US power landscape prepares for markets, demand to heat up with summer

OREANDA-NEWS. June 25, 2015. Summer for the power markets typically means volatility as demand shoots up with hot weather and prices bounce around as generators and traders try to provide the energy where it is needed.

Before each summer, grid operators across the United States gear up for the season by letting the stakeholders know how they are preparing in their summer outlooks. The outlooks share what the grid operators are expecting for peak loads and how much generation capacity will be available to meet the demand. For the power markets, preparing for the season means getting a handle on these outlooks and where prices are ahead of summer.

This year, some of the markets are seeing downward pressure on prices as the weak natural gas environment has been weighing on power.

Other markets, such as those in the West, are seeing shifting dynamics as the region deals with drought and a changing energy mix.

Nation’s largest grid operator, the PJM Interconnection, said in its 2015 summer outlook it was projecting a peak demand of 155,544 MW and a reserve margin of 20.8%, compared with 2014’s outlook that called for a peak 157,279 MW and a reserve margin of 25.4%. While the reserve margin is lower than last year, it is not surprising given all the retirements that have occurred in the PJM territory.

Looking at how PJM West summer prices are shaping up ahead of summer, one can see that prices are hitting some of their lowest levels of the year, largely because of the weak gas markets (more about that below) after being relatively flat most of the year and seeing some peaks last month.

Now shifting over to the Texas market, we’re seeing forward prices in ERCOT a fraction of where they were only a year ago. In 2014, ERCOT North Hub July-August on-peak peaked at \\$104.20/MWh on April 29, compared to this year when that same package sank as low as \\$41/MWh on June 5.

The lowest that North Hub July-August on-peak values fell in 2014 was \\$67.85/MWh on June 17, 2014. The highest that package has reached so far this year is \\$63.50/MWh on January 2. Currently, the North Hub July-August on-peak package trading around \\$43/MWh. At this same time last year it traded closer to \\$81.25/MWh.

ERCOT North Hub July heat rates are currently around 14,000 Btu/kWh while August heat rates are currently near 15,175 Btu/kWh, compared to this same time last year when the July 2014 heat rates averaged  to 17,263 Btu/kWh and the August 2014 heat rates were roughly 19,190 Btu/kWh.

The sinking NYMEX gas futures are pulling down electricity prices. NYMEX front-month contract has fallen from a high of \\$6.149/MMBtu on February 19, 2014, to a low of \\$2.49/MMBtu on April 27, 2015, which is the lowest point in nearly three years. Currently, NYMEX July futures are averaging \\$2.75/MMBtu so far this month.

And with 48.8% of electricity in ERCOT coming from natural gas-fired plants so far this year, the drop in gas prices have significantly impacted electricity prices.

In 2010, coal plants were the lead fuel source in ERCOT providing 39.5% of electricity compared to 38.2% from gas. This year, gas is accounting for 48.8% of ERCOT’s generation, while coal has fallen to 26%.

ERCOT officials expect to have sufficient resources to keep up with summer demand, according to the latest seasonal assessment report released in early May. The grid operator expected peak load to hit around 67,986 MW this summer, according to the report.

ERCOT’s all-time peak demand record is 68,867 MW set on August 3, 2011. Last year, demand in ERCOT hit 66,440 MW on August 25, 2014.

Unusually extensive generation outages during extreme weather or localized challenges in some areas (such as the Lower Rio Grande Valley) could result in a need to reduce demand on all or part of the system, the report said.

And already on June 3, ERCOT called on Lower Rio Grande Valley customers to reduce electric usage after 556 MW went offline unplanned coupled with early summer high demand. ERCOT took the precautionary measure to ensure that ERCOT could maintain overall reliability in the region during the high-demand period.

But then day later, another 488 MW in that same region suddenly went offline. Still, ERCOT did not initiate rotating outages.

Last fall, it was a different story when three generating units suddenly went offline on October 8, 2014, in the Lower Rio Grande Valley. ERCOT did initiate rotating outages for about an hour due to the generation loss. The next day a transmission line tripped and led ERCOT to issue a second emergency notice in as many days for the Lower Rio Grande Valley.

It was the fourth time in ERCOT history it had initiated rotating outages. Other events occurred in 1989 due to cold weather, April 2006 due to hot weather and February 2011 due to cold weather.

The Lower Rio Grande Valley is located at the southernmost tip of South Texas and borders Mexico. As one of the fastest growing – and poorest – areas in the country, the Valley is vulnerable due to its limited electric generation and transmission infrastructure. With the Valley population already at roughly 1.5 million and expected to increase more than 1 million by 2020, companies are working to build new lines and upgrade existing equipment.

Now shifting to the West, we’re seeing some shifting dynamics in the wholesale power markets for California, which is grappling with a continued drought, and the Pacific Northwest, which saw below normal precipitation this winter and is translating into lower stream flows.

For California summer power prices, we’re seeing NP15 third-quarter peak packages take on a slight premium over SP15 third-quarter peak packages.

Typically, SP15 packages hold a premium over NP15 as load centers and demand is mostly in the southern part of the state.

However, Northern California hydro generation this year is not performing as it has in the past and Southern California is also seeing an influx in solar generation, which is adding some downward pressure on prices for that region.

Looking at prompt-month power packages for the Pacific Northwest and Southern California, the market has recently seen Northwest prices climb above Southern California prices.

Right around the middle of June the market saw Mid-Columbia July on-peak packages jump above SP15 July on-peak packages.

The abundance of hydro generation in the Northwest has mostly kept Mid-C prices trading at a discount to SP15, which allows imports to California. However, Mid-C day-ahead on-peak prices have on occasion seen monthly averages come in slightly higher than SP15

When it does, it has typically occurred during a winter month as the Northwest is seeing its peak demand or in extreme event like the California energy crisis, which the Northwest was at that time also experiencing below-normal water supplies.