August 2, 2017 | by Warren Waite
What a difference one year can make. There is no other U.S. region besides the Northeast where the impact of new infrastructure projects is as profound.
In this week’s Get the Point, we look at the impact that pipeline projects are having in the Northeast on various outlets for natural gas exiting the Northeast region and recap upcoming projects that are on the horizon that further this objective. Currently, the Northeast is experiencing record production output and depressed gas consumption levels, creating an opportunity for recently expanded pipeline routes out of the Northeast to flex their muscles and make their mark on the Lower 48 U.S. natural gas market.
PointLogic is tracking over 12 billion cubic feet per day (Bcf/d) in pipeline projects through 2018 that have the ability to increase gas outflows from the Appalachia. However, we are forecasting Northeast production to increase by 6.0 Bcf/d from current levels during the same time, and only a marginal amount of demand growth. So that extra production will need to find an outlet. Outflows from the Northeast are playing a major role balancing the market this summer, but over the next 18 months pipeline capacity growth is likely to outpace the ability of new production to fill it. This could be a new chapter in Northeast basis relationships and behavior, one that is contrary to trends of the past five plus years.
Around this time in summer 2016, Northeast natural gas consumption levels, including fuel and pipe loss, averaged 15.7 Bcf/d, while regional gas production levels stood near 21.8 Bcf/d. Net outflows of natural gas to neighboring regions averaged near 4.7 Bcf/d, leaving roughly 1.4 Bcf/d of gas available to go into storage.
Over the same April-to-July period in 2017, Northeast production has increased by 1.7 Bcf/d, or 8% to average 23.5 Bcf/d. In fact Northeast production recorded a record high or 24.0 Bcf/d in July. (See Northeast Production Resurgence for further explanation of this trend.)
At the same time, Northeast gas consumption levels have declined by 1.9 Bcf/d, due to higher year-on-year natural gas prices that have given coal-fired power generation a boost and relatively cool summer. (See A Closer Look at Summer 2017 Power Demand for more details.) The implied increase in summer storage injections this year of 0.8 Bcf/d tracks closely with the Energy Information Administration (EIA) East Region storage weekly injections and history. The equalizer in this equation has been the surge in gas flows leaving the Northeast, up by 2.8 Bcf/d.
The Northeast region’s gas flows are highly complex, with gas flowing west, east, south and north. This occurs both from a region-to-region perspective at an individual pipeline level and within the Northeast region itself. PointLogic’s Gas Week Northeast report, and its daily companion, simplifies these complexities, shedding light on all the in’s and out’s of what is happening with production, demand and prices. However for the purposes of this edition of Get the Point, we will stick to the pipelines that directly affect regional flows.
As previously mentioned, April-July 2017 Northeast outflows have increased by 2.8 Bcf, or 60% compared to the same period in 2016, to average 7.2 Bcf/d. Below is a map depicting the regional flow of the first four months of summer 2017 (black arrows), and underneath that is the change from the same period last summer. The discussion below will address each region individually, highlight the pipelines and past projects that are driving these increases and note any upcoming projects that will allow for incremental gas outflows in the near future.
Net Gas Flows to the Midcontinent Region
Northeast net outflows to the Midcontinent Region averaged 2.2 Bcf/d this April through July, a gain of 1.2 Bcf/d, or 120%, compared to the same months in 2016. The pipelines within this corridor include Rockies Express (REX), Texas Eastern, Texas Gas Transmission, Panhandle Eastern and Crossroads. Pipelines that are only passing through Ohio or Kentucky and carrying volumes targeting the Southeast are tagged accordingly. By far, the most impactful pipeline sending Marcellus and Utica Shale molecules west is REX, through which outflows have averaged almost 1.9 Bcf/d, an increase of 0.5 Bcf/d from last summer.
Rockies Express (REX)
The main driver behind the increase in REX westbound flows from Ohio relates to the 0.8 Bcf/d Zone 3 Capacity Enhancement Project that was phased into service in late December 2016 through early January 2017. This spawned a production increase via expanded receipt point capacity in eastern Ohio at various supply sources and added capacity as several compressor stations to facilitate the upward trend in westbound flows to Midwest markets.
Since that time, some of that production has been reshuffled to other pipelines. By June, REX began contracting with various shippers for newly available westbound capacity as a result of system optimizations that were made possible by the Zone 3 Capacity Enhancement Project. Together, these events have resulted in summer 2017 westbound flows from Ohio averaging nearly 1.9 Bcf/d, a gain of 0.5 Bcf/d over last summer at this time. As REX continues to improve optimization of the pipeline, incremental gains in east-to-west flows are likely to occur.
