Q3 2020

The RealPage® Energy Outlook

About the Energy Outlook

Get the details on pricing trends, weather, storage levels, tariffs and more.

The Energy Outlook is designed to inform you about the current state of the natural gas and electric energy markets. While prices are most important, we offer insights into the drivers of the energy markets and shed some light on how these drivers impact market prices. The primary energy market drivers fall into 2 areas: Fundamentals and Politics.

  • Fundamentals are the factors influencing energy supply and demand of electricity and natural gas. Supply factors include power generation, natural gas production (drilling rigs, fracking, and horizontal boring), underground gas storage, and pipeline capacity. Demand factors include consumer usage and weather (driving how much energy is required for heating and air conditioning seasons).
  • Politics include changes to the legal and regulatory environment that can cause major moves in energy prices. Political impacts can be new emission standards, such as mandated movement to cleaner generation facilities with higher operating costs, new energy taxes or fees, and restrictions on new pipeline or transmission line placement. Political factors can be domestic or international.

2020 Q3 Energy Outlook

Small Uptick in Energy Prices, Yet They Remain Attractive

Brutally hot weather has gripped the country over the last few weeks, yet we haven’t seen any associated price spikes. Natural gas demand has increased by 9% over the first two quarters of 2020. There was additional gas-fired electric generation even though overall electric generation has dropped by 5%. Recent low natural gas pricing and new developments of gas-fired generation plants have increased demand for the clean burning fuel. The 12-month NYMEX natural gas curve moved up by 1.3% over the last couple of weeks but electricity prices have fallen by less than a percentage point.

Natural Gas Storage

Healthy Storage Continues to Grow

Natural Gas Chart

The Energy Information Administration (EIA) “Natural Gas Storage Report” shows working gas in storage was 3,215 as of Friday, July 17, 2020, according to EIA estimates. This represents a net increase of 37 BCF from the previous week. Stocks were 656 BCF higher than last year at this time and 436 BCF above the five-year average of 2,779 BCF. At 3,215 BCF, total working gas is on the higher end of the five-year historical range.

Natural Gas Storage Levels (Bcf)
Current Storage Level 3,215
Storage – One Year Ago 2,559
5-Year Average Level 2,779
Natural Gas Chart

The traditional injection season into the natural gas storage starts in April and ends in October. As of June 1, storage levels were 18% above the 5-year average. June and July came in unusually warm, yet strong injections kept the storage levels at 15.7% above the 5-year average. If the weather cooperates and the industry can hold on to 5-year average injections for the rest of the season, analysts are predicting that the storage at the start of the heating season in November would be at 12% above the 5-year average—a very comfortable level.

Weather will be the driver over the next few months. The recent heat waves are making it challenging for the gas industry to make sizable injections into storage to maintain a healthy surplus. Sweltering heat creates a high demand for air-conditioning loads throughout the US, and with natural gas as the fuel of choice for generation plants, this creates an unbreakable dependency. We are currently at 15.7% above the 5-year average compared to 20% above at the end of last quarter. We shall see how this story unfolds in the next few months due to weather influence, COVID-19 impacts and the hurricane season, which is just starting.

Weather Forecast

What is HOT & Red All Over?

And the answer is, U.S. weather over the next three months. NOAA’s weather service is predicting a high probability of above average temperatures across the country during August, September and October. Everywhere we look from Alaska to California to the Southwest, Florida and the Northeast, we see over 70% probability for above average temperatures. The middle of the country has a lesser probability, but it is still shaded above normal.

Earlier in the season, several weather models pointed to increased hurricane activity for the 2020 season. The risk for a direct hit from a storm is higher than normal for the Gulf and East Coasts. Tropical storm Hanna hit the Texas coast in late July. Hanna was the eighth named storm of the season so far. The first tropical storm, Arthur, formed off the coast of Florida in May, followed by Bertha, which made landfall near Charleston, South Carolina. This is the sixth year in a row that a tropical storm developed prior to the official start of the season, which is June 1. Warmer than normal water temperatures can be a big factor for increased number and intensity of storms.

NOAA Heat Map

Energy Prices

Near-Term Prices Are Slightly Up – Long-Term Prices Are Flat

The Energy Outlook mainly focuses on natural gas prices, because gas prices lead electricity prices. As natural gas prices increase or decrease, electricity prices often follow suit – whether it’s hours, days or weeks later. Also, natural gas has a national price established on the NYMEX. Other regional prices and markets exist but are compared with the NYMEX prices. Electricity is different because the U.S. is divided into six regional markets, each setting its own price and having its unique market rules. All six regions tend to move in the same direction, but price volatility and generation vary considerably between regions.

Natural Gas 12-month strip prices have maintained over the last quarter with a recent uptick. Higher natural gas fired electric generation has kept demand up. The COVID-19 pandemic has slammed on the breaks for the liquified natural gas exports market, but market expectations are showing signs of revival for LNG exports in the fall.

Currently 12-month strip prices are at $2.55 per MMBtu. Monthly settlement prices have stayed below $2.00 since February 2020. Next winter strip (November 2020 through March 2021) is averaging at just below $2.90.

