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Will it be a Make or Break Summer for Appalachia Production?

March 23, 2016 | By Warren Waite

Demand in the Northeast is highly cyclical, rising in the winter months and then falling off during the summer. In this week’s edition of Get the Point, we’ll study what problems could arise this summer as record gas production levels in the Northeast clash with languishing demand and little to no capacity on outbound escape routes that reach downstream markets.

The rapid growth of natural gas production in the Northeast over the last five years has outperformed anyone’s wildest imaginations. In 60 months’ time production output has grown by 16.6 billion cubic feet per day (Bcf/d), reaching 21.5 Bcf/d today— a 336% increase. Over the same five-year stretch, scores of infrastructure projects have come to fruition to treat and process this new production, reverse traditional flow patterns and serve new demand sources both within the Northeast and in neighboring regions. 

The Northeast spans a very large and crucial geographic area in terms of supply, demand, population and pricing. To better understand the interplay of activity taking place within the Northeast, PointLogic has sub-divided the region into four sub-regions: Greater Appalachia (KY, OH, PA, WV), Atlantic Coast (VA, MD, DE), New Jersey/New York and New England. Each sub-region has its own set of market fundamentals, but for the purposes of this issue of Get the Point, we’ll focus on the Greater Appalachia sub-region. On an annual basis, the Greater Appalachia accounts for 98% of 2015 Northeast natural gas production and nearly 40% of its demand. For context, the same sub-region represents approximately 29% of total production in the Lower 48 and 10% of domestic demand.

Greater Appalachia Accounts for 98% of all NE Production

Outflows key for production growth

On a seasonal basis, the swing in demand among the four Northeast sub-regions can be very dramatic. This is reflected in the chart below, in which average sub-regional gas consumption can decline from 25% to 48% from the winter to summer. (Winter is defined as November through March, and summer represents April through October.) Price hubs in New Jersey, New York and New England are infamous for their volatility, but in terms of volume, the Greater Appalachia has the largest seasonal downturn in demand, declining nearly 4.1 Bcf/d, or 48%, in the last five years.

Average Demand Swings

Every molecule of natural gas that comes out of the ground, either from production or as a withdrawal from storage, must be consumed locally (via residential/commercial, industrial or gas-fired power demand), injected into regional storage fields or transported via pipeline to downstream markets where those same gas molecules must be consumed, injected into storage or exported as LNG.

The network of gas pipelines crisscrossing the Northeast is very complex, nonetheless PointLogic flow data can be aggregated to simplify the net volume of gas flows delivered and received from neighboring regions and sub-regions.

Focusing on the Greater Appalachia, net outflows have grown by 3.1 Bcf/d to average 14.6 Bcf/d this winter, compared to Winter 2014/15. Summer 2015 saw an increase of 3.4 Bcf/d of net outflows compared to 8.0 Bcf/d during Summer 2014. A few of the key projects that came online last September to boost the outflow volume were the 1.8 Bcf/d Rockies Express Zone 3 East to West Project and Texas Eastern Transmission’s 525 MMcf/d Uniontown to Gas City Expansion Project. (For more on pipeline projects effecting outflows and production in the Northeast see “Going Its Own Way” and “Escape from the Northeast”.)

The graph below highlights that production growth in Greater Appalachia (dashed black line) is only feasible when net outflows (yellow shaded area) and sub-region demand (red shaded area) eclipse the dotted black production line. To help balance the peaks and valleys of seasonal demand swings, gas is injected into storage during the summer months (blue shaded area) and withdrawn from storage during the winter months (green dashed line).

Greater Appalachia Supply and Demand

Power burn drives summer demand

In last week’s issue of Get the Point, “The Case for Record Power Burn in the Summer of 2016,” we highlighted a handful of fundamental similarities between what occurred during Summer 2012 and how this summer is primed to not only repeat some of the market conditions witnessed four years ago, but to surpass a handful of previous records. Gas-fired power generation in the Lower 48 could outpace 2015 by more than 1 Bcf/d on an annual basis. Setting the stage for this to occur are bloated winter-ending storage inventory levels, low gas prices and a weather forecast calling for a hot summer. 

