For those awaiting a better natural gas market, a scriptural reference may be the order of the day—namely, that “endurance produces character, and character produces hope.” And for those with the character to have charted a course in natural gas, hope does endure that brighter days lie ahead, even though the exact timing of a gas-price recovery remains elusive.

Encouragingly, analysts increasingly point to structural factors boosting natural gas demand as they lay out timelines for a likely gas recovery. These include rising exports of natural gas to Mexico; gas-fired power generation replacing coal power retirements; and expanding gas demand from the industrial renaissance sweeping the U.S., prompting such projects as ethane crackers and ammonia plants.

The liquefied natural gas (LNG) sector is also cited as a factor offering relief to domestic pricing by providing access to export markets for natural gas. However, both LNG projects and ethane crackers involve long lead-times, such that their impact will be felt first on a smaller scale in 2016 and more fully in 2017 and 2018. Gas-to-liquids (GTL) projects are also on the drawing board, with South Africa’s Sasol, for example, planning a massive combined ethane cracker and gas-to-liquids (GTL) complex in Lake Charles, Louisiana.

So, the signs are that the tide is turning—especially with the Baker Hughes gas rig count down some 60% from its October 2011 peak, indicating U.S. supply may flatten, or decline . But will natural gas pricing gain traction only in 2016-2017, with a clear step-up in industrial demand and potential LNG exports? Or could it find its footing sooner, and surprise to the upside in 2014-2015? If so, which stocks would you want to own?

Rehan Rashid, managing director and head of energy research at FBR Capital Markets, is a standard-bearer for recovering natural gas prices, projecting a jump to $5 per thousand cubic feet (Mcf) next year. Thereafter, his price deck assumes a $4.50 average price for both 2015 and 2016. This compares to a consensus forecast of $4.20 for next year, followed by about a $4.40 estimate in 2015 and 2016.

“We think that gas prices have much more upside late this year, most of next year and beyond, than is priced into the strip and into equities,” says Rashid.

Although Rashid recently lowered his 2013 average gas price estimate to $3.88 per Mcf, he left his $5 projection for 2014 unchanged in the belief that fundamentals indicate a tight gas market. The lower 2013 estimate reflected some cooler regional weather, but a bigger factor was power generators’ need to burn off a “one-time” excess of coal inventory of about 23 million tons left over from the 2012-2013 heating season. Burning this coal instead of gas equates to 1.2 billion cubic feet (Bcf) of lost gas demand on an annualized basis, or 3.6 Bcf/d if concentrated into just June through September, as is likely.

“The extended winter helped get rid of the excess gas Btus, but we needed a fuller summer to get rid of the coal inventories as well,” he says.

In projecting a tight gas market next year—in the face of ongoing production gains from the low-cost supply basin of the Marcellus—Rashid models take-away capacity-constrained Marcellus production averaging 10.5 Bcf/d in 2014, up from 8.4 Bcf/d this year. In dry-gas basins, the rig count is assumed to be unchanged. Associated gas from liquids-rich plays is expected to continue growing but be roughly offset by the rise in exports to Mexico and the slide lower in imports from Canada. Total Lower 48 dry-gas supply, including net imports, is estimated at 69.3 Bcf/d, up 1% from 2013.

What tightens the market is mainly on the demand side, with the largest factor being increases in demand for gas to replace coal as a power-generating fuel in the wake of Central Appalachian (CAPP) mine closures, according to Rashid.

“From 2012 through 2014, 40 million tons of coal from mountain-top mines will have been shut down, equal to 2 Bcf/d of gas on an equivalent energy basis,” says Rashid. “And it’s not coming back.”

The 2 Bcf/d of coal-to-gas switching makes up the largest part of almost 2.8 Bcf/d in higher gas-fired electric power-generation demand in the three years since 2011, according to Rashid’s gas model. This brings projected gas-fired generation demand to 23.4 Bcf/d in 2014, up 1.5 Bcf/d, or 6.9%, from a year earlier. The jump in gas-fired generation demand, plus 3% higher industrial demand, pushes total dry-gas demand next year up to 72 Bcf/d, resulting in a 2.7 Bcf daily deficit versus supply of 69.3 Bcf daily.

