In more ways than one, domestic natural gas production is making history. It’s more involved than the record-setting Utica and Marcellus wells and the revival of the Cotton Valley Formation in northern Louisiana that have been making headlines. In April and once more in July, and for the first time ever, gas-fired electric power surpassed that of power generated with coal.

And in January, watch for the first LNG exports from the Gulf Coast as a tanker departs Cheniere Energy’s Sabine Pass liquefaction plant in Cameron Parish, bound for Asia. Commissioning and testing were under way at press time on Cheniere’s first train, kicking off an historic five-year buildup to 2020 of LNG exports from a handful of U.S. sites now under construction.

Developments to monetize the blessings of vast gas resources can’t happen fast enough for producers facing $2 prices and wondering when they can justify drilling more of their thousands of proved locations.

Help is on the way from a variety of sources. In October, for example, the governors of Pennsylvania, Ohio and West Virginia agreed to cooperate on marketing and research to attract manufacturing jobs, facilities and shale development in their region, where 85% of the increase in domestic gas production has come from since 2012.

That same month, David Mustine, senior managing director of the nonprofit JobsOhio, boarded a plane for Japan to talk about natural gas supply in the Buckeye State.

“We find the Asians to be very interested, and we have hosted a lot of groups coming over here,” he said. “We can definitely point to some very specific projects related to the Utica and Marcellus shales, and we’ve facilitated discussions between producers, pipelines and end users. We’ve gone from 2 Bcf/d to 22 Bcf/d in this region as the Marcellus and Utica have been developed, so we’ve got a lot of gas looking for a home.”

Ohio’s not the only state luring new businesses that will use plentiful gas supply. In September, Louisiana Gov. Bobby Jindal and executives from Yuhuang Chemical held a ceremonial groundbreaking for a $1.85 billion methanol complex in St. James Parish. It’s the largest foreign direct investment ever in the Pelican State by a Chinese firm.

Also in September, Jindal announced that Indorama Ventures Olefins LLC, a U.S. subsidiary of a Bankok firm, has acquired a dormant ethane cracker near Lake Charles, Calcasieu Parish.

Indorama will revamp it to produce ethylene, a building block of plastics, resins and other industrial materials.

South Africa’s Sasol, meanwhile, has been building an $8.9 billion complex, including an ethane cracker and six manufacturing plants, near Lake Charles since October 2014. Today some 2,500 construction workers are swarming the site. With full operation expected in 2018, the cracker will use about 100,000 bbl/d of ethane, a natural gas component, as feedstock. All these projects will make use of abundant natural gas.

Plentiful supply is a good news-bad news concept for gas producers who have so successfully increased production and proved reserves, causing a glut that dampens wellhead prices.

According to the EIA, U.S. gas production increased almost twice as fast as consumption from 2005 to 2012, due mainly to growth in shale gas production and “improved site planning and field optimization, multiwell drilling from a single pad, rising associated natural gas production from oil plays, and improved drillbit technology.”

Lower 48 production in August (the latest month of available data) was 84 Bcf/d, up about 5.7 Bcf/d year-over-year.

Organizations as diverse as the American Chemistry Council and the National Association of Manufacturers have taken note. The U.S. Chamber of Commerce tallies as much as $90 billion of new or expanded facilities planned for the petrochemical industry along the Upper Texas Gulf Coast to New Orleans. Reshoring initiatives by manufacturers are drawing construction and jobs back to both the U.S. and Mexico, notes Greg Haas of Stratas Advisors, a Hart Energy company.

In all cases, ample gas supply and NGL byproducts such as ethane are the drivers.

The call on natural gas

Just how much more natural gas will be needed, and by what date—and more to the point, when will producers see any financial benefits on the bottom line? The wait could be longer than many expect as most of these end-use projects are long-term, billion-dollar endeavors that won’t make a material difference until 2018, 2020 or beyond.

The call on U.S. gas could rise by more than 22 Bcf/d between now and 2020, driven by power generation in the near term and exports to Mexico and LNG shipments in the longer term, according to a report on demand by Morningstar’s senior commodities analyst Jordan Grimes. He cites “several years’ worth of low-cost inputs to power generation, export opportunities and industrial processes.”

The EIA forecasts the U.S. will be a net exporter of gas by the end of this decade.