Energy Price Graph

After a brief uptick to around $42 earlier in the week on July 19, West Texas crude oil prices ended the week at $41.29 per barrel, slightly higher than the prior week’s close of $40.45. The trading range has remained narrow at $2.50 per barrel. The latest EIA crude oil inventory report stated a build of 4.9 million barrels, well above expectations of a 1.95-million-barrel drop. Current storage inventories are at 19% above the seasonal average.

For the economy, the Senate and the House of Representatives are working on an additional coronavirus relief bill so they can extend jobless benefits which expired at the end of July. The federal Reserve, on the other hand, will release U.S. manufacturing data and a preliminary look into Q2 GDP estimates.

At this point weather is the only bullish parameter pushing on energy pricing. July 2020 has been one of the hottest months on record. As stated earlier in this outlook, extreme heat is expected in the Northeast and the West. Two-week models and beyond are still showing above average heat expectations.

Electricity pricing for all deregulated markets fluctuated slightly on the week with increases and decreases of magnitudes under 1% with ERCOT and CAISO strips showing the “biggest” drops in price.

Energy Price Chart
Energy Price Graph

Regional Electricity Outlook

Electricity markets are complex, and there are many regional markets. The regional markets may differ from the overall continental energy outlook. Warmer than normal summer temperatures and continuing social distancing measures due to COVID-19 are the major factors for the foreseeable future.

New England’s Average real-time electricity staying low.

Average wholesale power prices were down 5.6% in the Real-Time Energy Market in June 2020 when compared to the previous year, at $21.17 per megawatt-hour (MWh)*. Prices were down by 10.2% in the Day-Ahead Energy Market when compared to June 2020, averaging $19.84/MWh.

Power plant fuel: Fuel is typically one of the major input costs in producing electricity. Natural gas is the predominant fuel in New England, used to generate 49% of the power produced in 2019 by New England’s power plants, and natural gas-fired power plants usually set the price of wholesale electricity in the region. As a result, average wholesale electricity prices are closely linked to natural gas prices.

Electricity demand: Demand is driven primarily by weather, as well as economic factors. Energy usage during March increased by 4.6% compared to June 2020. The average temperature during June was 69˚ Fahrenheit (F) in New England, two degrees higher than prior year. The average dewpoint, a measure of humidity, was 56˚F in June, up one degree from June 2019. There were 67 cooling degree days (CDD)*** during June, while the expected number of CDD was 50 in New England. In June 2019, there were 31 CDD. Social distancing measures due to COVID-19 are causing an additional 3-5% decline in consumer demand.

Fuel mix: The mix of resources used in any given time period depends on price and availability, as well as supplemental resource commitments needed to ensure system stability. Natural gas accounted for 57% while nuclear was at 25%. Renewable resources were at 13% while hydro generation was at 5%.

PJM is Prepared to Meet Summer Demand.

Power system operators at PJM were prepared to serve a forecasted summer peak demand for electricity of approximately 148,000 MW. This assessment of PJM’s operational preparedness reflects a more conservative high peak-demand day and does not reflect the current decrease in demand experienced as a result of the coronavirus pandemic. PJM has over 187,000 MW of installed generating capacity available to meet customer needs, with sufficient resources available in reserve to cover generation that is unexpectedly unavailable, or for other unanticipated changes in demand.

Last year’s peak demand was over 151,000 MW, which occurred on July 19. PJM’s all-time, one-day highest power use was recorded in the summer of 2006 at 165,563 MW. As a rule of thumb, one megawatt can power about 800 homes. This year we already tested the ceiling with a peak load of 145,372 MW on July 20. PJM has issued 13 peak day alerts so far in July not including the latest alert on July 26 through the 28.

PJM’s resource mix mirrored prevailing trends, marked by the rising incidence of natural gas and renewables, a decline in coal, and a slight decline in nuclear.

The New York Independent System Operator (NYISO) July 22 Update

The New York Independent System Operator forecast power demand in its footprint reached nearly 30 GW on July 20 and the grid operator had activated Special Case Resources and Emergency Demand Response Program Resources in the Targeted Demand Response Program. Temperatures were over 90 degrees Fahrenheit around 3 pm ET, with nearly 80% humidity in the Hudson Valley region.

The New York Independent System Operator forecast power demand in its footprint reached nearly 30 GW on July 20 and the grid operator had activated Special Case Resources and Emergency Demand Response Program Resources in the Targeted Demand Response Program. Temperatures were over 90 degrees Fahrenheit around 3 pm ET, with nearly 80% humidity in the Hudson Valley region.

Real-time power prices averaged in the low- to mid-$20/MWh range in the late afternoon, with slightly higher prices in Long Island Zone K of $59.91/MWh, according to the NYISO website.

The NYISO’s Operations and Demand Forecasting teams continue to monitor and assess changes in electricity demand level and consumption patterns to further refine daily and longer-term demand forecasts. This ongoing assessment includes evaluating demand patterns, updating economic forecasts and engaging with local utilities.