Texas Gas Transmission (TGT)
Texas Gas Transmission is contributing a 0.5 Bcf/d change in summer-on-summer gas flows. TGT has decreased its reliance on south-to-north flows to meet remaining gas demand needs within Kentucky. In late May 2016, the pipeline put into service the 758 MMcf/d Ohio-Louisiana Access Project, which was designed to source Marcellus and Utica supplies at Lebanon, Ohio to delivery markets in Louisiana.
Since gas departing Ohio into Indiana reenters into Kentucky, we look at the net flow activity to simplify what remains after Kentucky gas consumption. In April-July 2016, TGT received 0.6 Bcf/d of northbound flows from Tennessee into Kentucky. In comparison, net flows this summer are averaging a marginal 64 MMcf/d, a decrease of nearly 0.56 Bcf/d due to a related increase in pipeline supplies at Lebanon.
Interconnect supplies at Lebanon increased by 0.5 Bcf/d, or nearly 200% over April-July 2017, to average 0.8 Bcf/d. Nearly 0.4 Bcf/d of that increase into TGT came from REX, and the remainder was supplied from Dominion Transmission. It wasn’t until July 2016 when, as part of the Ohio-Louisiana Access Project, that the TGT interconnect with Dominion became bi-directional and began receiving interconnect supply. Additionally, supplies from REX picked up in January 2017 when the previously mentioned production increase and late-December 2016 capacity increase on REX occurred.
Natural gas flows on TGT move west from Ohio to Indiana, where any remaining length then gets consumed within Kentucky. While there have been select days when net flows on TGT move south from Kentucky into Tennessee, monthly averages still place net gas flows south to north—marginally so. There is just over 1.0 Bcf/d of underutilized Lebanon interconnects among REX, Dominion and Texas Eastern (TETCO) that have the ability to receive incremental supplies. However, compressor station capacity constraints may limit the potential growth to 0.2-0.3 Bcf/d based on a PointLogic Energy analysis.
In August, TETCO put into service the 102 MMcf/d Lebanon Extension Project three months earlier than originally proposed. This project shares related facilities with two other TETCO projects that will target the Southeast come November. The early in-service was granted by FERC and championed by Gulfport Energy, one of two anchor shippers. This will allow for incremental Market Zone 2 (M2) production to flow across TETCO’s Lebanon lateral. Currently, the vast majority of Lebanon Lateral deliveries go to Panhandle Eastern Pipeline and ANR pipeline.
Rover Pipeline is a greenfield project that’s been covered in past issues of Get the Point and written about extensively in the last six months as events have unfolded during construction. In short, regulatory pressure has intensified which has slowed and in some cases halted construction. The latest update from Energy Transfer Partners, developer of Rover, is that Phase I will be delayed to sometime in ‘’late summer’’ instead of July, as was the prior estimate. Phase II is still on track for November 2017. Likewise, the 1.5 Bcf/d Nexus Pipeline project, which is awaiting FERC approval, recently announced it would be delayed until 2018. PointLogic estimates it could be online during 2Q 2018 based on construction timelines and when FERC may have a quorum status to approve the project.
Together, three upcoming westbound projects from the Northeast combine for 4.85 Bcf/d in potential outflow capacity from the Marcellus and Utica. This is a huge shift in available capacity and, per a PointLogic analysis, unlikely to be highly utilized in its first handful of months. Instead, production growth will be more gradual as 2018 progresses, filling up available capacity at a slower pace, contrary to how pipeline projects leaving the Northeast have behaved in years past.
Net Gas Flows to the Southeast
Natural gas flows between the Northeast and Southeast have been in flux for years as some pipelines have completed various projects to reverse flow, while others maintain the traditional pattern of molecules flowing south to north. There are at least nine different pipelines that crisscross the Ohio Valley to the Atlantic Coast as gas moves south and north between the Northeast and Southeast regions. Net outflows to the Southeast averaged close to 4.8 Bcf/d in the first four months of summer 2017, an increase of roughly 1.2 Bcf/d, or 33% compared to the same period in 2016. There are four pipelines leading the way: Transco, Tennessee Gas Pipeline (TGP), TETCO and Columbia Gulf Transmission (CGT) that, when combined, account for just over 1.0 Bcf/d of the 1.2 Bcf/d summer-on-summer increases mentioned above.
Starting with Transco, southbound flows measured at the Virginia-North Carolina border have increased by 0.3 Bcf/d to average 1.2 Bcf/d in April-July 2017. A capacity increase of just over 0.3 Bcf/d in April at Compressor Station 195 South made this possible. Contracts on Transco indicate this was a partial early in-service of its Dalton Expansion Project, which is set to reach full in-service by August.
