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Escape From the Northeast is About to Get Easier

July 29, 2015 | By Warren Waite

The much anticipated Rockies Express Pipeline Zone 3 East to West project officially goes into service August 1, adding 1,800 million cubic feet per day (MMcf/d) of pipeline capacity from Ohio to Illinois. Additionally, Texas Eastern Transmission’s Uniontown to Gas City Expansion Project (U2GC) will expand its ability to deliver gas from Pennsylvania to Indiana by 425 MMcf/d. 

Together these two projects will provide roughly 2.2 billion cubic feet per day (Bcf/d) of takeaway capacity from the Northeast to the Midwest. After that, there are 25 different pipeline projects being planned through 2018, which total 23.4 Bcf/d that could transport Marcellus and Utica Shale production to markets outside of the immediate Appalachian area of the Northeast region, according to PointLogic Energy’s Pipeline Projects database.

The commissioning of the two projects coming online in August and those anticipated to go into service over the next two to three years will be paramount to the future of Northeast natural gas production growth. What will need to improve is the ability to move gas out of the immediate Appalachia region of the Northeast.

In this issue of Get the Point, we’ll look at the effects of where Northeast production growth has occurred, the burden of severely discounted basis prices and what the future may hold as we highlight the billions of dollars being spent on the onslaught of pipeline projects set to come online over the next three years.

How did we get here?

Since 2012, U.S. dry gas production has grown nearly 7.2 Bcf/d, an 11 percent increase, to reach the roughly 72 Bcf/d that is being produced today.

It’s no surprise to followers of the natural gas markets that the bulk of the ramp-up in production was led by the Marcellus Shale boom in the Northeast U.S. Lately, the pace of production growth has slowed and in some cases stagnated (see the latest from the Gas Production in the U.S. at a Standstill? series). However, with new escape options out of the Northeast set to come online next month and throughout the next several years, the outlook for incremental production growth and improved gas prices couldn’t be better. Though current times are tough for many producers, there are better days ahead. 

For years, the concentration of the surge in new gas supplies coming to market has been in Pennsylvania and more recently West Virginia and Ohio. So much so that production growth outpaced takeaway capacity on pipeline infrastructure to downstream markets. This has resulted in severe discounted net back pricing to the producer’s well-head. The region is essentially choking on its own captive supply that has finite demand and limited optionality to premium priced markets downstream. 

The graph below highlights these facts. Dry gas production in Pennsylvania has doubled since 2012, averaging 6 Bcf/d then to around 12.5 Bcf/d in 2015. Likewise, over the same period, Ohio production from the Utica Shale as increased 2.3 Bcf/d to average 2.6 Bcf/d year-to-date and production volumes in West Virginia (part of the Marcellus) have gained 1.7 Bcf/d to average 3.1 Bcf/d in 2015. Altogether, these three states account for 97 percent of Northeast production compared to 91 percent back in 2012. For context, the Northeast accounts for about 24 percent of all U.S. production, while in 2012 only 11 percent of U.S. production came from the Northeast.

NE Production by State

For the past 12 months, Dominion South Point (a pricing hub in Pennsylvania that represents the bulk of nearby Marcellus production) spot market prices have averaged $1.98 per million Btu (MMBtu) and have held a $1.30/MMBtu discount to the national benchmark at Henry Hub, LA. The weakness in pricing at Dominion South Point (Dominion South) is a reflection of production that has continually outpaced the limitations of pipeline takeaway capacity. Coupled with periods of low demand, Dominion South cash market prices have dipped to as low as $0.72/MMBtu in the last 30 days – which occurred over the July 4th holiday weekend. 

This low price environment has deterred several producers from hiring frac crews, completing previously drilled wells and bringing new production to market until prices improve. There is some speculation that increased drilling could return in the fourth quarter, when winter demand gives prices an upward kick in the rear. 

