Against a backdrop of surging natural gas production and pipeline capacity expansions competing to tap demand growth in the Southeast and Gulf Coast, understanding the energy space requires a holistic approach informed by both equity and commodity markets, according to East Daley Capital Advisors President Jim Simpson.
Speaking to a crowd at the recent LDC Gas Forums Northeast conference in Boston, Simpson, looking specifically at the assets and commitments of a number of major exploration and production (E&P), and midstream players in the Marcellus and Utica shales, said analyzing the region requires going well beyond breakevens.
“If you don’t understand the companies, you can’t understand Northeast markets,” Simpson said. “If you don’t understand the assets, you can’t understand the companies. And if you don’t understand Northeast markets, you don’t understand the assets. That’s the new paradigm. It’s a holistic approach. You’ve got to understand the commodity space all the way through to the equity space, and then it feeds back into the commodity space.”
Using Antero Resources Corp. (AR) as an example, Simpson calculated the E&P is guiding for 4.5 Bcf/d of production by 2020, or about 13% of total Northeast production. At the same time, Antero Midstream Partners LP (AM), AR’s E&P-sponsored master limited partnership, is guiding for a distribution of $577 million/year by 2020, Simpson said. For processing and fractionation, he said AR carries an 80% minimum volume commitment on all new processing plant capacity added through a joint venture between AM and MPLX LP.
Add in AR’s firm transportation commitments, and “by the time I get to 2020, Antero’s on the hook for a little over $2 billion a year,” Simpson said. “So this isn’t just about breakevens anymore. You can’t just look at a breakeven in the Northeast and a breakeven in the Haynesville or even in the Permian, which is driven by crude oil. This is $2 billion/year. So of that 4.5 Bcf/d, I’ve got to produce 2 Bcf/d just to cover this nut. So again, a substantial number.”
AR is just one example, as Simpson calculated that the five of the largest Appalachian players, made up of AR, EQT Corp., Ascent Resources LLC, Range Resources Corp. and Cabot Oil & Gas Corp., are carrying slightly under 24 Bcf/d of firm transport commitments by 2020 at a total cost of close to $3.5 billion.
“These five producers by 2020 make up about 50% of total production in the Northeast,” he said.
Simpson later added that “when these big pipes come online, you don’t have a lot of leeway before you have to start generating cash to pay for those commitments.” In terms of whether all the Northeast pipeline expansions will fill up, “the answer is yes. We’re going to fill that space. We’ve got to. The consequences for not doing so for a producer, well, they’re pretty darn negative.”
Other analysts have recently pointed to growing Northeast output driven by takeaway expansions in their bearish forecasts for gas prices. Analysts with Sanford C. Bernstein & Co. LLC predicted last month that a “sunk cost curse,” could spread to Appalachia as more pipeline capacity comes online and E&Ps fulfill midstream take-or-pay contracts, no matter the price.
The buildout of pipelines in Appalachia may lead Marcellus/Utica players with midstream contracts to produce at price levels that could be “well below the full-cycle cost.” Midstream costs in many basins are running around 50-80 cents for a commodity that’s “worth under $3.00/MMBtu,” Bernstein analyst Jean Ann Salisbury and her colleagues noted.
There’s also Northeast natural gas liquids (NGL) output to consider. Simpson outlined the critical importance of NGL takeaway via Sunoco Pipeline LP’s embattled Mariner East (ME) and ME 2 lines for a number of regional players given limits on storage and transportation alternatives.
“If ME 1 goes down, it’s a MarkWest problem. If ME 2 goes down, it’s everyone’s problem,” he said.
For a producer such as AR that is looking to grow to 4.5 Bcf/d of production by 2020, “they can’t do it without ME 2.”
Meanwhile, crude-focused basins, such as the Permian, delivering “zero dollar gas” could become “the Northeast producer’s worst nightmare” over the next few years.
Echoing other analysts who have predicted growing competition to move gas to the Gulf Coast region, Simpson said producers will all be looking to get their gas into the “Southeast/Gulf box,” the only area of the country where demand is growing and “one of the few areas of the country” that still boasts a premium market in Henry Hub.
Looking strictly at anticipated associated gas growth from onshore crude oil reservoirs, specifically the Denver Julesburg-Niobrara, Bakken Shale and Permian and Anadarko basins, until new expansions into the Southeast/Gulf come online around 3Q2019, markets “outside of that box” will need to absorb about 4.6 Bcf/d of additional supply, he said.
“We’ve all seen cash prices,” said the East Daley executive. “We’ve all seen forward basis, particularly Waha, Rockies, Chicago. We’ve got another 4.6 Bcf/d that we’re going to squeeze into those markets to continue to compete in areas outside of the Southeast/Gulf.”
Surging growth in both liquids and associated gas output from the Permian, by far the most active play in the U.S. onshore, has led to transportation bottlenecks and negative basis differentials for pricing hubs in West Texas. On the natural gas side, Waha saw some of its cheapest average prices since the late 1990s earlier this year and has consistently traded about 70 cents to $1.00 off Henry Hub.
Given the prospect for continued attractive crude economics to drive associated gas growth, analysts with Raymond James & Associates Inc. earlier this year forecast U.S. natural gas prices to drop to $2.25 in 2019, with $2.50 likely needed to balance the market longer-term. “Given the high degree of associated gas production generated by some of the largest shale oil plays, U.S. natural gas prices have effectively become inversely related to oil prices,” said analysts J. Marshall Adkins and Pavel Molchanov at the time.
Then the Northeast has to be added in again, which has about 9.6 Bcf/d of expansions into the Southeast/Gulf coming online from 2017 through 2018, Simpson said.
“Northeast producers get into this box first,” he said. “They win. Now I’ve got a period in time here, before the Permian expansions open up, where I’ve got to push a little over 1 Bcf/d back into the Midcontinent and into this market” outside of the Southeast/Gulf. “So at this point, it doesn’t bode particularly well for basis markets outside that box...so we’ll continue to see fairly weak basis for much of the country for quite some time to come.”
Still, once more Permian associated gas shows up in the Southeast/Gulf by 2019, that should coincide -- give or take a few months -- with the arrival of more liquefied natural gas (LNG) export capacity.
“By the time we get another wave of capacity into that Southeast/Gulf box, we end up with some large-scale LNG export facilities to absorb maybe a decent amount of that supply,” Simpson said.