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June Webinar Informational Q&A

 

June Webinar Informational Q&A

Posted by Constellation on July 20, 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 more information based questions. 

  • Do you know why MISO capacity market prices are too low as compare with PJM annual capacity prices?

    MISO Capacity prices have not been as high on a $/MW Day basis as PJM capacity prices due to the large share of coal generation in MISO utility areas and the surplus of excess generation that exists above the 13.75% NERC suggested reserve margin. 
  • What form does ethane export as (i.e. a liquid)? I follow coastal cracker plants; how will the inland crackers ship by rail?

    Ethane is currently being shipped as a liquid. For example, out of Marcus Hook, PA the liquid goes out on ships to Europe. Inland crackers will be able to ship via rail or pipeline.  See the link below to Energy Transfer Partner’s Mariner East pipeline project that delivers Ethane to Marcus Hook: http://www.sunocologistics.com/Customers/Business-Lines/Natural-Gas-Liquids-NGLs/257/
    Source: Sunoco
  • What is the functional bottom on LNG prices, lower than 2.85?

    Picking bottoms is always a losing proposition. If summer weather comes in and stays “normal,” meaning hot and humid, then $2.85 is likely a reasonable support level. That doesn’t mean that you could not see some limited pricing action below that point however. Additionally, if summer weather fails to materialize in a meaningful way in the population air-conditioning load centric centers of the country, then additional softness in gas pricing is likely.  If summer weather turns above normal and stays that way for a month or two, then, there is a good case for significant upside.
  • Making the case that increasing exports of natural gas could have a significant impact on the domestic price of natural gas. You also indicate that the U.S. is now a large exporter of refined products. So has the increased export of the refined products increased the price of those products within the U.S.? If not, why is natural gas different?

    One key difference is that domestic demand for refined petroleum products is not growing in the U.S.  However, demand for natural gas domestically is growing quickly in the U.S. The U.S. is using the same amount of crude oil per day that it did in the mid-1970s. Today we use about the same amount of oil that we did forty years ago, but our population has grown 50% and economic output has nearly tripled over that time.  However, we have increased our demand for natural gas nearly 50% from 2005, so there are very significant differences and drivers in those respective markets.
    Source: EIA
  • Give the run up in load for Data Centers, how  do regional areas plan for load growth when data center companies seem non-committal pursuing marginal cost savings at a better cost effective location?

    Utility control areas and Regional Independent System Operators (ISO) generally have to plan to have an adequate generation reserve margin per North American Reliability Council (NERC) guidelines. These reserve margins are reviewed on an annual basis vs. the actual historical load for a regional area over the last several years. See link below to NERC 2017 Summer Reliability Assessment http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2017%20Summer%20Assessment.pdf
    Source: NERC
  • Seems that as NYMEX futures have been failing to earn their forward carry, we have seen basis numbers rising, so transportation as a fixed % of total delivered cost (TDC) is rising, particularly in the Northeast and mid-Atlantic regions, can you comment on this?

    Rising transportation costs as a percentage of total costs could be a function of covering costs for a lot a recent pipeline reversal projects in the Northeast. As gas can now flow bidirectional the nature of gas transportation costs has been changing.
  • What impact if any on power prices would you expect in ISONE as a result of off shore wind and Canadian hydro solicitations?

    The effect of wind and hydro in New England is not clear cut. Theoretically the addition of incremental zero cost fuel generation will put downward pressure on energy prices as these zero cost producers will displace more expensive ones in the stack and drive down the marginal price. But at what price? There are RFPs by certain New England states soliciting offers for direct wind and hydro deals. These deals would guarantee a certain price for these renewable sources, but the power would be sold into the wholesale market. The difference in rates (credit or debit) would be applied to ratepayer’s transmission and distribution rates. So although you may see the marginal prices of wholesale energy tick down with the insertion of more wind and hydro in the power stack, the risks with the ratepayers are on the T&D portion of the bill. The result could be a shift in rates from supplier costs to T&D costs for the end-user.
  • What do you see the Chicago Basis market doing going forward?

    The basis markets for Chicago City gate over the long term will see the basis premium to Henry Hub continue to decline as new pipeline takeaway capacity out of the Marcellus/Utica producing areas in brought online. One example of this is the Rover pipeline which is under construction and likely to come online in Q4 2017 for its phase I and sometime in 2018 for phase II, which will bring the full 3.25 Bcf/d of new capacity online.  

 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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