Texas Energy Summary

The ERCOT market was quiet last week (7/20-7/27) with real-time prices averaging $19.30/MWh for the week with a high price of only $54.96/MWh as temperatures were in the mid-90s and wind production was averaging above 2,000-5,000 MWh in late afternoon hours.

Tropical Storm (TS) Hanna hit the Texas Gulf Coast in late July, causing concern for the Gulf Coast energy infrastructure and possible impact on the ERCOT market. TS Hanna was expected to make landfall in Corpus Christi on July 25 with wind speeds up to 50mph. The storm’s path included 5.6GW of wind generation around the Rio Grande Valley area. Costal wind generation is important in the ERCOT market because in late afternoon hours, coastal wind farms can average 63% of their name plate capacity compared to Panhandle or inland wind farms that produce only 29% and 16% of their capacity respectively. Although TS Hanna could have caused damage to offshore wind turbines that would decrease the supply of wind generation during peak hours, demand also significantly decreases and may even take days to recover. Overall, TS Hanna had a bearish impact on prices, but future storms could damage windmill capacity for a period of time and reduce generation that ERCOT has available to it in peak summer conditions.

ERCOT has seen its operating solar capacity almost double to 4.3 GW from just 2.3 GW in December 2019. An additional 1.6 GW is in the works for 2020, which would bring total installed solar capacity to 5.8 GW is by the end of 2020. This increase in solar capacity is one of several factors contributing to lower average real-time on-peak locational marginal (LMP) prices this summer. LMP prices are down almost 44% compared to 2019 but peak demand is up 1.9% year-over-year. While solar plays a large role in serving peak demand because solar’s output is strongest from 10 AM to 4 PM, other factors such as COVID restrictions the curtail load, strong wind output this summer so far and lower natural gas prices, which are 33% lower year-over-year are playing what could be argued are keeping LMP prices low. While it could be argued whether solar is a dominant factor for lower LMP prices this summer versus 2019, next year could see as much as 11-14 GW of total solar installed capacity, so solar’s growing contribution in ERCOT cannot be counted out.

California ISO News

The LA Basin and Central Valley will flirt with the century mark in temps during the week of July 27. While this will increase natural gas demand as people start using their A/C, there’s a couple fundamentals in play that will prevent large draws from storage and basis blowouts. Diablo Canyon 2 generating plant, which has been on outage, should return in full by the end of the week and the PNW temps will be backing down. PG&E Citygate should settle in the $2.50 – $2.75 range. SoCal Citygate should move back up to ~$2.00/MMBtu. Aliso Canyon generating plant is closed right now on a maintenance outage through August 6 and Citygate pricing will only get to ~$2.00 with the temps setting up as they are is a direct result of the high gas storage levels in the state. In order to pull natural gas out of storage, both Citygates need to price above imports from the Rockies and PNW to avoid a congestion-pricing scenario later this summer.

The latest seasonal updates indicate that a developing La Niña in the equatorial Pacific is looking like it will dig in and influence weather patterns across the U.S. through the end of the year. What this typically means for the West is a warm and dry winter. This is a warning for possibly another rough fire season in 2021.

CAISO just set a new record for solar generation on June 29 when the meter read 12.016 GW at 12:32pm; an impressive 93.3% capacity factor given the CAISO’s metered solar capacity of 12.875 GW. In addition, there is roughly another 8.5 GW of solar capacity lurking on California’s grid in the form of residential and commercial rooftop arrays that are unmetered. Solar represents 54.9% of the 23.448 GW of installed renewable capacity (solar, wind, hydro, geothermal, etc.) as of July 1.

Understanding the largest source of renewable generation on the grid is helpful to understand the staggering amount of renewable generation curtailment that has taken place this year. As renewable generation on the grid has increased over the last four years, the CAISO has been forced to curtail generation in ever increasing quantities to prevent damage to transmission lines and associated equipment. Curtailments most often occur in the middle of the day as behind the meter solar is peaking and load is disappearing from the grid. Since thermal generation and imports are typically running at minimum levels during this time, the only lever left to pull to balance the grid is curtailing output from wind and solar projects. In June, the CAISO curtailed 206.4 GWh of renewables, which were down from 255.3 GWh in May and 318.4 GWh in April. Year-to-date, there has been 1,280 GWh of renewable output curtailed, roughly equivalent to turning both generating units at Diablo Canyon off for about 26 days.

Bottom Line

Long-Term Natural Gas Prices Remain Low

Buy! Multi-year gas and electricity contracts remain low. Both the natural gas and electric market prices have been volatile but within a narrow range. Prior to COVID-19 natural gas producers had started to reduce rig accounts and they have accelerated since then. The associated drop in natural gas production has not yet manifested itself in the market’s supply data. Temperatures were above normal for both June and July and are predicted to be above normal for the remainder of the summer. The upcoming U.S. Presidential elections, international geopolitical news and the current resurgence of COVID-19 could exacerbate the situation. Work with your trusted broker on long-term pricing strategies in order to avoid market volatility and ensure some budget certainty.


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