Energy Procurement Insights for September 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
ISO-NE to Move Forward on Fuel Security Measures

With a peak demand of roughly 27 gigawatts (GW), ISO-NE’s more than 31 GW of generating capacity would appear to be sufficient to keep the system in good shape.

But the healthy amount of capacity masks the precarious situation the system faces under conditions of extreme cold weather, during which many sources of generation cannot acquire the fuel they need to run.

Since 2013, nearly 7 GW of nuclear, coal, and oil-fired facilities have retired, and their replacements have come primarily in the form of large combined-cycle natural gas plants. Unlike their more traditional counterparts, which are able to store fuel on-site, natural gas generators typically rely on “just-in-time” deliveries of fuel via pipelines, and most purchase gas on the secondary market rather than carry firm contracts which would guarantee delivery. This system functions quite well, except under periods of extreme cold when excess pipeline capacity dries up and gas becomes either prohibitively expensive or, in many cases, simply unavailable. While 20 years ago coal and oil supplied roughly 35% of the region’s kilowatt-hours (kWhs), in 2018, they supplied a combined 2%. Over the same time period, natural gas’ share of supply rose from 13% to nearly 50%.

In general, the conversion to a natural gas-reliant system has been a boon for consumers, as cheap natural gas helped keep a lid prices in wholesale energy markets. For nuclear generators and other non-natural gas peaking plants, however, the new economic conditions have been proving untenable. Across the nation, oil and coal plants have been shutting down, while nuclear facilities are either following suit or petitioning for out-of-market subsidies in order to maintain operations. However, in New England, the current pipeline infrastructure cannot support demand for natural gas on the coldest days. In addition, the pipeline system shows few signs of expansion. During the cold snap in early 2018, the New England grid turned to oil to keep the lights on, burning more barrels of oil in a two-week stretch (over 2 million) than it had in all of 2016.

ISO-NE has long grappled with the stresses brought on by extreme cold in the region, and in 2013 had administered a “Winter Reliability Program” to provide incentives for generators with dual-fuel capabilities as well as demand response resources to remain at the ready should colder-than-normal conditions arise. The program, however, was discontinued with the implementation of pay-for-performance—a penalty scheme which was expected to sufficiently incentivize generators to secure fuel resources. However, following the retirement petition of Exelon’s Mystic 8 & 9 generating stations, ISO-NE concluded that penalizing generation for unavailability was not driving the investments in fuel security that it had hoped, and that existing market structures were not sufficient to compensate resources with on-site fuel storage or dual-fuel capabilities. Although primarily natural gas-burning, the Mystic Generation Station utilitizes liquefied natural gas (LNG) from the nearby Distrigas facility instead of interstate pipeline capacity to supply its facility. ISO-NE further asserted that the current market structure actually suffers from a “split incentive” problem, whereby consumers want generators to be fuel-secure to reduce the risk of power outages despite the fact that generators profit most when tight fuel supply drives price volatility. As a result, the current system requests generators to invest in measures that will reduce their profits without compensating them to do so.

FERC, which directed ISO-NE to develop market-based mechanisms to determine the adequate value of compensation for fuel security, lacked a quorum to review ISO-NE’s proposal. By rule, the proposal will go into effect with its two-year interim stage to pay for “inventoried energy” beginning December 2023. While still early in its development, ISO-NE is eyeing other changes to the wholesale market, including implementing a “multi-day ahead market,” additional ancillary services, and a seasonal forward capacity market. Charges from these changes will fall on the suppliers to collect from their customers, but, the extent to which these measures suppress price spikes in winter months will determine their net impact. Although a ways away, buyers should review longer-term electricity contracts for language regarding pass-throughs for “fuel-security” and “RMR” charges to ensure they are at cost.

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

New York
NY Kicks Off Large-Scale Investments to Reduce Carbon Emissions

The state of New York has taken big strides in the past year to reshape its future energy profile. Legislative initiatives culminated in the signing of the Climate Leadership and Community Protection Act (CLCPA) in late July, which set goals of 100% carbon-free electric generation by 2040 and statewide net carbon emissions of zero by 2050. The target set will require a dramatic overhaul of electricity generation and transmission throughout the state. Announcements from the state legislature and New York Independent System Operator (NYISO) surrounding the enactment of the CLCPA provide context into the challenges and plans to meet the state’s goals.