So far this year, production growth from the end of 2014 has been a challenge. The well documented collapse of energy prices and rig counts are the major reasons for the stagnation of production growth in the lower 48.  There have also been numerous pipeline maintenance events this summer that have hindered production growth. 

However, producers have proven their resiliency in tough times. They have lowered drilling and completion costs, improved production rates and shortened drill times. In some areas of the country like the Permian and Utica, these improvements have compensated for lower energy prices and yielded attractive internal rates of return.  But in parts of Pennsylvania where the nature of how dry or wet one’s production can vary dramatically, producers seem to be holding out for a day when prices improve – perhaps later this year.

The future is optimistic

The challenges noted in the preceding paragraphs and optimistic view of the future were echoed by Cabot Oil & Gas in their second quarter earnings call and covered by PointLogic’s news team. Click here for the article "Cabot Oil & Gas Updates On Marcellus And Pipelines." Similar to other producer CEO’s, Cabot’s CEO Dan Dinges said that compared to a year ago production was up, costs down and still the company lost money in this challenging commodity price environment. He cited that, “there are better days ahead,” mostly in the form of better realized prices from their Marcellus production. 

The commissioning of Transco’s Leidy Southeast Expansion Project on December 1, the construction and in-service of Constitution Pipeline by mid-2016 and Transco’s Atlantic Sunrise in the second-half of 2017 are a few of the invested projects Cabot is looking forward to. 

Cabot will be able to move more than 1.5 Bcf/d of production out on these three lines when they come in service over the next two years.  According to a May investor’s presentation, by 2018 “over 70 percent of Cabot’s long term sales and firm transport capacity reaches markets outside of NE and SW PA.” Annual long term firm sales/firm transport capacity more than doubles from 1.1 Bcf/d this year to 2.8 Bcf/d by 2018.

Cabot Oil & Gas Long-Term Firm Transportation & Firm Sales by Region

For the last few years, pipelines in the Northeast have been able to accommodate new production by displacing traditional sources of gas supply into the region. Fast forward to today, those options in large part have been exhausted and pipelines are turning around their compressor stations and expanding their ability to reverse the flow of gas from its original intent – typically west-to-east or south-to-north. Therefore you see producers such as Cabot and others signing up for pipeline capacity to move their production to better priced markets further downstream, which will ultimately increase the net-back price to their well-head.

PointLogic Energy’s Pipeline Projects database is currently tracking a staggering 88 different projects spanning over 4,000 miles that total over 50 Bcf/d of capacity residing in the Northeast that could come online between now and 2018.  An analysis of these projects and where the gas is ultimately moving from and to, suggests that 27 of the projects (roughly, 25.6 Bcf/d), will actually help gas escape the supply island that is the Marcellus and Utica Shale.


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2015 Projects

There are too many projects to detail each one individually, but there are many noteworthy milestones to address.  As mentioned at the beginning of this blog, on August 1, REX’s Zone 3 East-to-West (1.8 Bcf/d) and TETCO’s U2GC (0.425 Bcf/d) project will officially go into service. The westbound flows on Rockies Express (REX) have been gradually increasing for months. The Chandlerville compressor station, located in Muskingum County Ohio, has averaged 1.3 Bcf/d this July, nearly 90 percent utilized. In February, westbound throughput at Chandlerville averaged 0.36 Bcf/d.  In large part, production growth from the REX East-to-West project has already occurred.

After the two westward bound projects, the other two important additions are Transco’s Leidy Southeast Expansion Project and Tennessee Gas Pipeline’s Niagara Expansion. In total there will be 3.0 Bcf/d of takeaway capacity going into service over the next five months that will either go west, south, north into Canada or into New England (which still lacks reliable supply during the premium winter months). 

