Henry Hub is the center of the natural gas spot-trading universe with virtually every btu being sold at a price linked in some way to this market center. Henry Hub is also the delivery point for the CME/NYMEX natural gas commodity futures contract that is now the third largest in the world. In the past 5 years the shale gas phenomena has revolutionized North American gas supplies and changed the shape of the traditional south to north producer to consumer delivery pattern. More changes are on the way. Today we continue our blog series by asking whether Henry Hub still holds its own as the CME delivery point.
Daily Energy Blog
Monday, 9/24/2012
US nitrogen based fertilizer prices are currently at record levels as a result of high demand from farmers. Farm demand for fertilizers is driven by crop prices. The Midwest drought this year has pushed corn prices through the roof, creating strong demand for fertilizer to improve crop yields. Nitrogen fertilizers are derived from ammonia – largely produced using natural gas. The current cost to produce ammonia from natural gas is about $98/ton. With farmers in Iowa paying over $800/ton for fertilizer this month producer margins are extremely attractive. One company is pushing a new “mobile” technology to make fertilizer from surplus natural gas in the Bakken. Today we look at fertilizer market fundamentals.
Sunday, 9/23/2012
The Henry Hub is the best known natural gas trading location in the world. There is certainly no more liquid point in the industry. An average of almost 400,000 natural gas futures contracts trade there each day. The Henry price is used to compute location ‘basis’ at all other natural gas trading points in North America and thus is the reference price for tens-of-thousands of derivative instruments and other commercial contracts. In effect, the Henry Hub is the center of the natural gas trading universe. What if I were to tell you that Henry Hub is not a hub? It is not all located at some single spot you can drive by called Henry. And the gas flow through this so called hub is minimal. Could this be another LIBOR scandal where a benchmark is not what we thought? Or is all well and good at Henry, regardless of these revelations? Let’s find out why Henry is the Hub, why it developed the way it did, and how changes in gas flows from the big shale plays could impact Henry in the future.
Wednesday, 9/12/2012
Nowadays everyone is pretty sure that there is plenty of natural gas supply to go around. Storage is bursting at the seams; production is close to record levels. Midstream infrastructure companies are busy developing new pipelines and additions to deliver shale gas to existing markets. Market analysts agree that new natural gas demand over the next decade will largely come from increased gas fired power generation. Is the current natural gas infrastructure configured to deliver gas to this new generation capacity? Today we report on emerging power industry planning concerns.
Tuesday, 8/28/2012
Understanding the natural gas market is not for the faint hearted. Natural gas production recently returned to record levels last seen before prices fell through the floor. How could that happen in the face of record storage levels? It’s all par for the course - in a world where the threat of a major Hurricane no longer impacts the price of natural gas (NYMEX Natural gas closed down 4 cents at $2.614 yesterday). Today we will look at buoyant natural gas production levels.
Wednesday, 8/22/2012
Plenty of new natural gas shale reserves have been discovered in Western Canada. In British Columbia (BC) there are four basins (Horn River, Montney, Liard and Cordova) with estimated reserves in place exceeding 1,200 Tcf. Drilling in these basins is constrained by low natural gas prices, limited infrastructure and lack of market demand. Before any of these shale plays can be developed fully, producers have to find new markets for their gas that can justify the investment.
Saturday, 8/11/2012
In August 2011 there were 900 rigs drilling for natural gas in the U.S. As of last week 405 gas rigs had disappeared and only 495 were left. As we all know, when gas prices fell, so did the natural gas rig count as producers moved capital budget dollars and rig crews to crude oil. That shift resulted in an astronomical increase in the crude oil rig count - from 1,050 this time last year to 1,432 today (Chart #1). But somehow the decline in the natural gas rig count has not translated into a decline in natural gas production. Very Strange. With shale gas wellhead production decline rates up to 80% in the first year, how is it that gas production has remained flat? Ghostly. When Halloween comes this year the 2012 natural gas production trend line will fall below the 2011 trend. What will that mean? Today, the 13th of August, we’ll look into the numbers to see how these spooky trends are likely to play out over the next few months.
