U.S. natural gas prices are going to be sluggish this year as the oversupply slowly is whittled down, but analysts said falling rigs and delayed pipeline projects should lead to a bullish recovery in 2017.
In their overview of the U.S. gas market issued Thursday, Tudor, Pickering, Holt & Co. (TPH) analysts said they remain bullish for gas prices starting next year. Milder-than-expected winter weather and continued above-average inventory builds led analysts to reduce the 2016 forest to $2.25/MMBtu from $2.65.
“However, we have also lowered our expectation of 2016 gas and oil activity impacting both ‘on-purpose’ and associated gas production,” said TPH’s Brandon Blossman, Matt Portillo and Erik Stevens. “Our lower 2016 price forecast should incent sufficient incremental gas generation demand to keep the market tight and chip away at current storage overhang.”
In the Northeast, where exploration and production (E&P) companies are begging for more capacity to carry supple Appalachian output, pipeline projects now under construction are the only “sure bet,” they said. “Given stretched E&P counterparty balance sheets and low, low current activity levels, producer-backed projects 2017-plus all have some degree of delay/deferral risk…The risk is real for continued project delays.”
Northeast gas producers have slashed the rig count to under 30 from 100-plus, and even more rigs are expected to fall. TPH’s E&P coverage universe of Northeast gas producers indicates capital expenditures are down on average about 45% year/year.
“Of the 20-plus Bcf/d of pipes set to come online through 2018, more than 50% is committed by producers that are faced with contracting cash flows and expanding leverage,” the analysts said. “We have seen more than 7 Bcf/d of pipe capacity delayed in the past year, a trend which may continue as we move closer to build-dates of new pipe capacity.” Those facts are borne out by the Federal Energy Regulatory Commission, whose timeline to review Northeast-focused pipeline projects has slipped (see Daily GPI, April 5).
U.S. liquefied natural gas (LNG) exports continue to look strong, with nameplate U.S. capacity forecast to be 8.4 Bcf/d by the end of 2020. TPH only has Gulf Coast projects in Texas and Louisiana in its forecast, with no U.S. or Canadian West Coast projects included.
Of the 8.4 Bcf/d projected from the Gulf Coast facilities, 7.8 Bcf/d (92%) already is contracted, which means that offtakers would pay $3.00/MMBtu for any contracted volumes deferred/canceled, according to TPH. Buyers then could buy the LNG on the spot market for $7.00/MMBtu, for an all-in cost of around $10/MMBtu including the cancellation fee.
All-in, the U.S LNG landed price in Asia today “likely” is running around $7.50-9.50, depending on the Henry Hub gas price and transport costs. Domestic LNG to Europe, assuming $2.50/MMBtu Henry Hub, $3.00 liquefaction charge and $1.00 shipping, would command an estimated landing price of around $6.50.
“This pricing environment makes it very challenging for LNG producers to ink long-term contracts at or above the $3.00/MMBtu tolling fee level,” TPH said. However, liquefaction owners like Cheniere Energy Inc. have inked spot contracts with offtakers in Europe “and they could generate a profit…even given current spot prices. It makes economic sense for both parties to take the U.S. volumes.” Minus the $3.00 liquefaction fee, Cheniere could break even today at less than $5.00/MMBtu LNG pricing.
“The liquefaction charge is every U.S. liquefier’s vehicle to earn a return on capital for these expensive LNG plants, but the actual liquefaction cost is much cheaper than $3/MMBtu,” TPH analysts said. “We estimate the actual cost to liquefy the gas is 50 cents/MMBtu…An open arbitrage/high margin spot volumes are icing on the cake. Thus, at today’s pricing and transport costs, a facility owner could ship U.S. gas to Europe for a variable cost of $4.00/MMBtu.”
On the gas import/export front, net Canadian gas imports are projected to decline early in the forecast then rise to 2015 levels by 2020. Forecasted Eastern U.S.-to-Canada export growth “is tied to the incremental 2.5 Bcf/d of pipe projects moving Marcellus and Utica gas to Canada, where we forecast 1.8 Bcf/d of flow by 2020.”
Canadian gas imports have been on the decline, but that may not last as “Marcellus gas will push North into Eastern Canada,” TPH said. “It is a safe bet that U.S. to Canada exports will push West-to-East Canadian gas flows back West and South into the Central U.S., increasing import volumes.”
For power generation, the key gas demand driver has been and remains price. Through the forecast period, TPH expects gas demand in power generation to average 500 MMcf/d growth/year. Lower coal production trends are “good for gas,” even if prices are not.
Industrial gas demand is forecast to spur prices too, now ticking up following a decade of declines. TPH is forecasting a 1.5% compound average growth rate in industrial demand through 2020 “adding just 350 MMcf/d of gas demand per year — a conservative forecast in line with our bottoms-up demand model and historical averages.”
Goldman Sachs on Thursday also weighed in on gas prices — and oil.
Natural gas equities have posted “strong” performance in the past few weeks because there’s more greater confidence that gas prices will improve over the course of 2016, wrote Goldman analyst Brian Singer. “However, January supply growth of plus-0.4% (0.3 Bcf/d) versus December, with Appalachia/Oklahoma being key contributors, adds concern to persistent production from dry gas plays. Notably, however, Texas production dropped 0.3 Bcf/d sequentially.”
As far as oil prices, a “Goldilocks idealism” is intact for 2Q2016.
“We view our 2Q2016 oil outlook as an idealistic Goldilocks scenario — $35/bbl West Texas Intermediate is not too high and not too low but just right — above cash costs but keeping a too-early shale restart at bay,” Singer wrote. Recent supply data from both the United States and the Organization of the Petroleum Exporting Countries (OPEC) are “somewhere between in line and modestly bearish for prices,” but a modestly bearish near term “is not enough to change our attractive coverage view for E&P equities. We would use volatility to add to positions of shale productivity winners and the next rung down.”
Goldman analysts said they “are willing to look through near-term volatility because prices of $30-$35 should keep behavior of U.S. producers unchanged and accommodate $55-60/bbl oil in 2017, providing opportunity for equities. A rally to $45-50/bbl near term would reduce 2017 upside, but [it would] still be favorable for equities (at least temporarily).”
Producers aren’t likely to “depart from their capital budget plans unless oil goes to $50/bbl-plus and inventories versus historical trends fall,” although some Permian Basin players may begin to add activity at an oil price of $45-50.
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