As the saying goes, April heating demand brings May cooling demand, or something to that effect.
After an unusually chilly April prolonged the withdrawal season, a consistently warmer-than-normal May has raised the prospect of a hot start to summer cooling, encouraging natural gas bulls eyeing large storage deficits and boosting June bidweek prices, especially in California, the Rockies and Texas. NGI’s June National Bidweek Average added 7 cents to $2.48/MMBtu.
According to Gaithersburg, MD-based forecaster Radiant Solutions, May was so hot it could end up setting a record for U.S. population-weighted cooling degree days (CDD) going back to 1950.
Over the Memorial Day weekend, Minneapolis saw a high of 100 degrees, the earliest triple-digit heat on record there, while Milwaukee saw its hottest May temperature on record at 95 degrees that weekend, the firm said.
“May has been a month of frequent summer-like heat across much of the U.S., including key power regions such as MISO,” Radiant senior meteorologist Steve Silver said.
The heat should continue through the first part of June, focused over the Southwest and south-central United States. Texas should see sustained heat, including frequent highs in the 100s in cities like Dallas, according to Radiant.
“With the extreme heat coming much earlier this season across ERCOT,” i.e., the Electric Reliability Council of Texas, “Dallas has the potential to surpass last year’s total of 100-degree days rather quickly this summer,” Silver said.
Combined fixed and basis trades trended higher across Texas for June bidweek. In East Texas, Katy jumped 18 cents to $3.05, while Houston Ship Channel added 12 cents to $3.03, both enjoying premiums to Henry Hub.
The higher cooling loads on ERCOT helped improve the prospects for the constrained West Texas producing region after its shoulder season slump. For June bidweek El Paso Permian surged 62 cents to $1.89, while Waha similarly climbed 62 cents to $1.97.
Further west, SoCal Citygate and PG&E Citygate both saw big gains ahead of prospective June cooling demand. PG&E Citygate finished 45 cents higher at $3.10 for June bidweek, while the often-volatile SoCal Citygate added 52 cents to $3.53.
Southern California Gas (SoCalGas), dealing with ongoing import and Aliso Canyon storage constraints that have caused significant price spikes going back to last year, told shippers in late May that, per an order from the California Public Utilities Commission (CPUC), it will “make 245,000 Dth of the capacity set aside for the balancing function available for injection nominations starting cycle 1 for the month June.
“This quantity will be made available on a reasonable best efforts basis considering operational limitations,” the utility said.
Regulatory restrictions on the Aliso Canyon storage facility following the 2015 leak could cause problems for SoCalGas this summer, Portland, OR-based Energy GPS said earlier in May.
“The current SoCalGas system is under maintenance. Some of this is forced and some of this is planned, which is taking the available pipeline supply from the Rockies and West Texas down from 3.1 Bcf/d last summer to 2.58 Bcf/d this summer,” the firm said. “That is a 17% cut in system deliverability at a time when peak gas demand is expected to reach 3.5 Bcf/d. If the withdrawals from all other storage facilities on the system are maximized, Aliso will still need to take gas out of the ground for reliability.”
While the CPUC approved a request from SoCalGas to allow injections into Aliso for summer reliability, this could cause problems, given that once those molecules are injected their use would become restricted under a regulatory protocol calling for “rationing of power generation and every other means of meeting demand before the volume can be taken out of the ground,” according to Energy GPS.
In Canada, NOVA/AECO C added C19 cents to average C86 cents/GJ for June bidweek, a notable improvement given spot prices there traded in negative territory in early May.
“We continue to see the AECO market as undersupplied through 2018 and 2019, in large part due to strong demand from the power sector,” analysts with Tudor, Pickering, Holt & Co. (TPH) said in a recent note. “We estimate baseload (weather neutral) demand is up 18% year/year (y/y), as mothballing of coal fire plants is leading to gas fire capturing a greater share of the power stack.
“Year-to-date, the gas share of power generation sits at 39%, up from 30% last year and nearly double 2014 levels (20%),” the TPH analysts said. “Combined with oilsands demand, we estimate baseload demand is up 0.67 Bcf/d y/y, which, coupled with stronger exports, is more than offsetting higher production levels. We expect the tightness in the market to result in weekly inventory builds being roughly half of normal levels, leaving storage at a five-year seasonal low entering winter.”
TPH analysts pushed their estimated start-up date for the recently approved North Montney Mainline conversion from June 2019 to November 2019, “which extends the undersupply through 2019 and should support strong pricing for the next 12-18 months.”
In the Rockies, most points strengthened during June bidweek, including Cheyenne Hub (up 17 cents to $2.08) and Transwestern San Juan (34 cents higher at $2.11).
