Our February “Energy Market Outlook Webinar,” focused on several topics, including:
- Energy-related weather outlook
- Power and natural gas trends versus year-ago record lows
- New generation builds in 2017
- Energy policy update from David Brown, SVP Exelon Federal Affairs group, on impacts of the Trump administration in the White House
The webinar, which you can access by clicking here, inspired a few questions from some of our guests. We answered a few questions last week with input from principals in our Commodities Management Group. Here are a few more questions and answers.
Question: If forward natural gas prices are lower, then why are forward electricity prices higher for ERCOT?
Forward natural gas prices for 2017-2018 reflect the current market environment of both lower production and storage on a year-over-year basis. Prices for 2019 and forward are lower, as production is expected to continue growing in those outer years. The current ERCOT forward calendar strips reflect an excess over generation in a market that has seen little price volatility since 2011. However, it continues to grow load annually at an overall faster rate than other regions. The rising forward prices over time reflect a demand for power for future use. ERCOT does not have a capacity market. It is an energy-only market and thus higher forward prices are intended to send a signal to the market for future capacity. While ERCOT has rising power prices in the future, those prices may still not be high enough. One mitigating factor has been the build-out in wind capacity. It is at 19 gigawatts (GW) now, the most of any state in the U.S.
Question: Is it possible for President Trump's policies to affect the pipeline exports to Mexico?
It cannot be ruled out that the Trump administration could impact U.S. pipeline exports to Mexico. It is important to realize significant investments are already underway that will likely have a positive impact on the U.S. Specifically the Texas economy since 80 percent of U.S. exports originate in that state. As a recent EIA Today in Energy article stated, the export capacity of the U.S. border crossing pipelines is set to expand a lot in 2017 and 2018 from the current 7 Bcf/day to 14 Bcf/day (see chart below). While these pipelines will not be fully subscribed - current U.S. exports are 4 Bcf/day - it demonstrates the growing demand for U.S. natural gas in Mexico to meet growing power-generation demand.
During Secretary of State Rex Tillerson’s recent visit to Mexico in February, border security and trade were on the agenda with Mexican officials.
Question: Do the gas storage numbers really matter anymore since gas is so plentiful and able to be retrieved so quickly now?
Natural gas storage does still matter. It is still one of the key drivers of NYMEX prices in not just the prompt month, but the 12-month rolling term. As the year-over-year storage deficit narrows, prices generally decline (likely a result of a warmer than normal winter or cooler than normal summer). The inverse is true for a surplus that increases.
The market is always looking forward to the beginning of the next winter season to see if it will have adequate storage levels. For example, prices were averaging $4.50/MMBtu in April 2014 because we ended the winter at 822 Bcf, the lowest level since 2003. In April 2016, we had 2,400 Bcf of gas and prices were under $2/MMBtu, hitting a 17-year low of $1.61/MMBtu in March 2016.
Question: What impact will the Keystone Pipeline have?
The Keystone Pipeline and North Dakota access pipelines were granted expedited environmental reviews under an executive order issued on January 24th. The North Dakota Access will bring more Bakken crude south to the Midwest markets. The Keystone Pipelines will bring both, more crude from western Canada and Bakken as it makes its way south through the Bakken. The ability to bring more crude oil from both of these areas to the Midwest and Gulf refineries will likely increase oil supply to the Midwest. The impact of the Keystone Pipeline on gas prices over the long term will be higher associated gas output. This will be especially true in the Bakken if oil production continues to expand there.
Question: What is going on with the restructuring of PEMEX?
In 2016, the Mexican Senate passed amendments to the Mexican Constitution allowing foreign investment into the Mexican energy sector. PEMEX is primarily focused on growing oil production. In 2016, the Mexican power grid operator, CENACE (Centro Nacional de Control de Energía), began to allow day-ahead and real-time wholesale trading for power markets. Mexico will continue to rely on increased imports of U.S. natural gas to meet gas-fired power generation capacity in Mexico. Some recent EIA articles highlight the changes occurring in the Mexican energy markets.
Question: Where do you see electric prices going in the Northeast? Does it make sense to lock in 1-year, 2-year or longer terms?
Power prices in the Northeast will likely continue to be affected by many factors. One primary factor will be regional gas prices, such as Algonquin City Gate for New England and Transco Zone 6 New York for the New York City area and Non-New York for the Mid-Atlantic. Power prices will also be influenced by costs for non-energy components, such the annual capacity auctions in PJM and ISONE, transmission line enhancements and state modifications to Renewable Portfolio Standards (RPS).
Winter weather especially will be a key driver of regional gas prices. While the past two winters have been mild, a look back at the Polar Vortex during winter 2013-2014 highlighted the possibility of volatility. Locking a 1-year, 2-year or longer term depends on the level of budget certainty desired and what current procurements are in place. As this winter showed, it is very hard to predict how seasonal demand will occur. Taking a managed approach of layering in forward purchases either through Constellation’s Flexible Index Solution or Minimize Volatile Pricing (MVPe) can be a cost beneficial approach to take advantage of weather seasonality and market volatility.
Question: Where is the regional production?
Regional gas production in the Lower 48 states is focused primarily in three key regions: the Northeast, the Gulf Coast and Gulf of Mexico and the Rockies. Also, virtually all of Canada’s production comes from the Alberta and British Columbia regions of western Canada.
The map below from EIA identifies all the shale plays in the Lower 48 states. Right now, the largest producing area is the Marcellus and Utica Shale. These areas are currently at a combined 22 Bcf/day, followed by the historical producing region of production (Texas, New Mexico, Louisiana, & Oklahoma), as well as Gulf of Mexico production at about 3 Bcf/day. Out west, the Rocky Mountain States are the third largest producing area followed by the Bakken in North Dakota. Current shale dry production is approximately 42 Bcf/day out of about 71 Bcf/day of total gas production. Non-shale conventional production is primarily focused in Texas, Louisiana, Oklahoma, Kansas and Rocky Mountain States.
EIA recently noted that of the seven shale regions listed below, only the Eagle Ford in south Texas would see a month-over-month decline in output in February and March. This is the first time since March 2015 that more than five of the seven shale plays are seeing growth in production.
- Natural gas-fired power plants lead electric capacity additions in Mexico
- U.S. energy trade with Mexico: U.S. export value more than twice import value in 2016
If you have questions, reach out to us!