There is a small area of the country in Northeast Pennsylvania that covers a little more than the 3,000 square miles, less than 0.1% of the total continental U.S., or just 6.5% of Pennsylvania. Although small, this region is having a big impact on the energy landscape.

By 2020, this area is estimated to supply 17% of total U.S. natural gas production—a drastic difference from just 0.2% 10 years earlier.

What is equally impressive is more than one-third of the growth is expected to happen in a period of one year. Supported by new pipeline expansions, 5 billion cubic feet per day (Bcf/d) of natural gas is expected to reach the market between mid-2018 and mid-2019. While there are many interesting facets of this story, including the impact to downstream basis and the impending fight for market share with producers in the southwest Marcellus and Utica, those stories will have to wait for another campfire.

Instead, I’ll focus upstream on the productive capacity limit for this area and the tie that binds long-haul pipeline companies to midstream gathering to producers.

Constrained capacity

Growth in Northeast Pennsylvania is limited by productive capacity, which is not the total capacity leaving the area but is instead total available capacity for producers to fill. Productive capacity is the total physical capacity less demand-constrained capacity, or capacity that is non-displaceable. Demand-constrained capacity is capacity that is not available to producers because there is no downstream demand market to consume the gas.

This type of constraint can often be because of seasonal demand fluctuations. Producers cannot produce at seasonal demand highs because production is generally not seasonal and would need to move somewhere during lower demand months. Non-displaceable capacity is space that is not available because of contractual ownership.

For the area around Northeast Pennsylvania, this is generally capacity that is used by end-use customers for deliveries from storage.

The figure in the adjacent map show estimated productive capacity leaving in four directions out of Northeast Pennsylvania in 2019. Additionally, the map shows the estimated total demand within the region. Today, total productive capacity is around 9 Bcf/d but, as shown, that number will grow to 14.5 Bcf/d in 2019.

Financial limitation

It should be emphasized that productive capacity is necessarily a physical limitation. In fact, in this area of the country it is more of a financial limitation. The only significant increase to productive capacity for Northeast Pennsylvania in the last three years has been from the 500 MMcf/d expansion of Transco’s Leidy Line in January 2016.

Prior to that, productive capacity was around 8.5 Bcf/d. However in January 2015, production from Northeast Pennsylvania peaked out at just over 9 Bcf/d before pulling back. Dan Dinges, chairman, president and CEO of Cabot Oil and Gas Corp., the largest producer in the area, remarked during the company’s first-quarter earnings call that “it is clear from our first-quarter production that we have the ability to move volume in excess of these base load levels but we are not going to chase production growth to the detriment of cash margins.”

At the time, Cabot was producing around 2 Bcf/d and more than 75% of it was likely getting in-basin pricing. As a result, every additional molecule Cabot was able to produce was putting pressure on prices—and thus pressure on the pricing of three out of four molecules in Cabot’s base load supply.

Cabot and other producers are about to change all of that.

Today, producers own about 4.7 Bcf/d of capacity on long-haul pipelines in the region. Various end users and marketers own the remaining capacity. By mid-2019, producers will own or have firm contracted sales on 8.2 Bcf/d of capacity, which accounts for 65% of the 5.3 Bcf/d of expansions coming online. For Cabot and other producers in the region, that gives them more control. By 2019, Cabot is estimated to be producing more than 4 Bcf/d, but this time only 50% of its supply will be sold in the area; the remaining 50% will be sold in downstream markets.

A changing dynamic

The projects coming online that will change the dynamic in northern Pennsylvania include several that will directly feed new power demand, some that are enhancements and expansions of existing lines, and a couple of very large greenfield projects. These projects are in various stages of regulatory approval but all of them already have enough contractual support of producers and end users to move forward.

The accompanying table shows a list of expansions that are included in the additional productive capacity along with the estimated in-service date and capacity. As might be expected, the more uncertain projects are the longer-dated projects that have not received all the regulatory approvals required to move forward. The interesting dynamic here is that if they do not receive that approval, it may indefinitely reduce the amount of product capacity from the region due to the difficulty of building other projects to replace them.

The prevailing view might be that there are no quantifiable limits to the amount of capacity that can be added out of the area, whether that’s because another project is unable to move forward or due to increasing producer growth expectations.

Great rock

This view is taken in part because the assets have rightfully been referred to as some of the best rock in the world. However, building any substantial additional projects from the region will be extremely difficult for three reasons:
• Limitations on demand growth;
• Regulatory kerfuffle; and
• A lack of market incentive.

The first reason, limitation on demand growth, is simply that. Within the direct area around Northeast Pennsylvania, demand is growing but incremental demand beyond current plans is not likely to provide a significant boost to productive capacity. Certainly any demand growth is welcome, and new end users are likely to enjoy competitive pricing for many years to come, but as exemplified by the fact that this small slice of the country will support 17% of the U.S. production, the appetite of producers is well beyond the dinner plate of demand.