Capacity Additions Leaving the Northeast

2016 Projects

In 2016, an additional 4.5 Bcf/d of infrastructure will be added to aid in the escape of gas molecules from the major Northeast producing states of Pennsylvania, West Virginia and Ohio. Some of the biggest projects next year are Constitution Pipeline (0.65 Bcf/d), Texas Gas’s Ohio-Louisiana Access Project (0.63 Bcf/d), TETCO’s Gulf Markets Expansion Phase I (0.35 Bcf/d) and the initial phase of Energy Transfer’s Rover Pipeline project (2.2 Bcf/d). If all goes as scheduled, by the end of the 2016, there will be two newly built interstate pipelines in our nation’s natural gas pipeline grid. The last time any significant greenfield interstate pipelines were built was back in 2008, when Rockies Express Pipeline and Millennium Pipeline went into service. 

2017 Projects

The year 2017, will be a significant year for change. The Northeast is slated to add over 10 Bcf/d of takeaway capacity from the region, almost half of which is southbound and will target growing gas-fired power generation and industrial demand, but primarily gas demand for LNG exports. Capacity to liquefy natural gas along the Gulf Coast could push 7 Bcf/d by this time if all the projects tracked by PointLogic Energy LNG Infrastructure Informant come to fruition.

The big projects heading westbound are REX’s Clarington West Project (2.4 Bcf/d), Energy Transfer’s Rover Pipeline Phase II (1.05 Bcf/d) and NEXUS Gas Transmission (1.5 Bcf/d). Moving south, projects like Transco’s Atlantic Sunrise (1.7 Bcf/d) and Columbia Pipeline Group’s Leach Xpress (1.53 Bcf/d) will move large volumes of gas to the Southeast. 

2018 Projects

There are also some large scale pipeline projects being planned for start-up dates in late-2018. The announced projects total 7.5 Bcf/d. As time moves forward, the aspects and volume of these projects are subject to change. A few of the larger announced projects include Tennessee Gas Pipeline’s Northeast Energy Direct (NED- 2.2 Bcf/d), Transco’s Western Marcellus Pipeline Project (Appalachia Connector- 2.0 Bcf/d) and the new-build Atlantic Coast Pipeline (1.5 Bcf/d). 

Escape Routes form the Northeast

There is a long-game to the rapid buildout of infrastructure leaving the Appalachia Basin of the Northeast. By late 2017, there will be an incremental 18.2 Bcf/d of escape routes leaving the Northeast. Over the next 28 months, gas from greater Marcellus and Utica shale will have 10 Bcf/d of optionality to move west. Looking south, there will be about 6.2 Bcf/d of capacity and almost 2.0 Bcf/d of capacity that can move into Canada or New England. At the end of 2018, if the announced projects are constructed, westbound capacity is unchanged, but southbound capacity tops 11.4 Bcf/d and northbound capacity reaches almost 4.2 Bcf/d. 

Production companies plan to take advantage of all of the new pipeline takeaway capacity. Southwestern Energy has signed up for a handful of these projects, which was cited in a recent earnings call and covered by our news team. Click here for the article "Southwestern Energy Ups Productions, Lowers Cap Ex Guidance." Southwestern also cited several examples of shortened drill times, longer laterals, lower well costs and increased production. 

Southwestern has committed to several of the new transportation routes. These will help facilitate future production growth, provide new outlets and improve the sales price of marketed volumes.

Southwestern's Appalachia Takeaway

Presently, Marcellus and Utica dry gas production in Ohio, Pennsylvania and West Virginia average just over 18 Bcf/d and the vast majority of that production is consumed within the greater Northeast region. By 2017, PointLogic Energy projects production from the three States could surpass 20 Bcf/d, leaving plenty of spare room on the newly minted pipeline infrastructure. This will especially be apparent during the lulls of regional demand in the summer months. 

Over the last few years infrastructure hasn’t kept pace with production growth but as the waves of infrastructure projects are completed it will quickly outpace regional production growth. The region will move away from being supply constrained to demand constrained. The fluctuations of downstream markets both near and far will dictate the value and utilization of the monumental infrastructure build-out that is currently being developed.

