Billboard

At this time last year, the U.S. natural gas market was exiting an extremely bearish winter, the gas storage inventory was nearly 500 Bcf higher, and prompt month prices for the CME/NYMEX Henry Hub natural gas futures contract were more than $1.00/MMBtu lower. The question on our minds then was how far would production have to decline or how much demand was likely to show up to prevent storage capacity constraints by fall. In either case, the overarching sentiment was that prices would have to remain relatively low to balance the market. Now we’re exiting an almost equally mild winter, but a combination of lower production and higher exports has drawn down storage to well below year-ago levels, and the question occupying the market is more along the lines of, just how bullish could the market get this year? Today, we wrap up our look at injection season storage scenarios for the next seven months.

After exceptionally mild weather nearly derailed the U.S. natural gas market earlier this year, the gas supply/demand balance is set to end the 2016-17 withdrawal season relatively bullish compared to last year. Storage is finishing the season more than 400 Bcf lower than last year, albeit still 260 Bcf/d above the 5-year average. In addition, gas exports are continuing to ratchet higher. The April 2017 CME/NYMEX Henry Hub natural gas futures contract expired Wednesday (March 29) at $3.175/MMBtu, nearly $1.30 (67%) higher than the April 2016 contract settlement of $1.90/MMBtu and also about 55 cents higher than the March 2017 contract settlement. Yet, with the storage inventory still higher than the 5-year average and production growth on the horizon, the market remains susceptible to downside risk if incremental demand doesn’t show up. In today’s blog, we look at potential supply/demand scenarios for injection season.

The March 2017 CME/NYMEX Henry Hub natural gas futures contract has shed nearly 60 cents/MMBtu (17%) since February 1, 2017, and the rest of the 2017 curve has been slashed by an average 40 cents (12%) in that time. On February 1, prices for all 10 remaining 2017 futures contracts (from March to December 2017) carried $3 handles. Now, all but two contracts are below $3. Weather has been the primary driver of this shift. February 2017 is set to rank as the warmest February since 1970, after January 2017 also came in as one of the warmest in 40 years. Weather forecasts are also showing the warmth extending into March. These developments are signaling a more bearish 2017 than expected. Today, we continue our supply and demand update with a look at the 2017-to-date balance.

After ending 2016 on a bullish note, the U.S. natural gas market has been hammered so far in 2017 by relentlessly mild weather—January 2017 ranked as the fifth warmest in 40 years. The prompt CME/NYMEX Henry Hub futures contract, which had climbed to nearly $4.00/MMBtu by late December 2016, has come off more than $1.00 since then to settle at $2.834/MMBtu as of last Friday (February 17, 2017). With every balmy winter day that passes, the chances of sustained $3-$4 natural gas prices seem to be fading away. Nevertheless, there are still some bulls out there hanging on in hopes of a rebound. Prices are still well above year-ago levels and the underlying supply/demand balance continues to carry the implied potential for tightening if given even normal weather. In today’s blog, we provide an update of the gas supply/demand balance, starting with a recap of how we got here.

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.

The U.S. natural gas market in the past two years has undergone massive change, from breaking storage records and crossing long-held thresholds to flipping flow patterns and pricing relationships on their heads. This November, the market crossed yet another milestone:  the U.S. became a net exporter of natural gas for the first time ever on September 1, 2016. That lasted only a few days. But net exports resumed again starting November 1 and have continued through the month, almost without interruption, with pipeline deliveries to Mexico and to the first two liquefaction “trains” at Cheniere Energy’s Sabine Pass LNG terminal exceeding imports from Canada and LNG import terminals by an average 0.6 Bcf/d. Today, we look into what’s really driving this shift and what that tells us about the trend going forward.

<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.

On Friday (March 4, 2016) the April NYMEX/CME futures contract settled at $1.666/MMBtu, the lowest contract settlement since 1999. Rock bottom prices reflect a growing supply/demand imbalance and concerns about hitting storage capacity limits later this year. Last Thursday’s EIA report showed U.S. gas inventory stands 827 Bcf above last year at this time and 687 Bcf above the 5-year average. These are the biggest surpluses the market has seen since 2012. Moreover, our latest NATGAS Billboard storage outlook shows March withdrawals lagging way behind last year and expanding the surplus further heading into April. In today’s blog, we look at how a similar situation was resolved in 2012 and what it will take to bring down the surplus this year.