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June Webinar Price and Export Forecasting Q&A

 

June Webinar Price and Export Forecasting Q&A

Posted by Constellation on July 18, 2017

During our June 2017 Energy Market Outlook Webinar, we received a lot of questions from attendees. We have followed up with the individuals to provide answers, but also found that the insight from these answers could be beneficial to all. The questions and answers below touch on forecasting for both energy prices and natural gas exports facing the market.

  • Do you foresee future US policy being created to keep domestic prices for US produced energy (gas, etc.) lower than the export price as the demand for US energy exports rise?

    At this time there is likely to be little action from the Trump administration in regards to keeping domestic energy prices artificially low.  
  • Forecasting ahead, how much of an increase can we see in MW prices due to LNG exports by 2020-2022?

    Forecasting the price impact on wholesale power prices from LNG exports largely depends on how much forward gas prices increases. A general rule of thumb for calculation of the impact of gas prices on power prices is to take an increase in gas prices x heat rate (operational efficiency) for gas fired generation. Natural gas units generally operate at a 7-8 Heat Rate so any increases in gas prices would have to be multiplied by that factor. While the NYMEX may only move so many $/MMBtu on a cold winter, regional constraints could force spot prices much higher in winter months. We saw this in 2014; an example is Chicago City Gate that traded as high as $40/MMBtu a few days in January 2014. 
  • Could you restate the figure for the Indian/US daily usage of energy, using the 100 watt bulbs example from the webinar? What is the scale of expected effect (rise) in domestic natural gas prices as LNG export facilities come on line? Could this lead to drastic domestic price increases?

    Current production is in the 71-72 Bcf/d range right now for Lower 48 output. So, 8 Bcf/d of LNG export demand would be 11% of current U.S. dry gas production. If growth in demand from the following sources: LNG exports, pipeline exports to Mexico, growing gas fired power generation demand and industrial demand  all totaling  ~18 Bcf/d by 2020 continue to outpace the growth in supply. We have seen this since 2016. Gas prices would likely have to move higher to encourage higher levels of production. Drilling costs have been dramatically reduced over the last several years to under ~approximately $3.50/MMBtu, but factors such as a cold winter could put the market at a further supply deficit for a 6-12 month term and push prices higher. A proactive procurement approach could help diversify market risk vs. one point in time purchase. 
  • Can you speak to the fact that US shale gas producers continue to drill, but not actually produce wells?  The number of DUCs has been growing fast while production is only slightly ticking up year-over-year. Does Constellation have any outlook as to how this surplus of wells might influence natural gas markets in both the short & long term?  Do you believe this will have more relevancies to domestic gas markets, or international?

    EIA tracks DUC wells by region and you can see where the largest concentration is in the Permian basin in TX. The majority of these are oil wells with “associated” gas and oil drilling is currently economical in the Permian basin. Some DUC wells in Marcellus and Utica could be awaiting local pipeline infrastructure or new interstate pipeline capacity such as Rover project to come online. The Rover project will move gas from OH to MI and into Ontario starting sometime in late 2017.

In the past, as new pipeline capacity comes online to move gas out of the Northeast for example production generally has increased. We saw this in 2016 with the expansion of REX Zone 3 bilateral expansion. 

JuneQA_1.pngSource: EIA

  • Are there any trends on basis?

    Generally, as pipeline capacity increases in the Marcellus and Utica shale formations, the basis should improve for the producer. This causes it to move in the opposite direction for the end-user. As one moves south and mid-west, basis is likely to come under pressure to the downside. That means it will benefit the end-user becoming more negative to the NYMEX. There will be ebbs and flows along the way.  The trend can be illustrated by a map provided by Range Resources in a recent investor presentation. It illustrates what basis was for major trading points in 2016 and what forward market projections are for 2020 via Bloomberg. Generally, basis prices rise in the Northeast (become less negative) and decline in the Midwest (Chicago).
    June QA_2.pngSource: Range Resources
  • How do you see the recent weakness in the oil complex spilling into the natural gas market?

    Generally, and all other things being equal, weakness in the oil complex is supportive of natural gas prices.
  • How would the current Arab nation’s diplomatic breaks with Qatar impact US energy price, production, import and export etc.?

    Currently, it may not affect it a lot. Qatar’s exports of LNG are not likely affected in the near term in any measurable way. Of course, over the coming three to five year period, the global LNG market is set for lots of change as the U.S. emerges as one of the major players in the global LNG market. In short order and Australian exports could ramp up at the same time.
  • Compared to the low crude oil prices, do you think the LNG exporting demand will grow 8-10 Bcf/d?

    By 2020 the U.S. will have something on the order of 10 Bcf per day of export capacity. Approximately 6 Bcf per day of that capacity is under contract with various foreign counterparties. To get an additional 2 Bcf per day of spot cargo is not unreasonable, but there will be some challenges along the way. 
  • What impact on our exports will new liquefaction plants in Australia and Indonesia as well as shale plays in China have on our global competitiveness?

     Australia is going to be a major competitor for the U.S. in the global LNG market.  Currently, it appears that the U.S. has the cost advantage relative to Australia, but much of the Australian capacity has been financed and will go to market despite a potential higher unit cost versus the U.S.  No matter how one looks at it, the U.S. is likely a fierce competitive emergent force in the global LNG business. 
  • Are the large number of DUC's a sign that generators believe costs to generate will continue to decrease?

    There may not be a firm relationship between DUCs and generating costs. DUC inventories are a combination of physical logistics of connecting with local pipelines, waiting for new interstate pipeline capacity to come online (ex. REX Zone 3 reversal in 2016) and where producers think gas prices will rise or fall for a future term. 
  • In discussing the "Paris Accord", given the wild expansion demand expected for the Internet of things, could the rate of bringing renewable generation capacity surpass even the expansion needed to feed the new Cloud demand?

    It’s possible, but not likely.

Check out more June Webinar Q&A and reserve your spot for our next Energy Market Outlook Webinar on August 16, 2017

Topics: Energy Management

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