According to NYISO’s 2019 Annual Grid and Markets Report, carbon-free generation made up 34% of the state’s generation mix entering this summer. At 5,400 megawatts (MW), nuclear generation was the largest source of carbon-free generation. Nearly 40% of the state’s nuclear capacity and 15% of zero-carbon generating capacity can be attributed to the 2,060 MW Indian Point Energy Center nuclear facility, which is slated to begin retirement in April 2020 and be fully decommissioned in April 2021. The replacement of this resource is one of the largest challenges facing the state’s carbon-free electricity generation targets of 70% by 2030 and 100% by 2040.

One of the largest overhauls included in the CLCPA will be the development of offshore wind generation. With no offshore wind generation capacity currently in operation in the state, a target of 2,400 MW by 2030 and 9,000 MW by 2035 will require significant investment from the state. In July, the Governor of New York announced the award of contracts to two new offshore wind projects that will add 1,700 MW of capacity to the grid. The Sunrise Wind project by European wind developer Orsted is estimated to be 880 MW and will begin construction off the coast of Long Island in 2022. The second project, Empire Wind by Equinor, is planned to be 816 MW and begin development in 2021. Both projects are expected to be in service by 2024. Current estimates suggest costs for each project will be around $3 billion, and will be financed through renewable energy credit (REC) contracts with the New York Energy Research and Development Authority (NYSERDA).

With the impending retirement of Indian Point, the state faces the challenge of recouping the large baseload capacity that nuclear generation provides. Behind nuclear, hydro is the second largest source of carbon-free generation in the state, making up 11% of overall capacity. In early August, the Governor and New York Power Authority (NYPA) announced a $1.1 billion investment over 15 years in the Robert Moses Niagara Plant in upstate New York. The capital will go towards upgrading the 58-year-old facility and extending the lifetime of the 2,525 MW plant that will become even more crucial to statewide capacity in the transition to 100% carbon free electricity generation by 2040.

While state legislators continue to move forward with large-scale renewable projects, in December 2018, NYISO released a Carbon Pricing Proposal to reduce emissions through a market mechanism. The proposal would increase the price of carbon emissions for generators from about $5/ton (under the current RGGI program) to $50/ton in 2022 and $69.32/ton in 2030.

Projections on the net impact to retail energy consumers vary; current futures markets show Zone J wholesale energy for 2023 trading at $46/MWh, or 27% higher than in 2020. New York regulators will decide on the proposal later this year, and while it is unclear which way they are leaning, it is likely that the state will need to implement a carbon tax in order to meet its CLCPA targets. Regardless of the strategy, investments in large-scale renewable generation projects and carbon pricing mechanisms will ultimately be passed through to rate payers, resulting in higher electricity prices for years to come.

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

PJM Renewable Generation Summer 2019 through August

Many states in the PJM footprint are trying to integrate increasing Renewable Portfolio Standards by 2030 and beyond. These large-scale renewable generators currently make up a very small portion of total megawatts generated in summer 2019 to date. The graphic below shows total PJM generation by fuel type (provided by PJM) summed up by each hour of the day from June 1 to August 31.

In total, Traditional (Coal, Gas, Nuclear, Oil and Other) makes up 95.6% of the pie, followed by Hydro at 1.8%, Wind at 1.6%, Other Renewables at 0.7%, and Solar at 0.3%. The chart also shows renewable output at expected times, with hydro pumping when power prices are highest, solar at times of sunlight, and wind predominantly overnight. The two largest “growth” renewables, solar and wind, combine for less than 2% of overall summer generation to date this year. Maximum generation output for these resources are at opposite times of the day and year, with solar during the summer and mostly “on-peak,” and wind creating more power during the “off-peak” hours in the winter. 

Integrating renewables is extremely important for PJM energy buyers to offset carbon production. If power users have corporate sustainability goals that they would like to discuss, please reach out to an energy advisor to create a proactive strategy and plan for the future.

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

House Bill 6 at Risk of Facing Referendum

In July, the state legislature of Ohio passed House Bill 6 (HB6), which changed the immediate energy future of the state. As a reminder, the new law changed the following:

  • Renewable Portfolio Standards reduced from 12.5% to 8.5% by 2026 and eliminates the solar requirements
  • Reduces Ohio’s energy efficiency and renewable energy mandates
  • Creates a fund for both Nuclear and In-State Solar Generation Fund
  • Subsidizes the Ohio Valley Electric Corporation coal plants

On September 4, FirstEnergy Solutions (FES) filed a motion in the Ohio Supreme Court to block a potential referendum on HB6. The issue surrounds whether or not the new law is considered a tax increase – something proponents of the bill indicated was not the case prior to the vote. If the Supreme Court interprets HB6 as a tax and denies the motion, there will be no possibility of allowing a referendum.

