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Waiter, Another Round - Infrastructure Projects Set to Propel Northeast Production

June 7, 2018 | Jack Weixel

Last August, OPIS PointLogic penned a Get the Point that compiled a list of natural gas pipeline projects in the Northeast that would profoundly affect supply and demand fundamentals in the region and across the Lower 48 and Canada.

This edition of Get the Point will provide an update on several projects that will be completed by the end of summer 2018. We’ll also dive into supply and demand dynamics in the Northeast and our expectation of how these fundamentals will be altered over the course of this year.

Source: OPIS PointLogic Gas Week Northeast and forecast data

The chart above compares OPIS PointLogic’s expectations for the Northeast in summer 2018 (April-October) compared to what actually occurred in summer 2017. We expect production to increase this summer overall by 5.0 billion cubic feet per day (Bcf/d) – what was once a 24.0 Bcf/d market will average close to 29.0 Bcf/d. Production in the Northeast in May 2018 averaged 27.3 Bcf/d, its highest level ever. To average 29.0 Bcf/d for the next five months, we expect production levels to crest 28.0 Bcf/d this month and be above 29.0 Bcf/d from mid-July through the end of October.

On the demand side, two factors are driving total Northeast consumption up by about 1.1 Bcf/d. First, domestic consumption is up by about 0.5 Bcf/d, driven largely by residential and commercial (res/com) demand. The summer-on-summer increase in res/com demand is due to cold April weather that extended the winter gas withdrawal season into the first four weeks of that month, much to the chagrin of nearly everyone in the region except for the small sample of avid skiers, snowboarders and winter sports junkies. Second, pipeline feed gas deliveries to the newly commercialized Cove Point Liquefied Natural Gas (LNG) export terminal in Maryland make up the majority of the remaining 1.1 Bcf/d demand differential.

With 5.0 Bcf/d more production (anticipated) and 1.1 Bcf/d more demand, overall the Northeast is 3.9 Bcf/d longer than it was last summer. This 3.9 Bcf/d must either be injected into storage or shipped out of the region. Where this gas goes is of utmost importance as we gauge the impact of Northeast production gains on the rest of the contiguous U.S.      

Pipeline Projects and Production Growth

The month of June will see about 3.0 Bcf/d of Northeast pipeline projects placed into service. The most anticipated is the second phase of Energy Transfer Partners’s Rover pipeline, which received approval to place a substantial portion of its Phase 2 expansion into service last week. While still awaiting federal approval for two supply area laterals, having the entire mainline in service now allows Rover to increase capacity to 3.25 Bcf/d to pipeline interconnects in Defiance, Ohio, and further north to Vector Pipeline in Michigan.

Source: OPIS PointLogic

The graph above shows the immediate impact of Rover. Beginning June 1, deliveries on Rover jumped to about 2.1 Bcf/d, or 0.5 Bcf/d greater than they had been through the month of May. Nearly 0.8 Bcf/d of gas is now jumping on to Vector Pipeline in Livingston County, Mich. About 0.4 Bcf/d of that gas had previously been directed to ANR at the Westrick interconnect in Defiance County, Ohio.

Yet, so far OPIS PointLogic’s data are showing that Rover is not being wholly utilized at its full 3.25 Bcf/d capacity. Utilization is expected to increase after new production is sourced from several supply laterals that are awaiting Federal Energy Regulatory Commission (FERC) approval.

The next major project to come in service is The William Companies' Transco Atlantic Sunrise project (see map below). This will increase southbound capacity from Zone 6 of the pipe down to Station 85 in Zone 4. Like Rover, this has been a major project that has come in service in stages. In September 2017, Atlantic Sunrise went into partial in-service, delivering 0.4 Bcf/d of natural gas to Station 85. On May 1, 2018, FERC granted additional in-service approval for an incremental 150 MMcf/d of capacity, bringing the project’s mainline total to 550 MMcf/d. The project also includes several greenfield lateral projects from the Leidy Line in Pennsylvania that will push future production in Zone 6 further south and to the Pleasant Valley interconnect with Cove Point.

By the time July rolls around, OPIS PointLogic expects the remainder of Atlantic Sunrise to enter service, with 300 MMcf/d of southbound mainline capacity and 850 MMcf/d in total of contracted capacity from the Leidy Line that now has the ability to reach into Zone 6 and Zone 5.

Source: Williams Companies, Spring 2018 Update

On tap to be completed in July are a pair of TransCanada-owned Columbia Gas (TCO) projects that will be able to deliver more than 1.3 Bcf/d of natural gas to the Southeast (see map below). Phase I of the WB XPress project will move 800 MMcf/d of gas from east to west within West Virginia to ensure future capacity out of the region. WB XPress should receive its certificate decision from FERC by June 22, with the final environmental assessment expected to be on schedule.

WB XPress is lined to Mountaineer XPress, which will effectively be the header for the system, with the ability to ramp up deliverable gas to 2.7 Bcf/d by November 2018 after Phase 2 of WB XPress is completed to make this section of pipe bi-directional in order to serve Mid-Atlantic markets in Virginia.

Source: Columbia Gas

The net result of these projects is that more production will be able to seek higher prices outside of the Northeast.