Tuesday, 8/07/2012
September NYMEX natural gas closed up a nickel yesterday at $2.96/MMbtu. The January 2013 contract closed at $3.537 – a winter summer spread of $0.57/MMbtu, but the average seasonal spread in the futures market has fallen from $0.62/MMbtu just two years ago to $0.39/MMbtu this week. There was a time not that long ago when the winter-summer spread was measured in dollars. Now it seems to be fading into oblivion. Today we search for signs of seasonality in the forward curves.
Monday, 7/30/2012
Oil production from the North Dakota Bakken shale reached 639 Mb/d in May 2012. Associated natural gas production was 651 MMcf/d. So far oil production has been the main focus for Bakken producers. Gas production has been an afterthought. So much so that 1/3rd of it is flared. A new BENTEK study for North Dakota energy policymakers (we provide a link to the study) indicates natural gas volumes in the region will increase substantially in the coming years. The obvious market for this gas is to displace Canadian gas flowing through the Bakken to get to the Midwest. Today we look at the coming battle for pipeline capacity between producers in the Bakken and those in Canada.
Monday, 7/16/2012
A week or so ago in Part IV of the Marcellus Changes Everything series, we noted that by 2016 there would be a summer surplus of natural gas production from the Marcellus of around 3 Bcf/d. We pointed to Dominion’s Cove Point LNG proposed export terminal on the Chesapeake Bay as one likely outlet for the surplus. Dominion’s proposal is one of 14 LNG terminals being reviewed by the government for an export permit. Today we investigate how many of these terminals will be built and whether the natural gas markets sustain can such a high level of exports?
Wednesday, 7/11/2012
Today the Energy Information Administration (EIA) publishes weekly US natural gas storage numbers for the week ending July 6, 2012. Last week EIA reported 39 Bcf injections making the total storage 3,102 Bcf. The natural gas stockpile is now 602 Bcf higher than this time last year but the rate of storage injection has slowed as a result of increased demand for natural gas burn by power generators. In today’s blog we look at the supply demand picture to see what is driving higher natural gas burn by power generators and the implications for storage.
Sunday, 7/08/2012
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.
Thursday, 7/05/2012
In little more than two weeks, the CME/NYMEX prompt natural gas futures contract is up $0.76 to close at $2.945/MMbtu on Thursday (see graph below). That’s getting dangerously close to $3.00. Yesterday we noted that it was the drop below that $3.00 threshold that kicked off serious coal to gas switching in January. Now that the price is near to crossing the $3.00 mark the other way, we better look carefully at how plant fuel costs drive generation economics for natural gas versus coal. To do so we’ll take a deep dive into the math.
Wednesday, 7/04/2012
The coal to gas switching debate has been raging for months. How much is happening? How long will it last? Could switching continue to increase? Will the generators save the producers from themselves? So far this year, that latter assertion seems to be the case. Additions to natural gas power burn by electric generators have been about the only thing propping up natural gas prices. If the generators weren’t burning so much gas, the storage surplus would be through the roof. Last week EIA announced that natural gas matched coal’s share of U.S. generation for the first time in April. That’s a big deal. In today’s blog “Talkin bout My Generation – Coal to Gas Switching Part I” we uncover the drivers behind the shift to natural gas generation, and set the stage for a deep dive into the longer term implications for gas markets.
Monday, 7/02/2012
Over the past six months, natural gas production in the Marcellus has continued to ramp up, despite low gas prices and pipeline capacity constraints. It would have grown even faster if capacity had not held back well completions. But new pipeline capacity is coming, and as it comes on line, the production growth rate will accelerate. In the not too distant future, the Northeast will no longer need imports from Canada. Then imports from the Midwest will be backed out. And eventually all inflows from the U.S. Gulf region could come to a halt. That will be a vastly different gas market than we’ve known over the 25 years since decontrol. In today’s blog we’ll drill down into some of the important implications of this, the Great Flow Reversal of 2016.