FES maintains that failure to keep HB6 in place could have negative consequences for consumers. In a statement given to Utility Dive, FES noted that a successful referendum “would increase Ohioans’ monthly electric bills, eliminate ninety percent of Ohio’s carbon free, zero-emissions electricity, and cost Ohio 4,300 jobs.” Interestingly, critics of HB6 include members from both the natural gas and petroleum industries as well as renewable energy advocates. The new subsidies favor nuclear and coal industries while laying waste to renewables – as shown by the reduction in the state-mandated RPS.

Customers should follow this news story closely as it impacts all residents and corporations in Ohio. If the referendum is approved, the law will be placed on hold until the general election in November 2020, delaying most of the $150 million subsidies for the first year necessary for FES’ nuclear plants to remain operating. The controversy surrounding the state-level subsidy programs continues to evolve across much of the PJM footprint, with New Jersey and Illinois implementing programs ahead of Ohio. It should be noted that both programs have seen court challenges and have not been repealed. PJM’s capacity repricing proposal and energy price formation proposal are still under FERC review, and with no clarity in sight, there is risk that market participants could end up with higher bills due to an inefficient market.

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

Real-Time Pricing in Texas Hits System-Wide Offer Cap: $9,000/MWh

With delays and cancellations of planned generation projects, Texas entered summer 2019 with all-time-low reserve margins at 8.1%, or 78,555 MW. Shortage of reserve capacity raises the chances of hitting system-wide offer cap, $9,000/MWh, when demand rises during any weather-adverse conditions. As a heat wave baked the state and temperatures reached triple digits in August, spot pricing in Texas surged to $9,000/MWh for 90 minutes and exceeded $1,000/MWh for over 10 hours.

ERCOT set a new record on August 12, when demand reached an all-time high of 74,666 MW. To the state’s advantage, wind production was at 9,900 MW on August 12, which prevented average prices from surpassing $450/MWh. On August 13, with demand soaring above 74,000 MW and a shortage in reserve capacity, real-time prices averaged $8,600/MWh for the peak hours (4 PM – 6 PM) and $1,060/MWh for the entire day. Similarly, as system-wide wind generation plummeted to 4,455 MW on August 15, real-time prices averaged $9,000/MWh for the peak hours and $1,160/MWh for the entire day. Real-time prices in August averaged $131/MWh, the highest since 2011 and 325% more than in the month prior.

Customers on indexed contracts or served under the “Provider of the Last Resort” would have spent as much as 325% more for their energy usage in August (you can learn more about the risk involved for customers served by Provider of Last Resort in our Texas market commentary for July 2019). For every 1000 kWh used, customers floating at a market rate would have paid $131 in August, compared to $30 during July. Customers with open positions should consider hedging from the uncertainty stemming from this level of market volatility, and are advised to speak with their Energy Advisor to determine their options.

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

PG&E Files Plan of Reorganization to Exit Bankruptcy

On September 9, Pacific Gas and Electric (PG&E) filed its plan of reorganization, taking a step forward in exiting its current Chapter 11 Bankruptcy protections. Since filing for bankruptcy on January 29, PG&E has faced significant challenges to its attempts to regain financial solvency. Facing potential liabilities of more than $30 billion for its role in starting wildfires in 2017 and 2018, the reorganization plan provides some insight into the company’s strategy for managing its liabilities to victims, insurers, and generators before the June 2020 deadline for entrance into the state’s wildfire fund.

California wildfire investigators determined in May that PG&E transmission lines were responsible for igniting the 2018 Camp Fire in Northern California. The ruling came as no surprise to the utility, as it had already acknowledged in February that its equipment was likely what started the deadly fires. Combined with wildfires that PG&E was charged with starting in 2017, this left the company facing total liabilities of more than $30 billion.

In June, the company’s investors proposed a restructuring plan that allocated $16 billion to $18 billion to pay for wildfire claims. However, the company opted not to go with the investors’ plan. In their official reorganization plan, PG&E capped total compensation of wildfire liabilities at $17.9 billion, with $8.4 billion allocated to wildfire victims, $8.5 billion to insurers, and $1 billion to public entities. The plan claims that funding would come from raising $14 billion in equity “over the next several weeks,” and would have no effect on current electricity and gas rates.