However, with so many projects on the drawing boards to take advantage of surging gas supply, are U.S. producers going to cash in on an end-use boom? Gas prices are range bound—even the three and five-year strip remained below $3/Mcf at press time.

“Over the past few years, U.S. natural gas markets have become rather like a forgotten stepchild in a room full of screaming infants,” a Raymond James report said in October.

We decided it was time to take a closer look. Through the summer and into October we received a flurry of press releases announcing dozens of projects that will use natural gas. But currently the baseline is this: The U.S. uses 77 Bcf/d and produces about 84 Bcf/d, and gas in storage is now above the five-year average.

LNG exports

By all accounts, the biggest contributor to incremental demand will be LNG exports, although observers caution a worldwide supply glut is developing versus flattening Asian demand, meaning spot prices will be lower. However, most LNG contracts are long-term obligations with offtake agreements and take-or-pay clauses.

“There’s a tsunami of LNG export capacity being built across the world. I’ve heard Enterprise Products Partners calls LNG ‘gas on the shelf.’ Whatever and whenever you need production to be, we can get it there. We are putting in the plumbing to allow it to flow,” said Becca Followill, senior managing director at U.S. Capital Advisors.

“I’d say there’s an overwhelming view of a sea change coming in production, price and thus, behavior. But I do think it keeps a lid on prices because you have the ability to take so much gas off the shelf,” she said. In addition there are vast resources still awaiting the drillbit in plays such as the Haynesville Shale; these will be produced as needed and when the economics justify it.

Casey O’Shea, spokesman for the Center for Liquefied Natural Gas (CLNG), is among those pushing hard for Congress to institute a faster, easier and more certain federal approval process for LNG exports, a process that has already been changed three times in two years.

Even so, six facilities have been fully permitted by FERC and DOE and are in various stages of construction. Cheniere Energy’s Sabine Pass plant at the Texas-Louisiana border will take up about 2.2 Bcf/d. Its second train will be ready about six months thereafter.

Starting up next is Dominion’s Cove Point plant on the Maryland shore, now about a third complete. In following years we’ll see Sempra’s Cameron LNG plant in Louisiana; privately held Freeport LNG south of Houston (Osaka Gas is a 10% equity partner); Lake Charles LNG, which is owned by Energy Transfer Equity and BG, with first exports in mid-2020; and Cheniere’s second project, Corpus Christi Liquefaction LLC, where the first two trains are under construction.

If all these come on line by 2019-2020 as projected, their total nameplate capacity is 8 to 9 Bcf/d and they’ll export 7 to 8 Bcf/d.

“The thing is, on the demand side,” O’Shea said, “whether you have GE or Caterpillar or the National Association of Manufacturing ... they’ve all projected they will need more gas, and they’ve said that we’ll have enough supply for LNG exports, and can reap the geopolitical and environmental benefits, as well as provide enough gas for domestic use.”

The federal government and numerous think tanks agree there is enough gas for industrial use, power generation, LNG exports and more. “For every component of the demand picture and in all scenarios, every study has shown there will be a net benefit to the economy from LNG exports, and they’ve shown that there is going to be ample supply to meet all those needs at affordable prices,” O’Shea said.

Gas demand might rise by 22 Bcf/d to the year 2020, but it won’t absorb projected production increases. August production was 84 Bcf/d, the EIA said.

A recent report on LNG from Tudor, Pickering, Holt & Co. said the firm is confident LNG actually will exit the U.S., because about 85% of the offtake capacity under construction is already contracted. Diversity of supply and reduced price volatility are important to buyers, so buying LNG from several sources, including the U.S., is key. Finally, as the firm noted, “Off-takers for U.S. LNG projects are high-quality.”

Raymond James analyst Pavel Molchanov sounds a more cautionary note in an October report, however, saying the coming LNG export boom to 2020 has been overhyped and will not necessarily be the panacea for price recovery that U.S. gas producers hope for.

“If there were too many LNG wannabes a year ago, we would argue that is doubly true today,” said Molchanov. “It is true that 2016 is set to be the first year with Gulf Coast LNG exports, with visible and meaningful export increases (from the U.S., though not Canada) during 2017-2019.

