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Natural Gas Production Weighs on Bidweek Prices as Market Takes Stock of Winter

A hefty storage deficit combined with near-record production had April natural gas bidweek traders taking stock of the market’s supply and demand balance on the cusp of injection season; the NGI National Bidweek Average shaved off 7 cents month/month to $2.36/MMBtu.

The month of March offered a handful of late-winter storms along the East Coast that helped make up for a mild February. Forecasts during bidweek trading showed colder temperatures lingering in the Midwest and East through the first week of April, enough to prolong the withdrawal season by another week or two, according to analysts.

The threat of lingering cold appeared to support the Northeast regional average during bidweek, mostly thanks to a 72 cent gain at the constrained Algonquin Citygate, which averaged $4.14. Tennessee Zone 6 200L similarly averaged $4.21.

Elsewhere in the East and Midwest, bidweek trades trended lower as expectations for chilly conditions to begin spring proved insufficient to boost prices. Transco Zone 6 New York fell 36 cents to $2.63, while Transco Zone 5 dropped 24 cents to $2.76. In the Midwest, Chicago Citygate dropped 6 cents to $2.46.

Meanwhile, a 5-cent month/month increase at Henry Hub helped support modest gains at points throughout the Gulf Coast and Texas.

Tennessee Zone 0 South climbed 6 cents to $2.56, while Houston Ship Channel surged 16 cents to $2.77.

In its last day of trading, the April futures contract climbed 7.3 cents to expire at $2.691, about a nickel higher than the March contract expiry. Helped by the supportive weather outlook, April gained a combined 10 cents over its last two days on the board to finish on a high note.

The strong finish for April still left prices on the wrong side of $3.00, with surging production seemingly enough to overwhelm any bullish momentum gained from late-winter heating demand and a 300 Bcf-plus year-on-five-year storage deficit.

The Energy Information Administration (EIA) reported a 63 Bcf withdrawal from Lower 48 storage for the week ended March 23, tighter versus the 58 Bcf withdrawn in the year-ago period and a five-year average withdrawal of 46 Bcf. But the figure came in slightly bearish versus expectations.

“This is the fourth week where EIA data was on the looser side of expectations, as data shows the impact of increased production and limited nuclear outages” during the report week, Bespoke Weather Services said. “On a seasonal basis the print shows structural tightness also easing as production soars.”

Total working gas in underground storage stood at 1,383 Bcf as of March 23, versus 2,055 Bcf a year ago and five-year average inventories of 1,729 Bcf, according to EIA. The year-on-year deficit increased slightly week/week from 667 Bcf to 672 Bcf, while the year-on-five-year deficit increased from 329 Bcf to 346 Bcf, EIA data show.

“Weather-adjusted supply/demand balance takes another slide toward parity from the undersupply scenario we've been seeing all winter,” analysts with Tudor, Pickering, Holt & Co. (TPH) said. The 63 Bcf withdrawal comes in about “1 Bcf/d lighter than analyst expectations, implying a near-balanced market. Expect to see an inflection point in storage levels as injection season draws nigh.”

Early storage estimates for the week ending March 30 “indicate the draw will nearly halve week/week,” said TPH. “With production levels in March some of the highest on record and continued upside from impending takeaway capacity, we expect a step-change to oversupply in the coming months.”

Not including storage data from the last week of March, the winter 2017/18 season will finish “well behind inventories from the prior two winter seasons,” according to OPIS by IHS Markit analyst Sadie Fulton.

Using data from its PointLogic suite, as of Monday (April 2) the firm was projecting end-of-season inventories of just under 1,350 Bcf.  “The last available end of season data from EIA places inventories at 1,383 Bcf, which is just 67.4% of winter 2016/17 end of season inventories or 56% of winter 2015/16 end of season inventories,” Fulton said.

Meanwhile, OPIS production data showed Lower 48 dry gas output increasing throughout the winter outside of January freeze-offs. March production averaged 79.1 Bcf/d, up from 76.8 Bcf/d in November 2017.

“While winter 2017/18’s production exceeded every month of the prior two winters’ values, demand did not follow suit...Net exports, however, were much larger in winter 2017/18 than they were in the prior two winter seasons,” Fulton said. “In every month of winter 2017/18, the Lower 48 exported more gas than was imported. This shift accounted for 4.2 Bcf/d less gas to find a home for in November of winter 2017/18 than in November of winter 2015/16.”

RBN Energy LLC analyst Sheetal Nasta said in a recent note that even with an expanding storage deficit the prompt month contract has “struggled to hold onto the $3/MMBtu level it started the season with in mid-November, and, in fact, has retreated back to an average near $2.70 in the past couple months -- about 25 cents under where it traded a year ago.”

A year-on-year comparison showed the natural gas market about 1.7 Bcf/d tighter, with growth in liquefied natural gas exports and higher residential/commercial (res/com) demand helping to drive a 9.1 Bcf/d year/year increase in demand for winter 2017/18, according to Nasta. This comes as growth from the Marcellus and Utica shales has seen production “average a whopping 6.8 Bcf/d higher than the previous winter” to drive a 7.4 Bcf/d year/year increase in cumulative supply.

“There is a big caveat to that winter-on-winter comparison, which is that the weather in winter 2016/17 was extremely mild,” Nasta said.

Swapping in five-year average res/com demand levels in the same comparison swings the net supply/demand balance from 1.7 Bcf/d tighter to 0.7 Bcf/d looser year/year, the RBN analysis shows.

While April cold could extend the withdrawal season a while longer, “with the coldest months of the winter behind us, overall demand is expected to trend lower from here,” Nasta said. “Additionally, rig counts, producers’ drilling plans and pipeline expansion plans -- including the Rover Pipeline completion -- all point to still more production growth from the current record levels. Thus, it’s looking like the days of an expanding storage deficit (compared to last year and the five-year average) are likely numbered.

“The bottom line is that while supply-demand balance has appeared more bullish than last year, that’s been more a function of the extremely mild winter demand last year and less about this winter being particularly strong. Rather, the outlier this winter is just the sheer volume of new gas production coming online, and that’s likely to become all the more apparent as the shoulder season wears on and heating demand fades.”

Elsewhere during April bidweek, West Texas points fell sharply. Pipeline takeaway capacity remains an ongoing concern for the Permian Basin as strong crude oil prices figure to continue driving production growth.

El Paso Permian tumbled 63 cents to average $1.26, with Waha similarly giving up 65 cents to $1.28.

As negative basis differentials have taken hold for Permian natural gas prices, crude oil takeaway capacity is also a concern, according to a recent note by East Daley Capital (EDC).

The spread between crude prices in the Permian’s Midland sub-basin “and East Houston grew to a high March 30, reaching $6.15/bbl,” EDC analysts said. “The growing spread is indicative of the quickly filling takeaway capacity in the Permian, which EDC estimates could completely fill by mid-2018.”

EDC said its estimate is based on looking at a daily residue gas sample to gauge production growth. That sample “confirms the growth trend, rising from an average of 2.6 Bcf/d in January 2018 to 3 Bcf/d in March. The next crude pipeline project expected out of the Permian is the” Energy Transfer Partners LP-backed “Permian Express 3 pipeline, which will provide 200,000 b/d of relief in late 2018. With the rapid growth in production, the spread between Midland and Houston could grow significantly for multiple quarters.”

Points in the West generally declined during bidweek. The Rockies regional average fell 36 cents month/month. In California, moderating demand saw SoCal Citygate drop 41 cents to $2.70 even after the recent announcement of yet more import constraints for utility Southern California Gas Co.

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