The capped total valuation has drawn considerable criticism from victims’ legal representation, as the amount is significantly lower than the company’s initial estimated liabilities. On September 13, PG&E announced it had reached a settlement of $11 billion with insurers, almost $3 billion more than the amount allotted in its plan filed 5 days earlier. The company has not reached a settlement with victims who were not insured. Those liabilities for wildfire damages will be assessed by the U.S. District Court and will be incorporated into future PG&E bankruptcy proceedings.

The reorganization plan asserts that PG&E will be able to complete its restructuring and exit Chapter 11 protections by the June 30, 2020, deadline set in Assembly Bill 1054 (AB 1054), California’s wildfire fund. AB 1054 was passed by the State Assembly in July with the intention of providing a $21 billion financial backstop to the state’s three largest publicly owned utilities. The law was largely brought on by the bankruptcy of PG&E, California’s largest publicly owned utility, which caused financial liquidity problems for Southern California Electric (SCE) and San Diego Gas and Electric (SDG&E), due to their future wildfire liability risk. SCE and SDG&E both entered into the fund, together contributing $2.85 billion to the fund by the end of 2019. The approaching deadline places significant pressure on PG&E to emerge from bankruptcy swiftly, as future equity commitments will likely be predicated on the company’s protection from future liability risk through AB 1054. If PG&E is able to meet the law’s criteria by the June 30, 2020 deadline, the company will have to contribute $4.5 billion upon its admittance. 

PG&E ran into another hurdle prior to the release of its reorganization plan, when state legislators pushed back deliberation on Assembly Bill 235 (AB 235) to 2020. The bill would have provided $20 billion of financing by allowing the utility access to state-issued tax-exempt bonds, and allow the company to restructure before the June 2020 deadline. The high level of scrutiny that came with a bill that has been branded as a taxpayer-funded “PG&E Bailout” forced lawmakers to push further deliberation on the matter to 2020, when a decision may come too late to meet the wildfire fund deadlines.

Generators supplying PG&E and its customers have faced potential losses as a result of the bankruptcy, with the utility contesting many Power Purchase Agreements (PPAs) amid its restructuring. Since January, PG&E renegotiated or canceled over 100 megawatts (MW) of generation and storage projects. However, in its plan of reorganization, the company stated that it will assume “all power purchase agreements and community choice aggregation servicing agreements.” Community choice aggregators will find some relief in this, as the potential of renegotiation or cancelation would inevitably be passed through to their customers.

While the reorganization plan provides some clarity into PG&E’s restructuring strategy, there are still items that have yet to be addressed or are subject to change. Hearings on total liabilities began on September 10, and the company will be submitting their final plan by September 29. While the company’s current plan is described as rate-payer-neutral, there is still uncertainty regarding whether tax- or rate-payer funding will be required to fund some of PG&E’s total liabilities.

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

CFE Rates Down ~1.92% in September, 20% to 22% Lower than Last Year

The CFE published its rates for their Basic Service customers for September. Rates moved slightly lower by about 2.20% for capacity and 1.92% for energy. The August to September decrease was drastic compared to the increase that was seen a year ago, when prices began their dramatic escalation that continued until October 2018. While the lower seasonal demand has kept the rates constant during the winter and the first months of spring, commercial and industrial customers began paying lower rates this month compared to the CFE rate a year ago. For this month, capacity costs have decreased 22% and energy costs have decreased about 20% year-after-year.

The chart on the right shows the capacity prices in the Monterrey region for the GDMTH tariff, where prices for September 2019 are just under $354 MXN/kW-month. This represents a 2.20% decrease compared to the August rates, and a 22% decrease relative to last September’s rates, which registered at just $456 MXN/kW-month. The capacity component accounts for roughly 15% to 25% of overall energy costs.                                                                                                            

Energy rates showed a similar slight down movement in September. The chart below shows energy prices for the Aguascalientes region of the GDMTH tariff, load-weighted for each tranche assuming an average of 30% base consumption, 60% intermediate consumption, and 10% peak consumption. September energy prices decreased by about 1.92% in most regions compared to the previous month, roughly 20% compared to September 2018. Load-weighted prices in Aguascalientes have decreased from $1.829 MXN/kWh in September 2018 to $1.468 MXN/kWh in September 2019, a 20% decrease over that period. The energy component of customers’ bills usually makes up 50% to 70% of total costs.

In December 2017, the Energy Regulatory Commission in Mexico (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 part of the bill.

Customers nationwide have had to face the price growth experienced throughout 2018 that 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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