“That said, 7 to 9 Bcf/day of LNG exports by the end of the decade will not likely be sufficient to drive Henry Hub prices meaningfully higher than $3/Mcf.”

Haas of Stratas Advisors is more bearish than others on the outlook “given steep global liquefaction capacity growth, lower global commodity prices, and high capital and operating costs.

“Conversely, we are quite bullish on industrial gas demand in the U.S. and North America as a whole, including Canada and Mexico. Closer is better in our view. We see more North American natural gas staying on the continent.”

Given that LNG exports are so tied to demand in the importing countries, “Henry Hub could become a function of the economies of China, Japan and India and what’s going on over there,” said Grimes, of Morningstar, which just released a lengthy report on gas demand.

Power demand is more elastic, responding to gas price variations. “As gas prices rise in 2017, 2018 and 2019, power demand starts to flatten out. If we get to 2018 and prices are still fairly low, we could up our forecast for power demand,” Grimes said.

Petrochemicals and crackers

Even with the recent drop in oil prices, the chemical industry continues to enjoy a distinct competitive advantage in global markets, according to a recent report from the American Chemistry Council, and cheap natural gas is one reason.

“Chemical companies have begun or are planning 223 shale-related projects, including eight announced in December 2014, representing a cumulative investment of $137 billion,” according to ACC’s latest count in February 2015. “Fully 60% is foreign direct investment, driven by the trio of lower-cost feedstock, reliable infrastructure and a U.S. regulatory environment that is moving toward supporting, rather than hindering, competitive success.”

One of the biggest side effects of this wave of investment, ACC said, is that the increased chemical capacity is unlikely to be absorbed in U.S. markets, meaning more exports of U.S. plastics and other materials made in shale-gas-fired chemical plants.

The Marcellus and Utica have so much recoverable gas that petrochemical companies are scouting the region for the best sites—and the best tax incentives. West Virginia, for one, has been awaiting the long-anticipated Appalachian Shale Cracker Enterprise since it was first announced in November 2013, but project developers Odebrecht and Braskem put the Wood County project on hold in April. The companies haven’t officially canceled it, however, so Gov. Earl Ray Tomblin has said the state remains “hopeful.”

A similar plant in southwestern Pennsylvania’s Beaver County also is still under discussion, after Shell first proposed it in 2011, but there is some progress: In June, Pennsylvania regulators issued air and water permits that would allow Shell to begin building the plant on the site of a former zinc smelter it has acquired.

In September, Ohio Gov. John Kasich said an ethane cracker complex may be built in Belmont County on the Ohio River by the American subsidiary of Thailand’s PTT Global Chemical, which indicated it could invest in detailed engineering design studies, with the aim of building a cracker on the site of FirstEnergy Corp.’s former Burger coal power plant. A final investment decision is expected next year. It would be PTT’s first world-scale petrochemical complex outside of Thailand.

JobsOhio’s Mustine said Ohio is a center of the U.S. polymer and automotive parts industries, both of which use natural gas. Mitsubishi is expanding its facility in northern Ohio, which uses resin material from an ethane cracker.

Still, the majority of new large-scale chemical projects is planned for the Texas-Louisiana petrochemical corridor by companies such as Dow, Sasol, ExxonMobil, Chevron, BASF and Linde Group. In October, Celanese Corp. said its new methanol plant near Houston is up and running, a joint venture with Mitsui & Co. “This investment allows [us] to gain the benefit of abundant, low-cost U.S. natural gas,” said chairman and CEO Mark Rohr.

Powering up

This past July, natural gas’ share of U.S. electricity generation surpassed coal as the feedstock of choice for the second time ever (barely), when gas fueled 35% of generation to coal’s 34.9%, according to the EIA. What’s more, compared to July 2014, coal-fired generation fell in every region of the country, while gas-fired generation rose in every region.

The power industry is projected to use 24.4 Bcf/d of gas this year, rising to 30.1 by 2020.

“In the last few years, it’s really been up to power plants to take incremental gas, with coal plant retirements … but that peaked in 2015. There will be some retirements going forward but not to the level we saw this year,” said Nicholas Potter, Barclays research analyst. His price forecast for 2016 is $2.95.

“And if you do believe gas prices are headed higher longer term, you may not see as much incremental demand from coal plants,” he added, although further out, the Environmental Protection Agency’s new emissions rules will have positive implications.