Rashid estimates it will take between nine and 15 months for E&P companies to ramp up to a “reasonable number of rigs to clear the deficit,” allowing gas prices to average $5 per Mcf for the full year. “Demand is scalable; supply isn’t,” he observes. And natural gas gains in place of CAPP coal are unlikely to be reversed in a higher commodity price environment.

“That 40-ton marginal coal supply needs $5.50 gas to be incented back into the market. But it won’t happen because of the longer-term concern about climate change,” says Rashid. “Utilities would rather pay $7 for gas rather than to get CAPP mines started back up again.”

Stocks for a recovery

Rashid favors Comstock Resources Inc. (CRK) and Devon Energy Corp. (DVN) as stocks to play a recovery in gas prices. His target prices for the two names are $27 per share and $77 per share, respectively, offering upside of roughly 70% and 35% from levels prevailing at the time of his reports.

Comstock is well capitalized and can rely on growth of its more liquids-oriented Eagle Ford operations to act as “bridge assets” toward 2015-2016, when coal-fired power retirements and LNG exports will put “a better structural bid under gas.” Natural gas is projected to make up about 63% of its 2014 production.

In the Eagle Ford, Comstock has doubled its rig count to six, which Rashid expects will drive companywide production up 17% in 2014. With an inventory of 230 gross wells on 80-acre spacing, Comstock’s net resource potential is estimated at 78 million barrels of oil equivalent (BOE). However, based on industry success, Rashid is comfortable using denser 60-acre spacing, which expands Comstock’s inventory to 320 locations with a net resource potential of 100 million BOE.

Rashid values the Eagle Ford assets at $1.1 billion. Other gas-producing assets—some 156 million cubic feet per day mainly in the Haynesville—are valued at $780 million based on $5,000 per flowing Mcf. This adds to a combined value of around $1.875 billion, which net of $675 million in long-term debt leaves an equity value of some $1.2 billion. This compares favorably to a market capitalization of approximately $870 million, based on Comstock’s recent price of about $18 per share.

With a $100-million stock repurchase program, plus greater balance-sheet strength after the roughly $800-million sale of its West Texas operations, Comstock offers “an extremely compelling” value, says Rashid. And some 6 trillion cubic feet of resource potential in the Haynesville offers added upside.

Rashid takes a broader approach to Devon Energy, saying the company is well-positioned to go from having just one core area as it entered 2013 to having five such areas now and possibly six within the next 12 months. He defines “core” as areas where current production is “substantially in the money” or ones with a sustainable reinvestment capacity of $500 million to $1 billion per year. Devon’s “only real core area” entering this year was the Permian, where 2014 production is projected to double.

With gross drilling capex of $1.5 billion this year, the Mississippian play moves “firmly” into the core area category, he says. The Barnett and Cana, which are uneconomic at sub-$3.50 per Mcf gas, are re-designated core under a $4.50 long-term price assumption. Canadian thermal assets are similarly upgraded as a rise in take-away capacity, notably rail, is expected to improve differentials sustainably. And with geologic de-risking, the Cline in the Permian Basin has the potential to emerge as a standalone sixth core area.

Rashid expects Devon to deliver 10% growth in 2014 and says Wall Street has been slow to value the company’s progress. His $77 per share target is based on the stock trading at 70% of its 3P net asset value and at a multiple of enterprise value to 2013 EBITDA (earnings before interest, taxes, depreciation and amortization) of 5.8 times versus 4.5 times recently.

A slow drift higher

Analysts at Raymond James & Associates offer a somewhat more tempered viewpoint, forecasting simply a confidence that natural gas prices “will slowly drift higher over the next five years.” The firm’s price deck for natural gas assumes $3.75 and $4 per Mcf for 2013 and 2014, respectively, and $4.25 in 2015 and beyond as a long-term price assumption. However, the $4.25 forecast has an “upward bias” to it, according to a mid-June report.