The other side of the equation might best be described as a regulatory kerfuffle. Without getting too into the weeds, building infrastructure to support the nation’s energy needs only seems to get more difficult. Not only do new pipes face environmental opposition but they can also face issues of end-use rate base support. Several projects including the Northeast Energy Direct (NED) and Access Northeast have already failed to make it through regulatory hurdles and projects like The Williams Cos. Inc.’s Constitution Pipeline have—and continue to face—significant headwinds.

Where’s the incentive?

The final and potentially most significant hurdle a new project may face is the lack of market incentive to support any additional capacity expansions. 2018 summer spreads from the supply areas to the premium Northeast coastal markets are already $0.10-$0.20/Mcf, which is reflective of the fact that summer demand in the region dips dramatically.

This will make it difficult to justify another large pipeline project that would incur demand charges upward of $0.60/Mcf. At this point, winter basis is certainly much higher on the East Coast, but producers cannot generally produce into winter demand load without a significant alternative demand source in the summer.

On a net basis, the region has already displaced all of the supply coming into the Northeast, so the alternative would be for producers or end users to contract further away into Ontario or the Southeast.

However, Ontario basis is also expected to realize some dramatic changes in the next few years as both the Rover and Nexus pipelines provide 2.6 Bcf/d of additional takeaway from southwestern Pennsylvania and Ohio into the Michigan/Ontario market.
Building down to the Southeast can be an option, but other planned expansions will also compete with increasing production coming out of southwestern Pennsylvania and Ohio.

The Permian problem

Additionally, there will be increasing pressure from producers in the Permian Basin in West Texas and the Scoop/ Stack in Oklahoma that are also looking to make the Southeast their destination of choice. To date, Kinder Morgan,
Enterprise Produce Partners LP and NAmerico Partners LP have announced major projects from the Permian to the Gulf Coast, while Cheniere Energy Inc., ONEOK Inc. and Enable Midstream Partners LP have announced major projects from the Scoop/Stack.

Keeping in mind the productive capacity limitation of 14.5 Bcf/d by 2019—over 5 Bcf/d higher than today’s productive capacity limit of 9 Bcf/d—which producers and midstream gatherers are positioned for growth? The companies best positioned for growth are the producers that have contracted volumes on the new long-haul expansions.

For instance, Cabot has contracted for over 1.9 Bcf/d of new capacity and is expected to grow production by 107%. Seneca has made the next-highest amount of commitment at 686 MMcf/d and is expected to grow supply by 79%. However, not all producer growth is tied to contracted capacity. Some 32% of the companies supporting new expansions are either end users or unknown.

For these expansions, the allocation of producer growth is modeled based on producer expectations and the availability of interconnects with new expansion through gathering systems. The accompanying charts show the expected growth from both producers and midstream gathering companies from the end of 2016 to the end of 2020. Each producer is tied from their acreage through the midstream gathering system to the long-haul pipeline.

Gathering gains

On the midstream gathering side, Williams’ Susquehanna is expected to grow 85% and will likely be one of the largest gathering systems in the U.S. Breaking down Energy Transfer’s volumes by gathering system across the country shows that its northeast Marcellus system will be the company’s largest by volume, growing by 132% to an estimated 3 Bcf/d.

While growth expectations are exciting, an equally interesting part of the story is the downside risk. The upside is limited by the productive capacity, but the downside risk comes from the potential cancellation of the longer-dated projects and the implications go well beyond just the EBITDA risk to the pipeline itself.

For instance, if Constitution is not approved, a cancellation of the project would result in a reduction of $39 million in annual EBITDA for Williams Partners LP. However, that project also supports upside for gathering Williams Partners, which is estimated at $88 million in annual EBITDA, bringing the total impact to Williams Partners of $127 million.

The impact to Cabot will be a reduction of nearly 25% of its expected production growth.

The pie is just so big

There is also an interesting dynamic around the 32% of new expansions where the support is either unknown or from end users. The limitation of productive capacity means that the pie is only so big, and the market must main-tain a balance. Therefore, if a producer pushes beyond growth expectation noted above by selling higher volumes into the 32% of contestable capacity, it will result in another producer reducing its supply outlook.

While there is some question of which individual projects will move forward and when, there is no doubt that a small area in Northeast Pennsylvania is about to have a huge impact on the U.S. natural gas market.

New takeaway and demand coming online starting at the end of this year and ramping significantly by mid-2018 will help producers reach markets far from their acreage. These expansions will drive dramatic upside for the producers and midstream companies that have committed capital to make these projects a reality, with the financial uplift of each molecule benefiting the producer, gatherer and long-haul pipeline operator.

At the same time, the downside from project cancellations could have a similar snowball effect with consequences visible throughout value chain. While some producers and midstream operators will be affected more directly than others, the new reality for regional competition, basis spreads, and the price of natural gas, will ultimately impact everyone in the natural gas market.

Justin Carlson is vice president of research for East Daley Capital Advisors.