Whatever the future holds, power plants that can switch to gas more readily can give a quicker boost to gas demand than multibillion-dollar LNG and petrochemical plants that take years to build.

Utilities were once skeptical about gas supply reliability and afraid of price volatility, so they stuck to their preferred fuel, coal. But they are finally seeing the light, according to Marty Durbin, executive director of America’s Natural Gas Alliance (ANGA), the group formed in 2009 by gas producers at the leading edge of the shale boom such as XTO, Chesapeake Energy, Anadarko Petroleum and Newfield Exploration. You may have seen ANGA’s TV commercials that tout natural gas and end with the tag line, “Think About It.”

“From the start these companies knew they were going to be producing a lot of gas and they needed to know, who is going to buy it? Power generation is our biggest opportunity, and thankfully, the economics are so compelling that the market is driving that,” Durbin said.

ANGA has identified 15 states where utilities are shifting from coal-fired plants to gas, or growing their current use of gas.

New plants also figure prominently; in Ohio alone there are six gas-fired power plants under construction or proposed, thanks to the Utica Shale. Two combined-cycle, gas-fired power plants are under construction now. One is the Oregon Clean Energy project near Toledo, an 800-megawatt plant. Advanced Power and Bechtel are building a 700-megawatt plant in Carroll County, in the heart of the Utica Shale. A third gas-fired plant to be built by Florida-based NTE in Middletown just completed its financing and construction is expected to begin soon, JobsOhio’s Mustine added.

“The Obama Administration recently announced that carbon emissions from the electric power sector this April were the lowest in 27 years. It’s no coincidence this occurred in the same month natural gas surpassed coal for the first time in U.S. history as the leading source of our nation’s electricity,” wrote Durbin in an OpEd in The Boston Globe recently.

This fall the EPA published its controversial Clean Power Plan (CPP), the first federal rules proposing to limit CO2 emissions from existing power plants, not just from new ones. Nearly two dozen states immediately filed lawsuits to block the CPP.

“There’s no question the CPP creates opportunities for us, whether it goes forward or not,” Durbin told us. “Natural gas was originally put forth as incremental supply for peaker plants and not for generating base load, but now it is for base load. Everybody seems to understand we have a lot of natural gas, but it hasn’t sunk in yet what that actually means.

“We’re living in what we call ‘high resource reality’ and not high resource potential. Over the last several years even the high resource case hasn’t been high enough and our production has been higher than that … which means prices are going to stay reasonable for end users for a long time.”

Recognizing the shifting tide, in the past few weeks Southern Co., one of the largest utilities in the U.S., said it would purchase AGL, a gas distribution company. “Southern Co. was about 50% gas, so they are going all in now,” Durbin said. Likewise, Duke Energy announced it will purchase Piedmont, meaning two of the biggest utilities in the country are stepping up to more natural gas.

Morningstar’s Grimes said, “We expect most coal retirements to occur in 2015-17, during which time we forecast natural gas demand for power generation to increase 3.1 Bcf/d, with the vast majority occurring in PJM and MISO, two of the largest grid operators.

“As wind and solar capacity continues to grow, it is much more likely that coal-to-gas switching occurs more often—but this is less a function of gas being cheaper than coal, and more so the fact that uneconomic gas dispatch takes place to ensure system reliability.”

The EPA said contribution of gas-fired generation plants to electricity production in 2030 is 32.9%. It also said it now expects existing gas-fired plants to be generating more power by then, yet oddly, it sees fewer new gas-fired plants being built.

Conversions of existing plants are a likely scenario. For example, Dallas-based Panda Power Funds is financing and building one of the largest coal-to-gas conversions in the U.S. at a shuttered coal plant in Sunbury, Pennsylvania.

Industrial demand

U.S. industries currently use about 21.3 Bcf/d, according to the EIA, with demand estimated to climb to 24.8 Bcf/d by 2020 and 26 Bcf/d by 2025.

“Much of North America’s ramping industrial and utility output fueled by gas will surely benefit the lives of North Americans. But a good portion of the output will likely also go overseas as intermediate or finished goods at a higher value to global markets than commodity natural gas,” said Stratas Advisors’ Haas.

