Energy Procurement Insights for March 2019: 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
2022/23 Capacity Prices Fall to 6-Year Low

Capacity prices fell to a six-year low in ISO New England’s 13th Forward Capacity Auction (FCA13) for 2022/23 delivery. Prices cleared at $3.80 per kW-month (~$46,000/MW-year) for all zones for the June 1, 2022 – May 31, 2023 delivery year, the lowest level since the 2013 auction and nearly 18% lower than last year’s clearing price of $4.63/kW-month (~$56,000/MW-year) for 2021/22. The decline in capacity prices can be principally attributed to the absence of any new significant generation retirements, and the addition of new demand response resources.

Every year, the operator of the regional power grid holds a forward capacity auction to secure electricity supplies needed to meet predicted energy demand three years in the future. The auction sets the price that generators receive for committing to produce power when needed. In turn, these costs are recovered through charges imposed on electric consumers in New England based on their demand contribution to the ISO-NE system peak hour each summer.

This year, the FCA13 auction secured 34,839 MW of power capacity at a total cost of about $1.6B, which is about $470M below last year's auction. The auction procured 783 MW of new generation, including the proposed 650 MW natural gas Killingly Energy Center, and 58 MW from the Vineyard Wind offshore project. In addition, the auction secured 654 MW of new energy efficiency and demand response measures; otherwise, all other resources in the auction had been operating previously. While the Mystic Generating Station announced plans to retire its 2,000 MW facility in Everett, Massachusetts, effective June 2022, ISO New England received approval from federal regulators in late 2018 to retain the facility for fuel security and reliability. As a result, the 2022/23 delivery year will not be affected by major power plant retirements. However, the Mystic power plant will be compensated through out-of-market mechanisms, the costs of which will be recovered from ratepayers starting in June 2022.

The latest results mark the fifth consecutive year that capacity auction prices have fallen in Northeastern Massachusetts (NEMA), and the fourth consecutive year for all other zones. For Rhode Island (RI) and Southeastern Massachusetts (SEMA) customers, the recently released prices for 2022/23 represent a nearly 66% decrease, equivalent to ~$91,000/MW-year, compared to the current 2018/19 year. For all other New England zones, prices are 60%, or ~$69,000, lower than the current 2018/19 year. For an average large commercial SEMA or RI customer with a capacity pass-through supply contract, this will equate to a decrease of roughly ~$0.027/kWh compared to the current 2018/19 year. Elsewhere in the region, customers will see an average decrease of ~$0.021/kWh.

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

New York
Con Ed Proposes Rate Hike of $485M for Electric & $210M for Gas, Effective Jan 2020

Consolidated Edison (Con Edison) customers in New York City and Westchester could see an increase in rates on their utility bills come January 1, 2020. On January 31, 2019 Con Ed submitted a proposal to the New York State Department of Public Service (NYDPS) for a $485M increase in electricity revenues. The request for a 14.5% increase cites the need for greater investments in the transmission system for safety, reliability, and the implementation of clean energy alternatives. A procedural conference will be held on March 13, where a schedule for future proceedings will be established. The judge hearing the case has requested evidentiary hearings be completed by July 26. If the proposed rate hike is approved, most commercial and industrial customers could see their overall demand charges increase by around 10% in 2020 compared to their current rates.

Based on the proposed tariff adjustments released by Con Edison, the impact of the rate hike varies by utility rate class. As shown in the table below, summer (Jun – Sep) demand charges are posed to increase between $3.93/kW and $3.39/KW for the two most common commercial and industrial rate classes, which are Service Classification 9 Rate I and Rate II. For all other months (Oct – May), demand charges are projected to increase between $2.67/kW and $1.63/kW, respectively. Large General Service (Rate I) customers would see the largest increase for demand charges, at 13.3%. Large General Service Time of Day (Rate II) customers would see the smallest increase among rate classes, at 9.7% year-over-year.