For the Northeast and the Greater Appalachia in particular, the use of natural gas as a baseload fuel source for power generation is evident in the recent increases in the amount of gas consumed to generate power on a temperature basis. The burn per temperature chart, shown below, depicts 2016 (blue line) and 2015 (red line) outperforming previous years. That trend will continue this summer.

Burn per Temperature Greater Appalachia Powerburn

Gas prices for the two most liquid gas hubs in the Greater Appalachia, Columbia Gas Transmission (TCO) and Dominion South Point (Dom SP), are trading around $2.00/MMBtu and $1.30/MMBtu, respectively, for this coming summer. In the price chart below, both the full cash value and its corresponding basis differential to the Henry Hub are represented.

As more takeaway capacity from the Marcellus has come online, it has narrowed the basis discount at Dominion SP from minus $1.43/MMBtu in Summer 2014 to minus $0.84/MMBtu Summer 2016 per current market pricing. Over the same period, TCO Appalachia basis has moved 7 cents weaker to minus $0.13/MMBtu for this coming summer, due to increases in Utica production and more gas volumes moving west and south across Ohio.

TCO and Dom SP Price Weakness

For Northeast power burn, the unfortunate reality is that prices have already been depressed for quite some time, and coal-fired power plant generators with the ability to switch or convert to natural gas as a fuel source have already done so. The retirement of underutilized coal-fired plants has for the most part already taken place as well. In other words, major trends that drove rising gas demand in the Northeast in the last decade have mostly run their course.

When Northeast prices get below $3.00/MMBtu, natural gas is economically competitive with Central Appalachia coal. With regional prices a dollar or more below that mark, any upside to power burn from coal-to-gas switching has already been exhausted, too.

Injection demand will be limited

A problem facing the Greater Appalachia this summer will be the limited amount of remaining capacity for gas to be injected into regional storage fields. EIA’s East Region Storage is a larger geographic footprint than the Greater Appalachia. Luckily, two of the largest cumulative storage fields are right in this sub-region’s back yard. On a combined basis, storage tied to TCO and Dominion (DTI) account for approximately 54% of working gas capacity in EIA’s East Region. An analysis of where combined inventories stand today and how full storage can be filled can help us determine what summer injection demand for these two pipeline-owned storage facilities might be. 

On a combined basis, TCO and DTI storage inventories currently sit at almost 210 Bcf, or 40 Bcf below March-ending levels back in 2012. Appalachia production has grown by 14 Bcf/d since March 2012, indicating that the fundamental landscape of the sub-region is vastly different from just four years ago. However, if we look at Summer 2015 injection rates alongside some other benchmarks, we can get a better understanding of how inventories could theoretically build over the summer.

Combined TCO & DTI Storage

As depicted in the chart above, TCO & DTI summer storage injection cannot mirror 2015 injection rates (light blue dotted line) of 2.0 Bcf/d, nor can they replicate the five-year average rate (yellow dotted line) of 1.85 Bcf/d. The reason is that inventory would exceed capacity limitations (red line). But it is possible for inventories to climb back to the five-year high set in October 2012, when storage was roughly 96% full. To accomplish that, Summer 2016 injection demand would need to average 1.5 Bcf/d, or nearly 0.5 Bcf/d less than what the market injected last summer into said facilities. 

Gas Flow Go, No-Go Options

By now, it should be clear that the lofty production levels in the Greater Appalachia are subject to the barriers created by an almost 50% drop of in sub-regional demand as well as constraints in terms of less demand plaguing the Northeast this summer. Outflows will be more crucial than ever for production levels to survive in a demand constrained environment.

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Net outflows from the Greater Appalachia averaged 11.4 Bcf/d back in Summer 2015, a pickup of 3 Bcf/d from the previous summer. Winter-to-date net outflows have averaged 14.6 Bcf/d, a gain of 3.1 Bcf/d from winter 2014/15. The only sizable project to help facilitate additional outflows away from the Greater Appalachia this summer will be in June when Texas Gas Transmission (TGT) brings its 758 MMcf/d Ohio-Louisiana Access Project into service. The market will have to wait until November for the next round of sizeable pipeline escape routes to become available from the Greater Appalachia and the Northeast as a whole. 

Moving gas away from Greater Appalachia to New Jersey, New York and states along the Atlantic Coast is predicated more or less to the degree that gas demand rises or falls in those neighboring sub-regions. Remember, that summer demand declines 42-44% from the winter average in the sub-regions north and east of Pennsylvania. The drop in net outflows from Winter 2014/15 to Summer 2015 was 2.2 Bcf/d on average. A similar downturn in outflows north and east should occur again this summer.

