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February Energy Market Outlook Webinar Q&A – Part 1 of 2

 

February Energy Market Outlook Webinar Q&A – Part 1 of 2

Posted by Keith Poli on March 17, 2017

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 answer them below with input from principals in our Commodities Management Group.

Question: Any updates to the legal challenges to New York's nuclear Zero Emission Credits?

Legal challenges have been filed in both the Federal and State courts against New York’s Zero Emission’s Credit (ZEC) program, as well as a motion that was filed at the Federal Energy Regulatory Commission (FERC).  

The challenge filed in the Southern District of New York has oral arguments scheduled for March 29th to consider dismissing the motion. New York State court is facing a motion to dismiss and has not yet received a date for oral arguments. FERC cannot rule on the motion before it because it has lacked a quorum since commissioner Norman Bay resigned on February 3rd.

Question: Can you address basis movement with Rover for the Midwest? Michigan has seen about a 10-cent drop in the last two weeks. Should we expect any further significant moves down? 

The growth in the Marcellus and Utica Shale plays since 2009 has created the largest, single supply basin in the country. Right now, it’s at 22 Bcf/day, which now exceeds regional Northeast demand in non-winter months. This oversupply has spurred an infrastructure build-out that began by adding:

  • The capability of making interstate pipelines to bi-directional
  • Building new pipelines such as Rover, NEXUS and Atlantic Sunrise

These new pipelines will deliver gas to markets in the Midwest, Southeast, New England and Canada. As this infrastructure build-out from 2015-2020 allows constrained gas to move to the Midwest, the overall trend will be to lower basis prices in the Midwest and lift negative prices in Ohio and western Pennsylvania. 

The recent move lower in Michcon basis in the first two weeks of February was likely triggered by the continued warm weather this winter and the approval of Rover pipeline by FERC on initially a conditional basis. While Rover may not come online until 2018, the conditional certificate approval from FERC on February 3rd was seen as an indication that the pipeline is moving forward.

Question: What could be the coal-fired power impact if coal regulations relax? 

While the Trump Administration has made it a goal to help put coal miners back to work, the impact could be limited. First, the reality of low natural gas prices competing against coal is an impact. Second, many older coal plants were required to comply by 2015 with the Environmental Protection Agency (EPA) Mercury and Air Toxic Standards (MATS). The choices were to either upgrade scrubbers or retire and close up to 52,000 megawatts (MW) of coal retired since 2012, most of which was only running in summer and winter months during peak demand periods. The likelihood is very low that this generation will return to service. Coal production will likely need to rely on the export market, but a stronger U.S. dollar as of late makes U.S. coal less competitive. 

Question: Do you expect the current administration’s policies regarding foreign trade to affect export sales to Mexico?

It is possible that the Trump administration policies could impact exports of U.S. natural gas to Mexico. However, many of the new pipelines serving have long-term takeaway agreements to meet growing power generation load in Mexico. On February 22nd-23rd, Secretary of State, Rex Tillerson, and Secretary of Homeland Security, John Kelly, visited Mexico City to discuss border enforcement, security and trade. 

Question: How fast do you see production being able to react and come online to meet an increase in exports?

 The lead time from deploying new rigs to production flowing on pipes has continued to decline over the last several years, as drilling efficiencies have increased. A general rule of thumb is about a 6-month lead time from when a rig is deployed to when natural gas can begin flowing. The chart below shows weekly rig counts since January 2016 (Source: Baker Hughes). Over half of the oil rigs have been added in the Permian basin in west Texas. Natural gas rig counts have increased mainly in the Northeast and Louisiana (Haynesville) shale plays.  

Picture1.png   

While rig counts are important to monitor for future levels of production, a more immediate indicator can be the number of drilled but uncompleted (DUC) wells. The EIA tracks DUC wells as part of its monthly Drilling Productivity Report. As the table below shows (Source: EIA), there are about 5,300 DUC wells in the seven major U.S. shale plays. The ability of producers to complete and tie in those wells to both inter- and intra-state pipeline systems will be a key factor in how fast production can respond to changes in demand. 

 Picture2.png

Question: How much incremental gain in associated gas is expected in Bcf/day?

The majority of incremental “associated” natural gas output will come from the Permian, Eagle Ford and Bakken Shale fields. As the EIA’s Drilling Productivity Report for March shows below, current associated gas production as of February ’17 is equal to about 15 Bcf/day from the three respective shale plays, with Eagle Ford having the most gas-only rigs. From examining associated gas output in Eagle Ford over the past 12 months via EIA data for the latest month of January, we know that the rig count rose 39 percent from 199 in January ’16 to 276 in January ’17. Gas production per rig increased from 823 Mcf/day to 1,087 Mcf/day – a 32 percent increase in efficiency. Overall, Permian production rose 19 percent from 6.4 Bcf/day to 7.6 Bcf/day for January ’17. Per Baker Hughes rig count data for the week ending February 24th, rig counts are 306 in the Permian basin. That’s an 11 percent increase from January. Associated production may continue to rise.  

Picture3.png

One final consideration when looking at rising rig counts to associated production is that not all wells are the same. As new rigs are deployed, they may be less productive wells. In the downturn in oil and gas prices of 2015-2016, businesses generally focused on the best plays and retained the most productive crews. As new crews and rigs are deployed, efficiency gains may not be on a similar level. A conservative estimate of gains in associated gas for the remainder of 2017 would be about ~0.5 Bcf/day.

Question: How will basis be affected by either Nexus or the Rover pipelines in the Midwest – Northeast Ohio and Michigan?

The general effect of the Rover and the Nexus pipelines from 2018-2020 as they come online will be to lift constrained gas prices in Ohio at Dominion South Point (Dom SP), while reducing them in the Michigan and Illinois region. As constrained Marcellus and Utica gas can be moved out of the Southeast Ohio region, it will lift basis prices while generally reducing them in non-producing areas such as Michigan and Illinois. The pace of growth in Marcellus and Utica production as these new pipelines come online may affect regional natural gas prices. 

The current forward market view of regional basis prices for 2020 versus the 2016 average reflect this dynamic. MichCon is expected to decline from an average of $0.19 in 2016 to -$0.07 in 2020. Dom SP will rise from -$1.21 in 2016 to -$0.69 in 2020.

Picture4.png

                                                 Source: Range Resources

Check back on our blog soon for part 2 of this series. In the meantime, if you have questions, reach out to us!

Topics: Energy Management

Keith Poli

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