While not shown in the table above, the newly adjusted tariff made negligible changes to volumetric and fixed monthly charges in the proposed 2020 rate adjustments. The prospective changes to demand costs greatly outweigh changes to other utility bill line items, as demand often makes up more than 60% of total distribution costs for large commercial and industrial customers.

In addition to the proposed increase in electricity delivery rates, Con Edison also filed a request to increase revenues of natural gas delivery by $210M beginning January 1, 2020. The submission to the Department of Public Service cites the need for increased investment in infrastructure projects, specifically in upgrades to the liquefied natural gas plant. While the filing proposed a one-year rate plan, Con Edison does open the opportunity for discussion about multi-year rate plans in further proceedings. According to Con Edison, distribution rates are expected to increase between 4% and 14% year-over-year for most large commercial and industrial customers.

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

Mid-Atlantic
Marginal Fuel Postings Point to Increase in Natural Gas for Setting Marginal Prices (LMPs)

As a continuation from last month’s report, this article takes a turn into PJM’s increased reliance on natural gas generation and the effects on electric LMP pricing. The chart below, using information from Monitoring Analytics, shows how natural gas increasingly set the marginal price in 2017 and 2018.

PJM defines marginal fuel units as “the units that set the locational marginal price in each five minute interval.” Generators will offer into PJM a price and quantity of MW for each hour of the day. The next MW needed for the system will set the marginal price. This analysis does not take into account location, weather, operating schedules, generator hedging, and purchases or any other outside factors; it focuses only on simple percentage increase of natural gas-based generation. 

As the above chart shows, natural gas generation is setting the marginal price nearly 20% more often than the prior year. This increase could be explained by both an increase in natural gas capacity in PJM and the relatively flexible nature of natural gas generation, which is easier to activate on demand than uranium, coal, and renewable power sources.

In terms of pricing, it is important to look at input pricing, in this case Transco Z6 xNY, a major natural gas pipeline serving PJM, with annual averages higher in 2018 compared to 2017.

While only PJM knows the exact prices that generators offer, it is safe to assume that an increase in the cost of inputs would lead to an increase in the cost of outputs. Looking at average monthly ATC West Hub LMPs below, 2018 settled higher than 2017, which is consistent with the Transco Z6 xNY information above. Again, this is based on settlement price inputs alone and ignores the outside factors listed above.

With the proven increased correlation between natural gas and power, it is important for customers to review and understand the natural gas market even when dealing only with power accounts. Also, our electric block-and-index customers need to follow the natural gas market for any index or market pricing that is not hedged. For block-and-index customers, for example, a sudden rise in natural gas prices could signify an increased likelihood of higher-priced index power, as natural gas generators will need to account for the high cost of gas.

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

Midwest
Ohio Senate Bill 1 Reintroduces Legislation to Reduce Regulations Benefitting Utilities and Fossil Fuels

In an effort to relax regulations in Ohio, the Senate’s first bill, Senate Bill 1 (SB1), reintroduces language from a similar bill (Senate Bill 293) from 2018 and aims to require all state agencies to reduce regulations by 30% by the end of 2022. Initial analysis of the bill indicates that the utility and mining industries would have the most to gain from the proposed legislation. Further reduction or easing of certain regulations could impact customers negatively from both a cost perspective and an environmental perspective.

State senators in support of SB1 view the legislation as an effort to encourage businesses to expand or relocate into the region by easing regulations. Critics of SB1 view the efforts as a way to deregulate without focusing on whether or not the regulations in place serve a beneficial purpose to the state’s constituents.

A high-level summary provided by the legislature highlights the main components of the bill. The list includes these highly contentious proposed rules:

  • Requires each state agency to reduce the regulatory restrictions contained in its rules by 30% by 2022, according to a schedule set forth in the bill.
  • Prohibits an agency from adopting new regulatory restrictions that would increase the percentage of restrictions in the agency's rules.
  • Requires an agency that does not achieve a reduction in regulatory restrictions according to the required schedule to eliminate two restrictions before enacting a new rule containing a restriction.