Production in the region is averaging 27.2 Bcf/d in April and May, or 3.8 Bcf/d higher than it was for April and May 2017, which means a lot of the heavy lifting summer on summer has already occurred. Incremental production within the Northeast that will be injected into the ground or shipped to neighboring regions will need to average 5.5 Bcf/d greater over the remaining five months of summer than the same time period last summer. Last summer saw some modest stagnation in Northeast production, remaining at or near 24.0 Bcf/d from July to October while the region was waiting on new capacity. Just as new capacity out of the region last fall spurred production to record levels, new capacity this summer will help the Northeast eclipse those levels once again.  

Regional Storage Needs and Price

Price is king, and it dictates how gas moves around the country, how producers make decisions and impacts local utilities, power plants, marketers and storage operators alike. In turn, storage is a major driver of price. The level of storage in the ground, relative to prior years and the five-year average, helps set the price and on a regional basis. Price can drive gas to it or shoo-away gas, depending on how healthy storage inventories are in one particular region compared to another.

Source: EIA storage data through week ending May 24, 2018, and OPIS PointLogic

The map above shows the storage inventory deficits as of the week ending May 24, 2018, compared to the five-year average. The largest deficit belongs to the South Central at (164) Bcf, followed by the Mid-Continent at (160) Bcf and the East at (101) Bcf.

Layering average sub-regional cash prices onto the EIA storage regions shows what happens to prices (see map below). Some of the highest prices in the country are in the South Central region, where the storage gap is greatest. In particular, Henry Hub and Southeast Texas are $0.69/MMBtu (million Btu) and $0.79/MMBtu more expensive than Appalachian prices.

Source: OPIS Price Index for June 4, 2018

Midwest prices are also a healthy $2.66/MMBtu, which should drive gas to this region as well. Growing supply in the Northeast, in tandem with infrastructure projects designed to deliver gas to these high-price areas, will drive gas to these regions. How much goes where and how much goes into the ground in the Northeast is still to be seen.

Who Gets What?

The balance between incremental storage injections and outflows is tricky. Knowing what we know about price differentials, current inventories and new infrastructure projects to move gas out of the region, we can make educated guesses, but this will certainly take the majority of summer to play out. We’ll break down our initial thoughts below.

As we illustrated at the beginning of this report, the Northeast is expected to be 3.9 Bcf/d long this summer as compared to last summer. Over 214 days, this adds up to about 835 Bcf of incremental gas.

Conveniently, the Northeast’s inventory levels are 101 Bcf below the five-year average, creating an incentive to use some of that incremental gas to rebuild stocks. A majority of Northeast storage holders are local distribution companies (LDC), whose main motivation during the summer months is to inject gas into storage at regularly scheduled intervals. This ensures adequate supplies of gas that they can withdraw from storage over the winter.

While the OPIS PointLogic Northeast Region does not line up exactly with EIA’s East Region, the majority of those LDC and other storage facilities are located in the states outlined below.

Source: OPIS PointLogic Storage Module

With the exception of the Barmsley field in far western Kentucky, let’s go ahead and assume that Northeast storage is down about the same amount versus the five-year average as the EIA East Region, or 101 Bcf. Over 214 days, about 0.5 Bcf/d of incremental injections will have to occur to return storage to the five-year average.

Outflows to neighboring regions are next – so who gets preference? It's like to be those regions that have adequate infrastructure capacity built out and the price to command more gas, based on the relative spread from the producing areas in Appalachia. The map below depicts the OPIS PointLogic opinion on incremental flows to areas near the Northeast.

Source: OPIS PointLogic

After returning storage levels to the five-year average, there is 3.4 Bcf/d of incremental gas remaining that will be destined for higher-price markets. Starting clockwise, we believe that Canada will receive about 0.2 Bcf/d less gas this summer than in summer 2017. The reasoning is pretty straightforward – more gas will be entering Ontario via Rover and Vector Pipelines. In addition, growing associated gas from Western Canada is priced to move and has on several occasions this year experienced negative prices at the AECO Hub in Alberta. Taken together, Ontario will have access to less expensive gas compared to last summer.

Next, outflows to the Southeast are projected to increase from 5.3 Bcf/d in summer 2017 to 7.4 Bcf/d in summer 2018. In April and May, average flows to the Southeast averaged 6.1 Bcf/d. Add in incremental flow from Transco’s Atlantic Sunrise and TCO’s WB XPress and Mountaineer XPress projects, and we believe these flows will increase significantly over the next five months. Tennessee’s Broad Run expansion will also allow add 0.2 Bcf/d to the region’s total deliverability to the Southeast.

Outflows to the Midwest averaged 2.2 Bcf/d in summer 2017, with Rockies Express moving most of these incremental molecules following its east-to-west expansions last year. With the addition of Rover pipeline carrying gas to Michigan, we expect flows to increase by 1.5 Bcf/d. Considering that flows to the Midwest are already averaging 0.5 Bcf/d greater in April and May compared to last April and May, we believe the completion of Rover Phase 2 will push this outflow volume higher as summer wears on.

The chart below summarizes how the Northeast’s massive 3.9 Bcf/d surplus of gas will be distributed this summer.

Source: OPIS PointLogic

The current balance of Northeast Supply and Demand is documented daily and weekly in OPIS PointLogic’s Northeast Gas Fundamentals Daily and in the Gas Weekly Northeast. Keep your eyes on these two reports as the summer progresses to track progress on supply, demand, outflows, storage and price. To learn more about these reports, please contact sales@pointlogicenergy.com or call us at 855-650-4500.