As of Friday, the first day of the month, Radiant Solutions was forecasting persistent widespread above-normal temperatures through mid-June across much of the Rockies, Midwest, Southwest and Texas.
The firm’s forecast included much above normal temperatures averaging the period from June 6-10 from the Interior West into the central and southern Plains. From June 11-15, large portions of the Southwest, Interior West and Midwest were likely to see overall warmer temperatures, according to the firm.
Even with the prospect of a hot start to summer, the natural gas market continues to wrestle over the implications of large storage deficits -- still hovering around minus 500 Bcf versus the five-year average at the start of June -- given projections for supply growth to outpace demand over the next few years.
Lined up against predicted warmer-than-normal temperatures this summer is an emerging storage “lite,” which, when paired with booming production, especially from associated gas, portends a high likelihood that natural gas prices will start falling, according to EBW Analytics CEO Andy Weissman.
During a May 31 webinar, the energy industry expert said the market is in the first stages of an extended period where supply growth will outpace demand growth. The natural gas market, he thinks, is expected to see roughly 24 Bcf/d of additional supply in the United States during the three-year period from 2017-2019. Given that “startling increase,” the time period where supply growth outpaces demand growth month after month is expected to continue quite possibly into 2020.
“The implication of that is very clear,” Weissman said. At current price levels, the market would develop a growing amount of excess supply, whereby the only way it could be absorbed is for prices to come down “very significantly,” suggesting the July contract’s May 31 settle price of $2.952 is unsustainable.
The recent heat in May, preceded by the coldest April on record, was sort of a saving grace for the gas market as demand increased by a total of 180 Bcf for those two months. Had weather been normal during April and May, prompt-month prices would have been 37 cents lower, close to $2.50, according to Weissman.
Weissman’s bearish natural gas price outlook comes on the heels of similarly grim takes offered by Sanford C. Bernstein & Co. LLC and Raymond James & Associates Inc.
Gas price moves are sluggish, and “long periods of low gas prices” are likely if oil prices are constructive to U.S. growth, said Bernstein analyst Jean Ann Salisbury and her colleagues in a May note. “We are gas bears and believe that we have seen the end of $3.00/MMBtu gas prices for at least seven years.”
A recent survey by UK-based Energy Aspects Ltd. (EA) of 50 of the largest onshore operators showed U.S. natural gas producers guiding toward 4.2 Bcf/d of output gains in 2018 versus last year. That’s more than half of EA’s total projected year/year production growth of 7.0 Bcf/d.
The biggest uncertainty looming for exploration and production (E&P) companies in the leading natural gas producing Appalachian and Permian basins is takeaway capacity, according to analyst David Seduski.
“Range noted in its conference call that without additional capacity it has contracted on the beleaguered Rover Phase 2, its Appalachia production was likely at a ceiling of 1.2 Bcf/d,” while “Cabot cited the need to temper expectations until work is completed on Atlantic Sunrise.”
Lots of questions during first quarter calls also centered around Permian gas constraints, which E&P executives noted are linked to oil takeaway rather than gas infrastructure.
Appalachian producers got a bit of good news on the last day of May as FERC authorized full service on the 3.25 Bcf/d Rover Pipeline’s Mainline B.
“Flows on Rover have begun increasing with portions of Phase 2 now in service,” Genscape Inc. analysts Colette Breshears and Vanessa Witte said in a June 1 note to clients. “Minutes after that 9 a.m. CT deadline that Rover had set as necessary for allowing themselves time to complete June 1 contracts prior to offering service,” the Federal Energy Regulatory Commission issued its approval.
“However, FERC did not authorize Rover to operate the Burgettstown or Majorsville supply laterals, which restricts the addition of new supply to the mainline section,” Breshears and Witte said. “It is not clear if these new supply points are necessary to sustain a higher level of throughput on the pipeline, which Rover had said would increase by an incremental 0.85 Bcf/d if they were authorized in conjunction with the other facilities, or if currently operational receipt points will be able to increase volumes to take advantage of the extra capacity.”
Meanwhile, in a development giving natural gas markets bracing for associated gas growth more to ponder, crude prices started to retreat in late May in part on fears that the Organization of the Petroleum Exporting Countries (OPEC) could start to increase production.
OPEC and its allies, including Russia, could ramp up more oil to global markets “in the near future” to fill the gap from U.S. sanctions on Iran and the loss of Venezuela output, the Saudi Arabia energy minister said May 25.
During a panel discussion hosted by CNNMoney, Khalid Al-Falih said discussions are ongoing with cartel members and Russia to balance the market and reduce prices.
After cracking $70/bbl in May, as of June 1 Nymex West Texas Intermediate prompt month futures were trading down around $66/bbl.