The “two-for-one” language is similar to a presidential executive order signed in January 2017 which has received legal challenges. Ohio SB 293 passed the State Senate; however, it failed to pass through the Ohio House of Representatives. If SB1 makes it through the legislature and is signed by Ohio Governor Mike DeWine, it is very likely to face subsequent legal challenges.

Forced deregulation of this magnitude could have a ripple effect at the wholesale energy market level. While some customers may see a reprieve on environmental or operational fees and taxes, the legislation as a whole could ease restrictions on local utilities and make it easier to increase charges on customers.

In the meantime, locking in open positions may be an opportunity to avoid some, but not all, of the increased cost.

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

Texas
Summer 2019 Energy Forward Prices Increase by 97%

A look back at North Hub On-Peak forwards indicates that average energy forward prices for the summer 2019 months (June 2019 – Sept 2019) traded at $96/MWh in February 2019, an increase of 97% when compared to summer 2019 forwards in February 2017.

In its recently released Seasonal Assessment of Resource Adequacy (SARA) report, ERCOT declared that it does not anticipate the need to enforce rolling outages during summer peak conditions, despite the risk posed by historically low reserve margins,. The SARA report assessment takes into account generation availability, expected peak demand conditions, expected generation outages, and weather conditions that could affect the seasonal demand.

ERCOT’s targeted planning reserve margin is 13.75%, but since a number of coal plants announced their retirements in the past year, the reserve margin for summer 2019 reached a historic low of 7.4%, nearly half of the target. Based on average summer peak weather conditions from 2003 to 2017, the preliminary SARA report indicates summer 2019 system-wide peak load forecast of 74,853 MW, which is 1,380 MW higher than last year, while the expected resource capacity is 78,514 MW. In the event of an emergency such as extreme heat or reduced wind energy production, ERCOT would utilize the additional reserve capacity of 3,301 MW. Also, if needed, it would deploy demand response programs with an expected capacity of 2,200 MW to 2,700 MW. Retail customers on an index rate may experience elevated energy costs as supply tightens due to an unforeseen event.

In January, ERCOT executed a modification to its operating demand reserve curve (ORDC). In order to confront the capacity shortage and to help incentivize generation owners and developers to provide more capacity, ERCOT increased the standard deviation in calculating Loss of Load Probability to calculate ORDC by 0.25. The increase in the ORDC could increase electricity prices by as much as $4B annually, or roughly $0.01/kWh. Lower reserves are likely to lead to higher prices as well as the threat of power interruptions. In 2011, as per FERC’s report, even when the reserve margins were 17.5%, spot prices in Texas remained above $3000/MWh for 16.75 hours due to a prolonged heat wave. Also, reserve margins are expected to decline further, to 6.1% by 2020.

Customers in the Texas region with open exposure for summer 2019 are encouraged to lock in a longer-term contract, preferably 24 months or more. By doing so, customers can hedge against potential increases in energy costs due to risks posed by reduced reserve margins in summer 2019 and summer 2020.

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

California
California Energy Consumers Brace for Fallout from PG&E Bankruptcy

On January 29, Pacific Gas and Electric (PG&E) filed for chapter 11 bankruptcy protection as it deals with the fallout from its role in sparking California wildfires in 2017 and 2018.

PG&E is the largest utility in the nation, providing electricity and natural gas services for about 16M customers. The utility has insisted that there will be no stoppage in service due to the bankruptcy filing. In a letter to customers, PG&E wrote, “The power and gas will stay on: We will continue to provide you with reliable electric and natural gas service, and that will not change as a result of this process.”

While service will be maintained, PG&E customers can expect to see their utility distribution rates increase as soon as January 1, 2020 to help the utility pay for costs associated with wildfire prevention and safety improvements. In the longer term, over the next two to three years, customers face the prospect of paying for a portion of the liabilities associated with the 2017 and 2018 wildfires.

