Tighternatural gas supply and demand balances will be necessary to limit storageinjections this summer and keep inventories within capacity limits this fall ascurrent storage levels remain above the five-year range in all regions andstorage capacity remains relatively unchanged year on year, with demonstratedcapacity at 4,343 Bcf as of November 2015, up from 4,336 Bcf a year earlier,LCMC Research analysts said.
Assuming30-year normal weather assumptions at current NYMEX summer strip prices,end-of-October inventories will sit at 3,938 Bcf, just above last October'slevel, as demand and supply side fundamentals suggest a market more than 2Bcf/d tighter compared to the previous five summers, pointing to summerinjections of only 1,478 Bcf, the analysts said in a March 28 note.
Theanalysts anticipate a combination of stagnating production, rising LNG exports,lower Canadian imports and higher exports to Mexico will sink total supplythrough the summer by 2.5 Bcf/d year on year, while consumption increases by atotal of 2.1 Bcf/d.
Onthe demand side, power burn will remain the most important and dynamiccomponents of the equation. On an absolute level, power burns are up more than2.9 Bcf/d from the previous winter, driven by weather-related demand and moreimportantly coal-to-gas switching as a result of lower natural gas prices andpermanent coal-plant retirements. If natural gas maintains a similar share ofgeneration adjusted for seasonal trends and under a normal summer scenario,weather-adjusted switching levels could set new records and thesummer-over-summer incremental burn could be close to 3.0 Bcf/d, the analystssaid.
Additionally,there is another 6.5 GW of new natural gas-fired generation capacity expectedto come online by the end of October, with a majority of that scheduled tobecome operational before the peak months of July and August. Combined withmore than 5.0 GW of coal retirements, this greatly favors gas burn despite thelow utilization rates of the retiring coal plants, according to the LCMC report.
Counteringthe upside potential of this coal-to-gas capacity shift is 6.0 GW of new solarand wind assets along with a relatively better hydro situation, the greaterfeasibility to shut down the more flexible natural gas units to match thedecline in power demand levels for a weekend during the shoulder season,instead of shutting down a coal unit, and global economic growth or lackthereof.
"Whilethere is potentially another +0.5 bcf/d of industrial demand capacity expectedto come online throughout the summer of 2016, a decline in GDP growth wouldlead to an overall decline in capacity utilization and lower industrial demandfor natural gas," LCMC said. "We are currently assuming +0.25 bcf/dgrowth in industrial demand compared to the previous summer. That is also toaccount for the weakness in industrial demand observed last year as a result offuel substitution due to low oil and NGL prices as well as the negative impactfrom a weak energy sector overall."
Additionalboosts to demand could come from pipeline exports to Mexico, conservativelyestimated by LCMC to be at least 0.75 Bcf/d higher summer over summer,following the ramp up of phase II of Los Ramones.
LNGexports should provide an additional outlet to the U.S. natural gas marketstarting this summer, with Sabine Pass Train 1 already exporting and Train 2undergoing commissioning. Together they have an export capacity of 1.5 Bcf/dand Train 1 has operated at close to capacity as it loaded its first twocarriers.
" hasstated that they expect another 10 carriers by the end of April, however itscontractual delivery obligations do not start until the fall. With Sabine Passtaking advantage of spot market rates, we expect a 50% utilization ratethroughout the summer, which would provide +0.75 bcf/d of export capacity,"the LCMC analysts said.
Mexicoand LNG exports will be of the greatest benefit to the south central region,which saw the greatest inventory surplus at the end of the winter 2015-16, withinventories being more than 520 Bcf higher than last year.
"Thatsurplus has to be taken care of, because at the end of last summer inventoriesgot uncomfortably close to storage capacity causing considerable weakness inSouth Central regional cash prices and some impressive moves wider in frontfuture spreads," the analysts said.
Pipelineexports to Mexico and LNG exports out of Sabine Pass should cut summerinjections by 320 Bcf in the south central region, while a 2.5 Bcf/d decline insouth central production would cut summer injections compared to last summer by535 Bcf.
LCMCsaid overall natural gas production was down by about 300 Bcf in the winter2015-16due to weather-driven supply losses, and will remain weak across theregions through the upcoming summer.
Inthe winter, while warm weather limited freeze-off events to one in Texas andOklahoma that amounted to production curtailments of about 10 Bcf, weatherdenied producers the ability to ramp up production in response to peak winterdemand, the analysts said.
Coldweather at the end of January and a cold forecast for February at the timeshowed potential production capacity had winter demand been there, LCMC said. "Northeastproducers alone ramped up output by +1.5 bcf/d in February, pushing overallproduction to all-time highs at over 75.5 bcf/d – a level made possiblefollowing the Northeast pipeline expansions in 2015. Since this productionhigh-watermark is 2.0 bcf/d above the realized average daily winter production,we estimate weather-driven supply 'losses' at 300 bcf."
Further,a combination of lower prices in oil and natural gas has obliterated the numberof active drilling rigs to just 464 as of March 24, from a high of 1,930 as ofSept. 26, 2014.
Whilethe initial decline in active rig counts did not translate to a decline inproduction due to high-grading and efficiency gains that helped maintain steadyproduction levels early on, some plays have lost all rigs, making any drillingefficiency gains irrelevant, the LCMC analysts said.
With1,930 total oil and gas rigs in 2014, natural gas production was growing closeto 8 Bcf/d, while as of March 24, there were only 92 gas rigs left and even aformerly prolific shale play like the Fayetteville has lost all of its rigs.The Fayetteville itself is already suffering a year-on-year production declineof more than 0.5 Bcf/d and nationwide production should decline by about 1.0Bcf/d by October.
Althoughproducers have the ability to increase production without rigs due to a vastinventory of drilled but uncompleted wells, LCMC analysts said what the marketgains in flexibility is outweighed by a higher sensitivity to declining prices.
Withoutweather, Northeast production remains demand constrained so LCMC does notexpect any significant growth until the next pipeline capacity expansions inNovember. The declines in the rest of the country should also continue as longas producers do not get a price signal to access their drilled but uncompletedwell inventory or even bring back rigs and aggressively start drilling again,LCMC said.
Inpricing, LCMC said an end-October inventory level of 3,938 Bcf does not suggestcongestion pricing risk and, assuming normal weather beyond October as well,LCMC does not expect a repeat of last year's cash weakness. The South Centralinventory surplus should be addressed by the end of October as well; thereforethere will not be a need to incentivize gas out of the region through weakregional cash prices.
Atthe same time, the analysts said there is not enough spare storage capacity toallow for a significant and sustainable price rally that would hurt power burndemand and would risk incentivizing stronger production.
"However,if the lower weather sensitivity of the supply and demand balances does verifyduring the shoulder season as we expect, then we could have a repeat of lastyear's shoulder season rally," LCMC said.