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Weissman’s Market Negatives Adding Up to Plunging Natural Gas Prices

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 webinar Thursday, 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.”

Thursday’s trading action showed signs of natural gas prices testing the upper end of their recent trading range, and potentially moving to new highs, but Weissman said he doesn’t think the New York Mercantile Exchange (Nymex) July contract’s closing price of $2.952 is sustainable.

Weather Still Top Factor

As always, weather is paramount to the market. EBW is forecasting a warmer than normal summer overall, but June-August should see slightly cooler conditions when compared to the five-year average. May ended as the second warmest on record since 1981, with 178 total cooling degree days (CDD). That’s 64 more CDDs than last year and 56 more than the five-year average.

Meanwhile, the June-August period is expected to see 947 CDDs, up 10 CDDs from last year but six below the five-year average. EBW senior weather forecaster Stephen Strum, who is also a senior executive at Weather Decision Technologies (WDT), noted that the five hottest summers on record since 1980 have occurred in the last eight years -- 2016, 2015, 2012, 2011 and 2010 -- “so the bar is set really high for comparisons.”

“It’s going to be a hot summer for a lot of areas,” Strum said, including in the Plains, the Southwest and Texas. The eastern U.S. temperatures are expected to average close to normal, but forecasts are trending cooler.

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. The June contract expired at $2.875.

“We’re not anywhere close to a ‘business as usual’ scenario,” he said. “We’re entering a situation different than anything we’ve ever experienced.”

At the same time more supply is coming into the market, there is simultaneously a sudden change in storage targets, Weissman said. For example, in early April, the market was projecting end-of-November storage inventories near 3.8 Tcf. Now, those projections are down to around 3.6 Tcf, and Weissman expects projections to fall even further. EBW is forecasting the most likely scenario for mid-November storage is for inventories to be around 3,450 Bcf.

In the near term, EBW is projecting a 91 Bcf injection for the storage report for the week ending May 31, a 95 Bcf injection for the week ending June 7 and a 99 Bcf injection for the week ending June 14.

“If the market’s storage target declines, then the effect is there’s not a need to inject as much gas into storage,” and that loss of demand would increase the amount of excess gas and cause prices to drop lower. “Those factors are just starting,” he said.

Of course, other factors could influence prices in the coming months. Variances from normal weather, the actual growth rate for production versus the expected growth rate, additions of new gas plants and other forms of generation, pipeline additions and constraints, and a host of other factors also impact the market.

Meanwhile, the 2018 Atlantic hurricane season kicked off Friday (June 1). The season got off to an early start with subtropical storm Alberto, but Strum said this season should not be as extreme as last year’s hurricane season and only slightly above normal. WDT is calling for 13-15 named storms, down from 17 last year; six to eight hurricanes, down from 10 last year; and three to four major hurricanes (Category 3 or higher), down from six last year. A few Gulf Coast storms are possible, he said.

WDT’s hurricane outlook is in line with that of the National Oceanic and Atmospheric Administration, which called for a 70% likelihood of 10-16 named storms forming in the Atlantic Basin, with five to nine becoming hurricanes. Scientists at Colorado State University (CSU) expect 14 named storms, with seven becoming hurricanes, including three major hurricanes.

Current atmospheric conditions show no signs of an El Nino in place, but should a pattern develop later this summer, it could make for a cooler August and beyond, Strum said. The highest risk for an El Nino development is during August and September, which could impact the latter part of the hurricane season, which tends to pick up in August.

Gas Prices To Slump If Forecast Hits Mark

If WDT’s summer forecast is in the ballpark, gas prices would likely decline by an average of 30-40 cents compared to the current Nymex July-October strip ($2.90 as of May 30), Weissman said. Declines would be greater on the back end of the strip if gas prices were to remain at current levels for an extended period or temporarily increase.

Looking ahead, WDT’s initial fall and winter weather forecasts are warmer than normal, but Strum said they could change significantly depending on the evolution of El Nino and other factors.

As for supply/demand fundamentals, if prices were to remain at current levels in 2018 and 2019, then the market would wind up with so much excess supply “that if we put it all in storage, storage would reach 4,900 Bcf,” Weissman said.

Of course, that won’t happen because of the physical limitations of U.S. storage capacity. But more important, such a scenario would not develop because the market is lowering what it feels are acceptable levels of storage.

Furthermore, as new takeaway capacity in the Permian Basin comes into service beginning next year, the market should take notice, which could put further downward pressure on the storage target.

EBW is projecting that prices will have to reach $2.02/Mcf under its base case scenario for end-of-November 2019 storage levels to reach 3,550 Bcf. The Nymex strip (as of May 30) for the Nov. 2018-Nov. 2019 period sat at $2.80.

“If we get a mild summer, we could see prices that average as low as $1.20. We see more downside price risk than we’ve seen previously,” Weissman said. “And we don’t see it limited to 2019. It will likely continue in 2020.”

With associated gas being the single biggest source of growth, there is a very realistic potential that “we’ll have most of the gas we need even at a price that approaches zero,” he said.

The same dynamics in the gas market have the potential to drive down electricity prices, “which can be very good news or very bad news depending on which side of the table you’re on,” Weissman said. Currently, electricity prices in most regional transmission organizations are depressed, thanks to low natural gas prices, flat demand and rapid growth in renewable energy. Some markets have even seen negative pricing occur in some hours.

The exception to that is Texas, where real-time power prices have surged to well over $9,000/MWh as intense heat strains already tight reserve margins in the state. Weissman said the Electric Reliabilty Council of Texas (ERCOT), the grid operator for most of the state, is a prime example of low gas prices prompting the retirement or mothballing of significant coal capacity. In addition, low-cost renewable energy has kept prices low for a long time, which has deterred construction of more generation in the state.

“The result of that is that reserve margins in ERCOT have gone down substantially, and that’s left Texas very vulnerable to hot summer weather,” he said. With Texas on tap to see some of the hottest weather this summer, that could provide an early warning sign to other parts of the country that as renewables tend to drive prices down, the other side is that it causes retirements and noninvestment in new generation.

Already, EBW is expecting an extended period of electricity prices being driven low enough, especially by next year, putting a significant percentage of power producers under major financial duress.

“We believe this is a pretty extreme situation that’s about to develop,” Weissman said. EBW is expecting to signs occurring this summer and increasing in the fall, but the most dramatic declines will be halfway through next winter and into 2019 and 2020.

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