PG&E filed for bankruptcy in 2001 due to debts accrued related to the Enron scandal. In that case, rate payers were subject to pay $7B in pass-through costs (60% of total liabilities) that were packaged as the Department of Water Resource (DWR) bonds, a financing measure established in the restructuring of the utility. Applied on November 15, 2002, the “DWR Bond Charge” on customers’ utility bills amounted to an additional cost of $0.00525/kWh. This charge remains on customers’ utility bills today, and for a small general commercial/industrial customer with 1M kWh of annual usage, this charge amounts to $52,500 per year.

Current speculation indicates that PG&E’s total liabilities in this case could reach $30B, which would far exceed its insurance and assets. The California legislature passed a bill last year that allowed PG&E and other utilities to raise rates to pay for part of the damages inflicted by wildfires that occurred in 2017. While this act would not apply to fires that occurred in 2018, on December 13, 2018, PG&E submitted its General Rate case for 2020-2022 to the California Public Utility Commission, which included a request for a $1.1B increase in year-over-year revenues. In its submission, the utility claims that more than half of the new revenue would fund their wildfire prevention and Community Wildfire Safety Program.

PG&E Corp, PG&E’s holding company, announced on February 28, 2019, that it was incorporating a $10.5B pretax charge in its earnings for the fourth quarter of 2018 and the entirety of 2019. This charge is a result of the utility believing that it is “probable” that its own equipment was the ignition point of the 2018 Camp Fire. While the bankruptcy proceedings will take years to establish the final amount of liabilities—the 2001 bankruptcy filing took two years—$10B dollars in pretax charges can be considered a floor for total liabilities the company expects.

While customers continue to face increased rates due to PG&E’s bankruptcy filing in 2001, government officials are trying to shield them in the fallout of financial restructuring in the 2019 proceedings. Recent legislation introduced by Senator Jerry Hill (Democrat, San Mateo) would give the California state government final say on utility rate hikes in an effort to protect ratepayers. The proposed legislation does not provide any guarantees to PG&E customers, but if passed it would reduce the likelihood that ratepayers will bear the burden of billions in rate increases to cover liabilities.

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

Mexico
CFE Rates Up ~2% in March, 40% to 55% Higher than Last Year

The CFE published its tariff for their Basic Service customers for March. Rates moved slightly higher, with a 2% increase for capacity and a 1.7% increase for energy. The February to March increase was much more modest than the same increase one year ago, which was when prices began their dramatic escalation that continued through September 2018. While lower seasonal demand has kept rates steady through the winter and early spring months, commercial and industrial customers are still paying substantially higher prices compared to the CFE tariff from one year ago. In many cases, year-over-year cost increases in March approach 55% for the capacity component of the bill and about 45% for energy.

The chart on the right shows capacity prices in the Monterrey region, where prices for March 2019 are just under $349 MXN/kW-month. This represents a 2% increase compared to the February rates and a 55% increase relative to last March’s rates, which registered at just $230 MXN/kW-month. The capacity component accounts for roughly 10% to 20% of overall energy costs.

Energy rates also saw slight upward movement in March. The chart below shows energy prices for the Aguascalientes region, load-weighted for each tranche assuming an average of 30% base consumption, 60% intermediate consumption, and 10% peak consumption. March energy prices increased by about 1.7% in most regions compared to the previous month, marking an increase of roughly 45% to 50% compared to March 2018. Load-weighted prices in Aguascalientes have increased from $1.008 MXN/kWh in March 2018 to $1.478 MXN/kWh in March 2019, a 58% increase over that period. The energy component of customers’ bills usually makes up 50% to 70% 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 confront the price growth experienced throughout 2018, which has not pulled back so far in 2019. Leaving the CFE Basic service tariff in favor of 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.

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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