“Don’t rule out the possibility of a short-lived gas price spike in 2015-2016, if surging demand temporarily outpaces the industry’s ability to bring new supply on line,” the report says.

The Raymond James research team has put a pen to expected growth in gas demand from four key sectors. It concludes that gas demand will rise by seven to 12 Bcf/d in the years 2014 to 2017.

Industrial gas demand is set to grow by 0.75 to 1.5 Bcf/d annually, with the largest drivers being ethane crackers and GTL projects. While GTL is harder to predict, Raymond James believes at least four ethane crackers will be built, adding nearly 1 Bcf daily of gas demand. In total, industrial demand is forecast to grow to more than 23 Bcf/d in 2017, up from 19 Bcf/d in 2012.

Gas-fired power demand is poised to grow by 0.65 Bcf to 1.0 Bcf/d annually, driven by retirements of coal-fired plants, while U.S. exports to Mexico are forecast to grow by 0.4 Bcf/d annually. Meanwhile, Cheniere Energy’s Sabine Pass project is scheduled to start up with 1 Bcf/d of LNG exports from its first two trains in 2016, doubling capacity with a third and fourth train by late 2017.

Andrew Coleman, managing director at Raymond James, currently has two gas-levered stocks that are rated Buy: Cabot Oil & Gas Corp. (COG) and Southwestern Energy Co. (SWN), with targets of $80 and $48, respectively. Two names he covers with a Neutral rating are Range Resources Corp. (NYSE: RRC) and Ultra Petroleum Corp. (NYSE: UPL), both companies with “high-quality management teams and meaningful gas resource exposure.”

Coleman favors Cabot , a leading Marcellus player, because, among other attractions, it has a “stellar” balance sheet and can self-fund its growth even as it expands production by as much as 50% on a year-over-year basis, as was the case in the second quarter. For Southwestern, he is attracted by an outstanding operational track record and a solid balance sheet. Even though it will grow its Fayetteville shale production by only 15% this year, he sees upside from the firm’s new-venture activities across several basins.

In the event of stronger gas prices, Coleman says Range Resources is a “go-to gas name,” given its extensive base of quality assets and its exposure to a possible takeout. His current Neutral rating reflects Range’s relatively higher debt at roughly three times trailing 12 months EBITDA. “If the balance sheet were cleaned up somewhat, it would merit a different look, all else being equal.”

The most levered to higher gas prices is Ultra Petroleum, which amid weak gas prices has cut capex over the last two years by 75%. This has allowed it to generate free cash flow at the cost of production growth turning negative. With higher gas prices and capex, production growth would resume, and Ultra would stand to recover proved undeveloped reserves that it shed on paper with lower gas prices, notes Coleman. “Ultra has the leverage and the opportunity to surprise, because the story has been pretty quiet over the last 18 months.”

Of course, in commodity markets, timing can be crucial, and recent weakness in gas pricing has not helped a forward natural gas strip that continues to struggle to stay above $4 per Mcf for the next several years. So does the outlook justify any urgency?

As the gas-storage injection season progresses, “we’ll see if we are taking a step closer to repairing the gas market, or if we’re just going to be running in place for a period of time,” says Coleman. Longer term, much may depend on oil prices falling enough to allow gas projects to compete for finite capital in E&P budgets. “The longer it takes for that to happen, the more gradual the increase in gas can be and the greater the opportunity for that mid- to late-decade spike in prices.”

Rashid is open to a more optimistic viewpoint.

“Until you have those structural, longer-term solutions, the gas price outlook for the rest of 2013 and maybe the first half of 2014 is still a trade on weather. But in between, weather could really swing things hard. Demand is scalable; supply is not,” he reiterates.

“If the summer ends up being decent—even from here—you could be tight going into the winter. And then if winter shows up, a normal exiting winter number is 1.4 trillion cubic feet in storage. And 1.4 trillion in storage means $5 gas.”

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