Another option for gas to escape the Greater Appalachia is to move south into the Southeast region, where it serves various types of demand along the Gulf Coast. The three most significant options to do that are on Tennessee Gas Pipeline, Texas Eastern Transmission (TETCO) and Transco. Each of these pipelines curtail and restrict nominations on a daily basis, and they only schedule the quantities that are operationally feasible on a given day based on changes in supply and demand on each respective pipeline. Generally speaking, these routes are full every day. As new capacity enhancement projects came into service, new production ramped up and utilized whatever space remained.

Select Southbound Flows

As previously mentioned, there is a project on TGT to add 758 MMcf/d of north-to-south capacity this coming June. This is more of a long-term development and isn’t expected to have a significant impact on TGT flows this summer unless current gas flows are redirected to its Lebanon interconnects. There are only two options for TGT to receive Marcellus and Utica sourced gas, interconnects with TETCO-Lebanon and Rockies Express (REX)-Lebanon.

We’ll return to TETCO below, but it’s safe to presume TETCO’s 24” line remains maxed out, and anything more than the 30 MMcf/d TGT receives from TETCO would only be possible if TETCO deliveries to Panhandle Eastern at Lebanon, Ohio flipped over to TGT. There is roughly 325 MMcf/d of open capacity available for that to occur.

Interconnect receipts on TGT from REX in Lebanon, Ohio averaged 235 MMcf/d last summer and 180 MMcf/d this winter. TGT’s interconnect capacity is 490 MMcf/d, leaving roughly 250-300 MMcf/d of available interconnect capacity from REX to move south on TGT. Construction on this project is progressing fast enough that some or all of the capacity could go into service sometime in April.

The last option for gas to escape the Greater Appalachia is to move west into Indiana and Illinois. The two choices to facilitate this would be on REX and TETCO. As was the case in southbound flows, throughput utilization to the west is also highly utilized. Simply put, the pipes are full.

The implementation of REX’s 1.2 Bcf/d Zone 3 East-to-West Project last September added to the 0.6 Bcf/d of westbound capacity from the Seneca, Ohio lateral and brought east-to-west capacity to the current 1.8 Bcf/d. (In previous editions of Get the Point, we’ve covered the gas flows and projects tied to REX in great detail.) 

In the same month as the REX Zone 3 East-to-West Project was implemented, TETCO put into service its 425 MMcf/d Uniontown to Gas City Expansion Project. This essentially flipped gas flows along the Lebanon Lateral and gave shippers access to new markets in Indiana. However, choke points upstream of the Lebanon Lateral along the 24” line remain completely full.

Select Westbound Flows

The Sarahsville, Ohio compressor station on TETCO and the Chandlerville, Ohio compressor station on REX are good barometers to measure how much gas can truly flow west from the Greater Appalachia. These two compressors are the best throughput locations to capture where the two respective pipelines can restrict flow when gas nominations exceed pipeline limitations. Combined, the two choke points account for 2.4 Bcf/d of east-to-west capacity. February 2016 was 100% utilized, while the slight downturn in March is short-lived due to a handful of maintenance events. PointLogic expects westbound flows to remain full going forward. There are no projects slated to go into service this summer to expand westbound capacity. 

Upside and Downside Risk

In conclusion, the Greater Appalachia will feel the summer squeeze as the sub-region tries to juggle falling seasonal gas consumption, a dip in storage injection demand and pipeline outflows that run at extremely high utilization rates. What may be the ultimate balancer this summer could be periods of time when Appalachia price hubs fall to levels near or below $1.00/MMBtu and producers choke back on marginal production. There is more downside risk to production output than to the upside. If current production levels of 21.1 Bcf/d in Greater Appalachia hold steady, then there is likely enough flexibility in storage injection demand remaining to absorb the drop off in seasonal demand and outflows to the north, south east and west.

What could ease the burden on production and prices? Higher than expected power burn from a really hot summer. As we stated last week, forward weather forecasts are calling for above-normal temperatures in June, July and August. Stay tuned to upcoming editions of Get the Point as we monitor how the market shakes out this summer. 

 

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