Energy Management

Hot June, Slow Production Could Mean Higher Energy Prices

4 min read

If you were feeling the heat, you weren’t alone—this past month was the second-hottest June on record nationally, according to MDA Weather Services.

Patterns for La Nina, the fluxes in temperature between the ocean and atmosphere, show early indications the Midwest and East regions could be in for a warm July and a hot August.

Coupled with a declining surplus in natural gas and slower oil and natural gas production, this means we could see energy prices rising through the end of the year. Near-term forward power prices are following a trajectory that’s similar to 2012 in many parts of the country. If natural gas markets continue to tighten, that’s a good indication we’ll see increases similar to what we experienced four years ago.

The red lines in the graphs below illustrate where regional power prices are sitting so far this year. The blue lines show the upward trend we experienced in 2012.


Each power market is also influenced by several regional factors, such as natural gas pipeline delays and coal and nuclear power plant retirements.

In our latest webinar, we discussed some of these trends that could possibly impact energy prices, as well as strategies for mitigating costs and improving reliability. We also took the time to answer some of your burning questions about supply, demand and pricing. Here are just a few of them.

With increased demand, lower production and futures three years ahead average about $3, is $3 adequate to bring back natural gas production?

Much of the Marcellus and Utica shale region has breakeven prices that are well below $3/MMBtu. Some of this new production could be constrained by pipeline capacity that’s available to move additional natural gas. For example, a new pipeline to move gas from northeast Pennsylvania to New England is being blocked by the State of New York. In Texas, $3/MMBtu prices would likely lift output in lower cost parts of the Eagle Ford, Permian and Haynesville shale in Los Angeles.

While the breakeven economics of the Marcellus are impressive, it is only 30 percent of U.S production. To extract gas out of Texas, Oklahoma and Los Angeles is generally going to be more expensive than in Marcellus/Utica. Also, there are transportation costs of moving Gulf Coast gas north or moving gas from the Northeast to the South. These factors mean prices may need to increase to $4 per MMBtu or higher to boost higher production.

Are there any major infrastructure investments started to handle natural gas distribution?

There have been several pipeline reversal projects that have reversed natural gas flows out of the Marcellus and Utica shale plays. For example, Rockies Express (REX) pipelines zone 3 can flow east to west out of Clarington, Ohio, as far west as Mexico, Mo. Several pipelines that run from the Gulf up to Midwest and Northeast are reversing flows and interconnecting with REX. These include Texas Gas Transmission, which began bilateral flows in early June. Other interstate pipelines such as Transco, Columbia and TETCO all have reversal projects at different stages.

There are several projects underway to move Marcellus gas to Ontario, Canada. The two biggest are NEXUS (1.5 Bcf/d) and Rover (3.2 Bcf/d) pipelines, which are competing to move from Ohio into Michigan. It is unclear at this point if they will both get built by the 2017 to 2018 timeframe.

What do you think will have a greater influence on the market: Extreme warmth to drive prices higher, or high end-of-season natural storage to drive prices down?

Current weather is having a bigger impact on the market in the short run. We just experienced the second-warmest June since 1950. This has boosted gas-fired generation demand on a national level by over 2 Bcf/d. If the hot temperatures remain, that could support NYMEX prices at $3/MMBtu if injections into storage remain below year-ago levels.

If natural gas production levels remain flat or climb above year-ago levels, that could put downward pressure on prices. Storage was at 3.1 Tcf as of June 17. We usually hit 3 Tcf in late August, so it is very likely we will get to over 4.0 Tcf by end of October.

The string of seven weeks with injections below year-ago and five-year average levels have helped support NYMEX prices. However, the further it runs up, the more competitive coal will be against gas. If gas-fired generation levels decline, you could see a pullback in prices. If weather moderates in August and injections are exceeding year-ago levels, then the supply surplus would be a bigger driver.

How do the trends in market pricing compare with the trends in utility pricing? Are they trending similarly, or are utility prices getting more competitive?

Utility pricing for energy is usually determined in load auctions held in regular intervals some time period before power term. These load auctions can be for varying terms, but with an overall correlation between gas and power prices in most markets, lower gas prices should translate into lower power prices.

When is ideal time to lock in forward electric rates in the Texas market?

Power markets in ERCOT are some of the most highly correlated to gas markets given Texas’ proximity to Henry Hub in Los Angeles and the largest amount of gas-fired capacity in the state. Pursuing a dollar-cost-average strategy in Texas can be beneficial since the power markets reflect the cyclical nature of the gas markets.

What can I do to minimize my risk of power outages?

Over the years, the monthly average of grid outages has increased six-fold. In 2000, there were an average of 2.5 grid disruption events per month, and by 2014, we were averaging 20 disruptions per month.

Power outages can be catastrophic for businesses. For hospitals, it can mean putting patients’ lives at risk. Manufacturers lose valuable production time, and food production companies that rely on cold storage can lose thousands of dollars in inventory. Constellation offers backup generation solutions that can be bundled into electric supply contracts so no upfront capital is required. Customers pay a monthly backup generation service fee called a reliability rate, while Constellation is responsible for owning and maintaining the system. The total cost is less than most customers would pay to own and maintain a backup generation system themselves.

To learn more about solutions for managing energy prices in 2016 and beyond and ensuring reliability, talk to your Constellation representative or contact us today.

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