of the RPS to 8.5%, is held up in the Senate by split votes among both Democrats and Republicans. The outcome of this bill, and the subsequent outcome of Ohio’s energy future, will most likely be determined by the outcome of this election.   

Cordray’s stance on energy favors the state’s current RPS and, according to his campaign office, the Democratic candidate intends to work to “double” its renewable energy and energy efficiency goals by 2025, if elected. Additionally, Cordray has stated he would do away with current “wind setback regulations” passed in 2014, which more than doubled the previously imposed property line setback distance to roughly 1,300 ft. These focal points of his campaign, aimed at strengthening the overall state of Ohio’s RPS, stem from the candidate’s desire to capitalize on the clean energy sector in order to spur economic growth in the state by creating jobs in the wind and solar industries and encouraging businesses keen on operating under certain renewable standards to relocate to Ohio.

Similarly, DeWine has shown support for Ohio’s continued growth in the clean energy sector. Although DeWine has not presented a specific energy plan to date, his nominee for lieutenant governor, Jon Husted, has stated the candidate intends to take a “holistic” approach to the state’s energy future and curb burdensome regulations in the sector (Advanced Energy Economy). Historically, as Ohio’s Attorney General, DeWine consistently challenged the Obama-era Clean Power Plan.

Regardless of the candidate elected, the net impact to markets could bring increased short-term costs to customers. Policies implemented that favor renewables could bring a greater demand for ancillary services from thermal generation and energy storage due to technology-specific intermittency. This would more than likely lead to increased costs for balancing reserves and black-start capability. A move to make the state RPS voluntary would further increase Ohio’s dependency on fossil fuel-burning capacity, or could lead to the introduction of state subsidies. The implementation of a Zero Emission Credit (ZEC) program similar to Illinois or New Jersey—also currently held up in Ohio’s Senate under the nomenclature House Bill 128—could increase regional electricity prices, as well as result in downstream impacts on capacity markets by artificially deflating regional capacity clear prices.

While the explicit impact will not be known until further down the line, customers should be aware that if changes in law result in higher costs, those costs would more than likely be passed onto them by third-party suppliers.

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

ERCOT Forecasted to Have Sufficient Reserves Through 2022

ERCOT has filed a new report with the Texas Public Utility Commission that indicates that the ERCOT market design is sufficient to support revised reserve margins of 10.25%.

The study, a joint effort between The Brattle Group and Astrape Consulting, looked at market design and projected system conditions through the year 2022, simulating a variety of reserve margin scenarios, weather, and other conditions. The results found that the current system would be economically efficient to operate at a planning reserve margin of 10.25%, well below the current 13.75% target under which ERCOT currently operates.

This past summer, ERCOT operated below the 13.75% target at a 10.9% reserve margin, which drew concerns about the stability of pricing in the market. Summer pricing at North Hub increased $5/MWh when the preliminary Summer 2018 study mentioned ~11% reserve margin, then another $10/MWh when the final Summer 2018 assessment indicated a sub-11% reserve margin seemed certain.

Despite the concerns in the forward market, which forecasted an average summer 2018 ATC LMP of $89.18/MWh on May 29th, the average real-time ATC LMP at North Hub for summer 2018 was $33.55/MWh. Fears were largely proved to be unfounded, as extended periods of above-average temperatures failed to test the system at a 10.9% reserve margin. The new 10.25% reserve margin will be submitted to various ERCOT working groups for potential implementation, with stakeholder comments being accepted until November 26. Customers in ERCOT should have faith that even with the lower reserve margin, reliability will persist and prices will continue to be in their average range. We encourage customers to actively engage with their account managers to determine proper market timing and avoid overpriced markets.

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

San Diego Becomes Largest City to Join Community Choice

A few months ago, California Governor Jerry Brown established a statewide goal of becoming 100% reliant on renewable energy by 2045. Milestones of this plan have the state being 50% powered by renewable energy by 2025 and 60% by 2030. The City of San Diego has decided it can achieve these goals even faster.

After three years of research and analysis, San Diego Mayor Kevin Faulconer announced the city will be moving towards the Community Choice Aggregation (CCA) model, creating an opportunity for end users to divest themselves from the investor-owned utility, San Diego Gas & Electric Company. In making the announcement, Faulconer said this is the best pathway for the city to not only achieve the state’s renewable energy goals, but to achieve those goals a decade sooner by 2035. The city says this program will increase competition to drive down electricity rates by 5% or more. Surrounding cities and communities in the San Diego region will also have the opportunity to join the CCA as well.

This decision comes weeks after the California Public Utilities Commission (CPUC) made a final ruling stating that any customer leaving the utility (to join a CCA or other aggregation) will be subject to an exit fee, as the utilities are still responsible for managing the power line and any operational costs related to grid reliability. Early estimates place these exit fees around a 5% increase on each bill. 

