Average natural gas prices for May failed to budge between April 6 and 12 as strong dry gas production in the Lower 48 continues to duke it out with ever-growing storage deficits, according to NGI’s Forward Look.
Dry gas production was reported to be around 78.9 Bcf/d for April 13, but the average for the week surpassed the long sought after 80 Bcf/d threshold, according to OPIS PointLogic. Production growth is expected to gain momentum in the coming months, with industry estimates pointing to a year-over-year growth exit rate of more than 6 Bcf/d.
For its part, Genscape Inc. on Friday said its monthly production model is calling for production to be more than 11 Bcf/d higher than the five-year average by Q4. Its daily production model has gone from 6.5 Bcf/d over the five-year average in January to 8.6 Bcf/d so far in April.
All that production growth is going to be needed, though, as natural gas storage inventory deficits continue to widen even beyond the traditional storage withdrawal season, which ended March 30. Working natural gas in storage at the end of the 2017-2018 heating season totaled 1,351 Bcf, the lowest level for this time of year since March 31, 2014, when stocks were much lower at 837 Bcf following the Polar Vortex winter of 2013-2014, according to the U.S. Energy Information Administration (EIA).
Deficits for this year widened even more when the EIA on Thursday reported a 19 Bcf draw from inventories for the week ending April 6, well above estimates averaging around a 12 Bcf draw. The pull compared to a 9 Bcf injection a year ago, which also matched the five-year average.
Total working gas in underground storage stood at 1,335 Bcf as of April 6, versus 2,060 Bcf a year ago and five-year average inventories of 1,710 Bcf, according to EIA. The year-on-year deficit widened week/week from 697 Bcf to 725 Bcf, while the year-on-five-year deficit increased from 347 Bcf to 375 Bcf, EIA data show.
Early estimates for the week ending April 12 point to another storage withdrawal between 10 and 20 Bcf, compared to the five-year average 38 Bcf injection. That would increase deficits in supplies to nearly 425 Bcf.
This summer, EIA expects injections into storage to be higher than normal, exceeding the average of the previous five injection seasons (April through October). Because of the regulatory obligations of many of the larger storage operators to provide winter heating service, U.S. natural gas storage levels tend to end the injection season close to the previous five-year average of about 3,800 Bcf.
“Doing so would require injections to total nearly 2,500 Bcf, or about 30% more natural gas than the average of the previous five injection seasons,” EIA said.
EIA’s latest Short-Term Energy Outlook forecasts that working gas levels will total 3,767 Bcf at the end of October, requiring net injections of about 2,416 Bcf over the injection season, the equivalent of 11.3 Bcf/d. In order to meet the injection requirements, the EIA forecasts that dry natural gas production will average 81.6 Bcf/d during the 2018 refill season, an increase of 8.3 Bcf/d, or 11% more than last year’s rate, “which more than offsets forecast increases in natural gas consumption, exports and storage refilling requirements.”
But gas prices, which for now appear to be stuck near $2.70, need to increase in order to ensure coal-to-gas switching does not prevent some of the new production from going toward refilling storage. After failing to move more than 4 cents on any single day from April 6-12, Nymex May futures rose 4.9 cents on Friday to settle at $2.735.
But Friday’s rally had little to do with the storage picture and more to do with slight changes in overnight weather models that called for another blast of cold to arrive in the East on Sunday and linger for a few days, driving up demand in the densely populated region. The strength in futures also piggy-backed off firmer cash prices due to the upcoming cold snap.
“It’s a rather chilly late season system with temperatures dropping 10-25 degrees Fahrenheit below normal behind the cold front with lows of teens to 30s,” NatGasWeather said. For the rest of the week through the following week, there will be a “nice mix” of mild and cool periods as numerous weather systems track across the country every few days with showers.
Given the short-term support, Friday’s move was being seen more driven by cash and weather than any type of need to raise prices significantly to fill storage sufficiently, according to Bespoke Weather Services. “Overnight data did not change much, though we did see nuclear outages increase quite a bit, which has strengthened burns. That, combined with very cold weather early next week, sent cash prices flying, and it seems like that’s pulling up the front of the strip,” Bespoke Chief Analyst Jacob Meisel said.