Next up is TGP, where southbound flows at the Kentucky and Tennessee border increased by just over 0.2 Bcf/d through July 2017 to average 2.0 Bcf/d. There is no change in incremental capacity, but the gains on TGP are more of a reflection of weaker consumption levels and net activity at interconnects throughout the Northeast.
Southbound flows along TETCO’s 30” line leaving Kentucky have increased by 0.2 Bcf/d to average nearly 1.4 Bcf/d this summer. In October 2016, TETCO put into service Phase I of the Gulf Markets Expansion project, boosting southbound capacity by 0.1 Bcf/d. In August 2017, Phase II will add another 0.4 Bcf/d of southbound potential.
Lastly, CGT is receiving an incremental 0.25 Bcf/d from TCO at its Leach, Ky. interconnect. Past projects and shifts in flows among interconnects on the TCO system helped push additional gas molecules to Leach and southbound on the CGT pipeline system. In November, the related Leach Xpress project on TCO and the Rayne Xpress project on CGT will provide an additional 1.1 Bcf/d of southbound capacity.
As the table above indicates, there are flurry of projects coming that will expand Northeast gas flows to the Southeast. Details of each can be found within PointLogic’s Pipeline Project Tracker or online via the respective pipeline’s website. The two August 2017 projects, TETCO Gulf Markets II and Transco’s Dalton Expansion, were explained in the prior section.
Come November, southbound capacity will gain 2.5 Bcf/d and create a large opening for Northeast production to grow—if downstream demand within the Southeast materializes in kind. Then, during 2018 another monumental shift will occur, with over 4.3 Bcf/d slated for in-service. Each of these projects is contracted by a combination of producers, gas distribution companies, and in a few instances shippers with LNG export intentions.
Net Gas Flows to Canada
The interplay of pipelines along the Canada border and the Northeast region vary from pipe to pipe, with some exporting gas to Canada and other importing gas. For example, TGP, Empire Pipeline and (on occasion) Maritimes and Northeast Pipeline will export gas from the Northeast into Canada. The vast majority of imported gas into the Northeast takes place at the Waddington, N.Y. interconnects, with Iroquois Gas Transmission and TransCanada, and at the Pittsburg, N.H. interconnects with Portland Natural Gas Transmission System and TransCanada. On a net basis, the Northeast is typically an exporter of natural gas except for peak winter months when demand spikes.
Using the same April-July comparisons as before, the Northeast is exporting nearly 0.4 Bcf/d more than last year on a net basis. This phenomenon is a result of a decrease in imported gas, not increases in pure exports. And the driver behind this is a decline of imported gas at the Iroquois- Waddington interconnect.
The aforementioned weaker gas-fired power demand and higher gas prices are the driving forces behind the downward trend of Waddington imports this summer. April-July 2017 averaged 0.13 Bcf/d, a loss of 0.33 Bcf/d compared to the same period in 2016.
The only project through the end of next year that could affect border flows with Canada is the 133 MMcf/d Atlantic Bridge project along Enbridge’s Algonquin Gas Transmission and Maritimes & Northeast Pipeline. It is slated for a June 2018 in-service.
In review, the implementation and utilization of numerous infrastructure projects since summer 2016 have had a positive impact on Northeast regional outflows (+2.8 Bcf/d), on Northeast gas production growth (+1.7 Bcf/d) and helping the region deal with the extra length in the market left over from weaker summer-on-summer gas consumption levels (-1.9 Bcf/d).
PointLogic forecasts Northeast production to surpass 30.0 Bcf/d by late 2018, a build of roughly 6.0 Bcf/d from current levels. Meanwhile, takeaway projects from Appalachia will add over 12.0 Bcf/d in pipeline capacity that pushes gas west and south.
While a large portion of that buildout is anchored by producers, it is dependent on a demand-pull reality. Without corresponding demand growth across all the demand sectors and exports, it would not be realistic for 6.0 Bcf/d in Northeast production growth to indirectly displace production in other areas within the next 18 months.
That said, by year-end 2018, there is likely to be excess takeaway capacity from the Northeast, and it could persist for a period of time. Producers own a little more than half of the 12.0 Bcf/d in Appalachia takeaway project growth through 2018. As a result, basis relationships and transportation spreads may experience more volatility, given that the behavior and incentives are different than how a gas marketer would optimize that transport capacity.
Stay tuned to future editions of Get the Point and updated PointLogic Energy forecasts available for client download as the Northeast story continues to unfold.