Big Dollar Bets

When you think about it, it’s pretty remarkable the amount of capital that is being invested to make these projects a reality. According to the Energy Information Agency (EIA), estimations of what all the infrastructure projects will cost within and from the Northeast region tally to about $26.3 billion. In 2015, an estimated $2.9 billion could be spent and the year after, another $3.2 billion would be needed in infrastructure projects. In 2017 and 2018, the cost of building new gas pipelines account for the vast majority of the estimated project cost of $9.7 billion and $10.6 billion, respectively.

Northeast Infrastructure Expenditures

Expanding, reversing and building new pipelines is a very complex and costly process from obtaining right-of-way rights, engineering, construction, environmental assessments and many layers of local, state and federal permitting and approvals. Obviously, these projects take years of planning and in order for the financing of these multi-million dollar projects to go forward, firm capacity commitments are required. These projects are backed by the firm commitments of producers, utilities and as of recently participants in LNG export projects.

As mentioned earlier, some Marcellus and Utica producers have choked back on bringing new wells online during the current low price environment. Additionally, the price of natural gas isn’t the only thing to consider as revenue from the liquids rich portion of the production stream can become monetized after being processed, transported and fractionated into purity NGL products. Looking to the forward basis curve as an indicator of what future prices may hold, regional prices in the Appalachia Basin are improving, but not by leaps and bounds. 

Dominion South Point basis for Summer 2015 (cash basis April-July and forward basis August-October) could average ($1.46)/MMBtu, a mere two cents weaker than Summer 2014. However, once you factor the Henry Hub price, Dominion South implied fixed prices have averaged $1.30/MMBtu this summer. Summer 2014 cash prices averaged $2.76/MMBtu, or $1.46/MMBtu above this summer’s implied fixed price. Though Dominion South basis differentials tighten, the implied fixed prices during the summer months never cross the $2/MMBtu mark until the summer of 2017. The winter season also shows some strength with, November 2017-March 2018, priced at ($0.72)/MMBtu, a 20-cent basis gain from Winter 2014/15 levels. As of market indications on July 24, the Dominion South implied fixed price will remain below the $3/MMBtu threshold through the next five seasons.

Appalachia Pricing

As the supply glut that exists in the pricing of Dominion South is slowly released and takeaway capacity gains move west and south, so too will the pricing relationships between neighboring regions and price hubs. Generally speaking, the Columbia Gas-Appalachia (TCO Pool) is southwest of Dominion South Point. TCO Appalachia Pool pricing is truly an interruptible paper pool and under normal operation conditions can originate from any source on the Columbia Gas Pipeline system. 

Columbia Gas Pipeline system 

Despite the proximity of the TCO Pool and Dominon South, the value of natural gas is quite different. The $1.37/MMBtu discount of Dominion South to TCO Pool during Summer 2014 is nearly the same for Summer 2015; assuming August-October forward basis values remain unchanged. However, as the Appalachia Pricing graph indicates, the spread between these two hubs narrows over time. By Summer 2017, Dominion South will command a $0.83/MMBtu discount to TCO Pool.

The weakening seen in the TCO Pool curve and strength from the Dominion South curve is a reflection of downward pricing pressure relief from the new takway options out of Pennslyvania and the gradual weakness at the TCO Pool is the transfer of a portion of those gas molecules westward. The same can be said with other pricing hubs further west and south.  As the flood of natural gas from the Northeast spills over into other markets, expect the value of those transportation paths to narrow.

Perhaps never before has the U.S. gas grid seen an explosion of pipeline infrastructure additions coming to market as what is expected to occur over the next three to four years – not to mention all the LNG export projects, industrial projects and both gas-fired and renewable power plant projects. In that regard, it’s truly special times that we live in today, being on the verge of such engineering  marvels, redefining how our energy markets physically work and broadening the U.S. gas market to the fundamentals of what is happening around the globe. That said, there are lots of moving parts to how the U.S. gas market will look like in the future. Stay tuned, as PointLogic Energy helps you navigate the varying aspects of the evolving U.S. natural gas markets through our many products and services as well as future editions of Get the Point.

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