surplus

The CME/NYMEX Henry Hub January contract settled yesterday at $3.54/MMBtu, about 30.8 cents (~10%) above where the December contract expired ($3.232) and 77.6 cents (28%) higher than where November settled ($2.764). The natural gas winter withdrawal season is officially underway—it’s a lot colder and gas demand has spiked. But this week also marks another key bullish threshold: as today’s Energy Information Administration (EIA) storage report will likely show, the U.S. natural gas inventory has fallen below the prior year’s levels for the first time in two years (since early December 2014). That’s in sharp contrast to where the inventory started the injection season in April—more than 1,000 Bcf higher compared to April 2015. Moreover, we expect the emerging deficit to grow substantially over the next several weeks. Today we look at the supply-demand fundamentals driving this shift and what it means for the winter gas market.

<p>June was somewhat of a game-changer for the 2016 U.S. natural gas market. Summer weather finally arrived and U.S. consumption, particularly from power burn, was at record highs, as were exports to Mexico.</p>

Over the past 20-some days, U.S. natural gas prices have gone from being the lowest in more than a decade to very close to last year’s levels. The July 2016 CME/NYMEX Henry Hub natural gas futures contract on Thursday (June 23) settled at $2.698/MMBtu, up about 70 cents (36%) from where the June contract expired ($1.963/MMBtu on May 26) and also up nearly 50 cents (23%) from where the July contract started as prompt month on May 27 (at $2.169). Market buying to unwind short positions initially kick-started the rally, but since then hot weather and a boost in power demand has kept the rally going. National average temperatures have averaged nearly 8 degrees (Fahrenheit, or F) higher in June to date versus May, and in the past week they’ve climbed above the peak summer levels normally not seen until mid- to late-July. Gas consumption on a temperature-adjusted basis also soared in the first half of June, led by power burn (gas use for power generation). The combination of hot weather and higher gas usage per degree of demand has been practically made-to-order for the oversupplied gas market, and has led to record power burn in June to date. But higher prices have the potential for bearish consequences—the recent gains have catapulted natural gas prices well above prices for coal on a cost-per-MMBtu basis—making the latter fuel more economically competitive in the power generation sector. That’s welcome news for coal producers, but what will it do to natural gas demand and in turn gas prices? Today, we look at the shift in the coal-gas price relationship and the potential impact to power burn and the gas market.

The U.S. Energy Information Administration (EIA) on Thursday (June 9) reported a surprisingly bullish 65-Bcf injection for the week ended June 3—that was 8.0 Bcf below our Natgas Billboard estimate and more than 10 Bcf below the Bloomberg industry average assessment. In response, the CME/NYMEX Henry Hub July natural gas contract screamed about 15 cents higher following the report to a settle of $2.617/MMBtu, the highest daily settle for the prompt month in nearly 9 months. Thursday’s gains extended a rally that began on May 31 (2016) just after the July contract rolled to the front of the futures curve. It’s likely the rally was initially spurred by market participants looking to cover their short positions. But in the past week, an increasingly bullish fundamental picture has emerged prompting us to raise our price outlook (in our June 10 NATGAS Billboard report). In today’s blog, we analyze the fundamentals behind rising natural gas prices.

Natural gas production in the Lower 48 has surged 40 percent since 2005 – hitting record levels in recent months in spite of low prices and a drilling migration away from dry gas to liquids plays. Following a similar trajectory, natural gas liquids (NGLs) output from gas processing plants jumped 40 percent since 2009 as drilling for wet (high BTU) gas accelerated. Crude oil production from shale did not take off until the end of 2011 but since then has surged an astronomical 56 percent to 7.8 MMb/d. While this winter’s harsh weather has placed a temporary slow down on these skyrocketing production numbers, RBN fully expects the growth trend to continue - putting the U.S. within sight of energy independence in the not too distant future. Along the way plenty of new opportunities for the industry will be tempered by market challenges. Today we preview RBN’s latest Drill Down Report.

The Louisiana Offshore Oil Port (LOOP) is currently the nation’s largest waterborne crude import terminal. Throughput at LOOP has been declining as domestic crude production has increased. Crude oil imports were over 1 MMb/d in 2008 but dropped to 0.5 MMb/d by September 2012. Light sweet crude imports in September 2012 were 10 percent of their level in 2008. Today we look at future prospects for this huge marine terminal and storage facility on the Louisiana Gulf Coast.

Over the next five years, natural gas production in the Marcellus is expected to double, from just less than 8 Bcf/d today up to almost 16 Bcf/d in 2016.  As that production enters the market, volumes that have traditionally served the Northeast market from LNG imports, Canadian imports, inflows from the Rockies/Midwest, and inflows from the Gulf will no longer be needed.  Last week we examined possible scenarios for these flow shifts.  Today we’ll look at the ramifications for regional supply imbalances and where the traditional supplies will be going if not to the Northeast in this, the Great Flow Reversal of 2016.

Two weeks ago we took a deep dive into the great 2012-18 ethane debate. Will we make too much of the stuff?  Or not?  Over the next five years, billions will be spend by the petrochemical industry chasing what promises to be huge margins for conversion of ethane to ethylene.  But it will take time to bring most of that capacity online.  What happens in the meantime?  NGL production from wet shale plays is growing fast.  If the ethane cut exceeds the ethylene industry’s capacity to consume the feedstock, then the excess ethane will be ‘rejected’ back into the natural gas stream. When and if this happens, the price of ethane in Mont Belvieu will drop to something near fuel value at the gas processing plant.  The debate is whether or not this is likely to happen.

Yesterday was Day#2 of Benposium, the annual Bentek conference being held at the Houstonian hotel in Houston.  It was another day when I could attend the sessions as a participant, which is considerably harder work than it sounds.  Between Tuesday and Wednesday there were seven outside speakers and 15 breakout sessions with Bentek analysts, each repeated twice over the two days.  They went deep into natural gas, crude oil and NGL markets.  After 48 hours of Benpo 2012, my brain is full.  And there is one more day to go.

Rather than getting into the gory details of all these presentations, I thought it would be a good idea to take a page out of Cramer (that would be Cramer's Mad Money, not Cosmo Kramer) and do a lightning round on all of the major themes I heard across the two days. 

Last Thursday we looked at one side of the great 2012-18 ethane debate. Will we make too much of the stuff?  Or not?   Will the petrochemical industry have the capacity to chew up rapidly increasing ethane production. Or could producers and processors churn out so much ethane that the price will be forced down to fuel value (a price equivalent too natural gas), resulting in massive ethane rejection at gas processing plants.