In Ohio, several industrial plants are planned or under way, JobsOhio’s Mustine said. He cited Potash Corp.’s expansion of an ammonia plant in Lima, which although in the western part of the state, benefits directly from Utica production in eastern Ohio. The $20 million project is nearing completion.

“I should mention the PTT company out of Thailand. They’ve selected Belmont County for their site—they are in FEED now [front end engineering and design]. This would be a $100 million commitment with Fluor and Bechtel over the next nine to 12 months. This wouldn’t be there except for shale gas,” Mustine said.

The EIA’s projections are lower than estimates from Stratas Advisors, which said total U.S. gas demand will rise to 104 Bcf/d by 2020.

From commercial to Mexico

Morningstar said growth in the commercial sector “has been stagnant for a while, with relatively flat growth since 1997. However, concerns regarding emissions, particularly in the northeastern U.S., have led to programs that extend the choice of fuel source to the end user. We expect average peak residential and commercial gas demand to rise from 23.5 Bcf/d in 2014 to 25.5 Bcf/d by 2020.”

This year Mexico will import some 2.6 Bcf/d, but that number is estimated to reach 4.3 Bcf/d by 2020. “We expect low-cost gas supply to industrialize Mexico into a major consumer of U.S. gas for both feedstock and fuel purposes,” said Haas.

“Within this year or next, we expect more U.S. gas to flow to Mexico than Canada. The shale gale that started in the U.S. has not only led to reshoring of industrial manufacturing back into the U.S., but also the establishment of a new industrialization in Mexico.”

Mexican authorities have indicated they hope to import 9 Bcf/d from the U.S. under a five-year plan to 2019, to build additional pipelines and infrastructure, the country’s Energy Ministry said. That would be a major increase. The five-year plan also includes a new compression station and 13 other projects. The Los Ramones pipeline is already under construction to Nuevo Leon state.

“We see the significance of Mexico being a little underplayed,” said Morningstar’s Grimes. “The potential is huge … if their economy continues to improve we could increase our forecast.”

The price outlook

With so much planned on the demand side and so much natural gas supply available, the price outlook changes by the week. In his October report, Morningstar’s Grimes posited a base case of $4/Mcf to the end of this decade, despite his healthy forecast for incremental demand. Why not more? The beast in the Northeast.

“Break-even levels in the Marcellus—in dry-gas and liquids-rich areas—range from $0 to $4/Mcf, with an average of around $2.50. Accordingly, development is unlikely to slow—at least in the ‘core’ parts of the play … even under meaningfully lower natural gas prices. By 2020, we estimate the Marcellus will account for more than 25% of domestic gas volumes, up from less than 5% in 2010.

“Similarly, the Utica Shale … is characterized by high production rates and relatively shallow decline rates. …With an average of around 30 rigs running through 2020, we project that the Utica will add an incremental 5 Bcf/d to U.S. supply, accounting for just under 10% of domestic volumes by the end of the decade.”

At press time Deutsche Bank reduced its price expectations to $2.90/MMBtu for 2016 and $3.10/MMBtu for 2017, “on the basis of a mismatch between expected demand growth at 2.2 to 2.4 Bcf/d and supply growth of 3 to 4 Bcf/d, based on producer plans and infrastructure expansions.”

A Raymond James report on gas said recently, “There is no avoiding the reality that there is plenty of sub-$3 gas through the end of this decade.”

Natural gas liquids have been hit as hard as oil and gas, and Raymond James thinks that until new petrochemical plants using NGLs are up and running beyond 2016, prices will remain low.

“Our thesis remains that easing infrastructure constraints (i.e., long-haul takeaway capacity, LPG exports, additional rail loading/unloading capacity) will continue to support NGL production. To those points, with the NGL barrel in a sustained period below $20/bbl in Mont Belvieu, yet production still arriving higher than last year, it’s apparent that only a substantial and lengthy slowdown in both oil and gas producing activity could materially tighten the NGL markets—at least until meaningful export demand and petrochemical cracking hits in 2016-plus.

“Even when we factor in modestly higher LNG exports, the U.S. gas equation now looks meaningfully oversupplied at $3.25/Mcf. Accordingly, we are lowering our 2016 Henry Hub price estimate from $3.25 to $2.35/Mcf, and our long-term forecast from $3.25/Mcf to $2.75/Mcf.”