This program is set to begin in 2022, with all eligible customers automatically enrolled. End users still have the option to elect out of the program and stay with the utility. It remains to be seen if customers will actually benefit from joining the CCA due to the exit fees.

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

No Seasonal Relief, CFE Rates Flat in October

Despite some expectation that the more moderate autumn temperatures would provide price relief in the CFE tariff, commercial and industrial customers saw effectively flat rates month-over-month in October. As a result, customers in certain regions continued experiencing high capacity prices in October, which have increased 200% since last December. Energy prices across the country have also risen more than 50% in most regions over the same period. Together, the energy and capacity components comprise roughly 80% of customers’ bills. The CFE argues that the price increases reflect the company’s costs as underlying commodity prices have grown.

The chart on the right shows capacity prices in the Monterrey region, where prices have risen from $186.24 MXN/kW-month in December to $454.51 MXN/kW-month in October for medium-tension customers. In this region, October was the first month since February that did not post a month-over-month increase. However, October’s decrease was only about a 0.2% change. The total increase in capacity costs since December exceeds 144% in this region and even more in other regions. The capacity component accounts for 15%-20% of overall energy costs.

Energy rates saw a similar sideways movement in October. The chart below shows energy prices for the Querétaro region, load-weighted for each tranche assuming an average of 30% base consumption, 60% intermediate consumption, and 10% peak consumption. While October marked the first official decrease in energy prices since December for most regions, the month-over-month change amounted to just a 0.2% tick down. Load-weighted prices in Querétaro have increased from $1.15 MXN/kWh in December to $1.82 MXN/kWh in October—a 59% increase over that period. The energy component of customers’ bills usually makes up 50%-60% of total costs.

In December 2017, the regulatory body CRE forced the default utility company CFE to unbundle their power rates, breaking out supply components such as energy and capacity from regulated components including distribution, transmission, and ISO charges. This unbundling would increase transparency and make it easier to compare pricing offers from third-party suppliers, which can now provide alternatives to the supply portion of the bill.

Customers throughout the country have had to grapple with the steady increases in prices. Third-party supply can be an attractive alternative. More than two dozen qualified suppliers now operate in the market and offer a range of products to achieve greater budget certainty and lower costs.

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

Henry Hub
Future Natural Gas Price Closely Tied to Oil

The fundamental relationship between oil and gas is enticing customers with open NYMEX positions through 2021 to maintain some exposure. The production increase from associated gas brings low-priced supply to an already over-supplied market. Natural gas production and consumption levels are the traditional price drivers for the market movement of the commodity. However, the sustained upward move in crude oil prices may continue to drive gas prices lower for the next two years.

In the past 24 months, the inverse relationship between the price of natural gas and oil has pushed pricing for both fuels in opposite directions. The current trend clearly shows the natural gas price heading downward and oil pricing steadily on the rise (see linear trend lines in the chart below). Since October 30, 2016, natural gas went from a high price of around $3.70/MMBtu in December 2016 to a low price of around $2.65/MMBtu in December 2017, a drop of around 26%.

Throughout 2018, the natural gas 12-month rolling strip price remained relatively low, between $2.70-$2.95/MMBtu. Crude oil pricing went from relatively low, stable pricing until late summer 2017, to put in a low price of around $44/barrel in May 2017. Since summer 2017, crude oil pricing rallied steadily to put in a high price of around $76/barrel in September 2018, an increase of around 72% from the low point. The inverse relationship signifies that sustained growth in crude oil production will maintain downward pressure on natural gas prices. The chart below shows the past 24 months of natural gas and crude oil 12-month rolling strips.

The elevated crude price allows producers to reach their revenue goals from the sale of the oil and the natural gas liquids (NGLs). However, the amount of associated natural gas production from three oil-directed wells is roughly equivalent to one natural gas-directed rig. A crude oil price above $70/barrel is likely to incentivize enough associated gas production to continue applying downward pressure. Current backwardation in oil the markets may prevent further growth in oil and associated gas unless calendar strip pricing can rally to near $70/barrel. The table below shows the current calendar strip pricing for crude oil and the benchmarks over the past year.

Dry conventional natural gas production is the highest-cost form of gas production, followed by dry shale, which is the most prominent form of gas production. Wet shale gas is less costly than dry shale and dry conventional production, but less prominent. The least expensive form of gas production is associated gas. As a result, an increase in associated gas production is likely to apply downward pressure on forward NYMEX natural gas pricing from 2019-2021.

The associated gas is adding extremely low-cost supply to the natural gas production stack. Going forward, analysts will need to dig into the specifics of the production numbers because of the potential bearish impact to natural gas pricing from increased associated gas production from oil wells, compared to dry production. The near-term NYMEX strips are particularly prone to further downside movement as a result of the elevated associated gas production. It is likely pricing will need to hold above $70/barrel to incentive oil, NGL, and associated gas production.

For further updates on the natural gas markets, 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