The market seems to have priced in production allowing the market to easily fill storage, “and that does not seem to have changed much recently,” he said. Bespoke’s long-term estimates, however, show the market may need higher prices this summer to ensure storage is adequately refilled, “but for now at least, the strip seems to indicate this is more a short-term story than a longer-term structural story.”
Some Market See Large Swings
Despite average prices for May seeing little change week over week, there were some markets that posted far more substantial gains or losses.
On the down side, El Paso-Permian saw prices across the forward curve ended firmly in the red as growing production in the oily Permian Basin is expected to become constrained soon due to a lack of gas infrastructure to move that gas to demand markets.
El Paso-Permian May forward prices plunged 16 cents from April 6 to 12 to reach $1.396, well more than $1 below the benchmark Henry Hub. June tumbled 12 cents to $1.457, the balance of summer (June-October) slid 13 cents to $1.43 and the winter 2018-2019 fell 11 cents to $1.42, according to Forward Look.
It was a very similar story at Waha, where May forward prices were down 11 cents from April 6 to 12 to $1.528, June was down 10 cents to $1.567, the balance of summer (June-October) was down 12 cents to $1.53 and the winter 2018-2019 was down 9 cents to $1.49.
Meanwhile, Transco Leidy posted substantial losses as the first of two maintenance events was set to begin April 16 as Transcontinental Gas Pipe Line begins work associated with the Atlantic Sunrise project on its 24-inch Leidy Line A.
The $3 billion Atlantic Sunrise expansion would open a path for constrained Marcellus Shale gas to reach markets in the Southeast through the Transco system running along the Atlantic seaboard. The expansion includes 197.7 miles of pipeline composed of about 184 miles of new 30- and 42-inch diameter pipeline for the greenfield CPL North and CPL South segments in Pennsylvania; about 12 miles of new 36- and 42-inch diameter pipeline looping known as Chapman and Unity Loops in Pennsylvania; about three miles of 30-inch diameter replacements in Virginia, and associated compressor stations, equipment and facilities.
The first event will run from April 16 to 26, and the second will run from May 1 to 11. During these outages, scheduled capacity at the Leidy Line Aggregate Receipt MP 101 location will be limited to 756 MMcf/d. As much as 1,120 MMcf/d has been nominated at this point within the last 30 days, according to Genscape.
Given the cut to receipts, Transco Leidy May prices fell 12 cents from April 6-12 to reach $1.997. But the rest of the curve was down as well, with June sliding 9 cents to $1.963, the balance of summer (June-October) dropping 7 cents to $1.98 and the winter 2018-2019 slipping 4 cents to $2.38, Forward Look shows.
AECO Edges Higher Amid Pipeline Expansions
The AECO forward curve was on the upswing during the week as the western Canadian market got two bits of good news. TransCanada brought online its Sundre Crossover project in Alberta. The in-service had been delayed from its April 1 target due to discovery of dents in the newly constructed line, Genscape said.
The Sundre Crossover is designed to enable the Nova Gas Transmission system to increase Western Canadian export capacity to the western US. It involved construction of 13 miles of 42-inch pipe adding 229 MMcf/d of incremental capacity to circumvent an existing constraint to flow gas to TransCanada’s Foothills BC system, which feeds the GTN pipeline in the U.S.
“The project should provide moderate relief to a heavily depressed AECO basis price, while radiating downward pressure on Rockies’ Opal-area basis by intensifying Alberta vs. Rockies gas-on-gas competition within relatively demand-stagnant western U.S. markets,” Genscape said.
Meanwhile, longer-term prospects for Alberta production to find a relief valve were improved as Alliance Pipeline announced it received enough interest from a non-binding open season to proceed with a binding one to expand the mainline system by 0.4 Bcf/d, a 25% increase from today’s levels. The expansion is targeted to be online by 4Q2021.
The Alliance pipeline carries liquids-rich gas from eastern British Columbia and Alberta to the Aux Sable processing facility near Chicago. Liquids-rich production continues to sustain Western Canadian gas production growth, which is well outpacing local demand and hammering on AECO basis by threatening to max out capacity on pipelines capable of exiting the region.
The supportive backdrop helped lift up AECO May prices 4 cents from April 6-12 to reach 81.3 cents, June prices 3 cents to 80.8 cents, balance of summer (June-October) prices 3 cents to 99 cents and winter 2018-2019 6 cents to $1.69, according to Forward Look.
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