Last week, I delivered my major address on the future of natural gas. The occasion was a high-powered meeting hosted by Dominion Transport at the beautiful Nemacolin Woodlands Resort in western Pennsylvania.
In attendance were more than 100 leading CEOs and other executives from principal gas production, transmission, distribution, and end using companies.
My keynote presentation was entitled "Natural Gas Moving Forward: LNG, Hubs, and Pricing Prospects." In it I addressed where liquid natural gas (LNG) prices have been... where they are now... and where they're going.
I thought I would share my presentation with you in today's Money Morning, as it will be especially useful as we look for opportunities with investing in natural gas. Here's what I told my audience... the straight story on what's happening in the LNG sector...
Ten years ago next month, I was sitting in a meeting of analysts, practitioners, and energy sages discussing the condition of the U.S. natural gas market. We all agreed that by 2020 the country would be importing at least 15% of the gas used daily.
That turned out to be quite a "B.S." read - "before shale," that is.
Well, these days we are at another juncture. And this one is going to propel us into quite a different market. I want to lay out for you what I have been experiencing in the world energy market, the import of discussions around the globe, and the impact on things closer to home.
"Brave New World" is going to be an understatement. And that becomes clear when we sketch out the current and short-term projections for natural gas production and demand, along with the picture attending, expanding end uses for gas - electricity generation, industrial applications, for vehicle fuel, and as feeder stock for petrochemicals.
But first, let me outline the current domestic energy situation...
Natural gas inventory at the end of July came in 23% higher year on year (after two months of declines). That figure is estimated to reach 3.867 trillion cubic feet (tcf) by the end of October (and the end of the summer refill season) - 69 billion cubic feet (bcf) above the five-year average and the second highest on record.
2015 demand should end up at 76.5 bcf per day (bcf/d), or 27.9 tcf for the entire year. This is up 4.08% from 2014. Gas marketed production is expected to grow by an annual rate of 5.4% in 2015, to 78.72 bcf/d, and to rise 2.3% in 2016, to 80.52 bcf/d. That puts it at an estimated total of 28.7 tcf for 2015.
According to the Aug.14 figures from Baker Hughes, the natural gas rig count stands at 211, 52% down year on year and 87% down from the high-water mark of 1,606 in September 2008.
Of course, increasing efficiency in drilling and well services has been improving per well production while lowering costs. However, primary production from unconventional tight and shale plays are still coming in with primary production in the first 18 months or so while market considerations continue to put a restraint on rework and refracking options.
That is because of the price. The 2015 spot price should come in at an average of less than $3 per 1,000 cubic feet and below $4 in 2016 (my read is $3.25 by the end of second quarter 2016, $3.75 by end of year).
Nonetheless, there are some significant changes under way.
In addition to the traditional residential and commercial use of natural gas for heating purposes, there are five other expanding outlets for gas usage.
First, the most visible has been in the generation of electricity. Coal's power production share should be about 35.6% in 2015, down from 38.7% in 2014. Natural gas will come in at 31.2% for 2015, up from 27.4% in 2014.
Renewables will provide about 7% in 2015. But over half of new generating capacity coming on line this year is powered by renewables 55%, with almost all of the remainder (44%) using natural gas as the primary fuel.
Here's where it gets interesting. We are expected to replace 90 gigawatts of power production by 2020, all aging coal-fueled plants. As much as another 30 gigawatts would be impacted by EPA non-carbon limits (mercury, nitrous, and sulfurous oxide emission standards).
I initially estimated that each 10 gigawatts moved to natural gas would require 1 bcf/d more in supply. It is now coming in at closer to 1.2 bcf/d, with the transition showing a quicker upfront movement than I had initially anticipated. The slowdown over the past year, therefore, is simply a reflection of a higher front-loaded movement.
The bottom line is this. If only 75% of the replacement fuel sourcing moves to natural gas (and that would be giving renewables a decidedly bigger slice than anticipated), we require almost three times the current surplus inventory just for power generation, and even then for electricity that remains at today's levels.
Second, industrial usage is increasing again, with annual increases above 3% estimated for both 2015 and 2016.
Third, the move to LNG (liquefied natural gas) and CNG (compressed natural gas) for high-end truck traffic is just about completed in Canada and is moving forward in the United States. Transition of lighter truck traffic and a bridge to passenger vehicles will take longer, but municipal and bus usage has picked up with natural gas-powered and hybrid vehicles becoming emphasized (or in some cases mandated) for taxi fleets in several cities.
Fourth, and of greater impact, is the transition to natural gas and away from oil as feeder stock for petrochemicals. This makes the competition for new cracker facilities such a focal issue. There are seven major projects under consideration at the moment, with some smaller satellite units also possible. Of the main sites, three facilities are likely to be approved. Beaver County in western Pennsylvania should be one of the three, with the other two probably on the Gulf Coast.
This element alone will have a major impact both upstream and downstream, with the Marcellus occupying a main location for a broader gas footprint.
However, it is the fifth that comprises the most significant game changer we are going to be witnessing in our lifetimes. This refers to the massive transformation unfolding in the global LNG market.
LNG is natural gas cooled to a liquid state, moved by tanker, re-gasified on the receiving end, and then injected into existing pipeline networks for distribution. Because it relies less on pipelines, LNG is often more amenable to international trading than natural gas.
LNG global demand should reach 420 million tons a year (mt/y) by 2020, and 500 mt/y by 2025. Given that 1 billion cubic feet of natural gas translates into 21,000 tons of LNG, demand in 2020 should come in at an equivalent of around 20 trillion cubic feet a year (tcf/y). By 2025, it should move up to about 23.8 tcf/y.
On the other hand, global LNG projects on stream and in development amount to 677 mt/y, equivalent to 32.2 tcf/y. So something has to give. Obviously, not all of these projects will be completed.
The same is true of the U.S. market. Through last week, the federal government has approved 46 LNG export licenses for nations with which America has a free trade agreement (FTA), with another six pending, while 12 have been approved for any nation in the world not on a sanctions list (non FTA), with another 25 pending.
To date, 47.92 billion cubic feet per day (bcf/d) in FTA exports have been approved, translating into 17.5 tcf/y or 36.7 mt/y of LNG. The figures for non-FTA export capacity amount to 45.1 bcf/d, 16.46 tcf/y, and 34.6 mt/y.
These are non-additive figures and express LNG plant capacity, not in-hand contracts. So there is some duplication. Leading the list of companies having export permission are Cheniere Energy Inc. (NYSE: LNG), with permission for 5.68 bcf/d (2.1 tcf/y, 4.4 mt/y), and Freeport-McMoRan Inc. (NYSE: FCX), with 6.02 bcf/d (2.2 tcf/y; 4.6 mt/y).
Once again, these amounts are non-additive since they include combined FTA and non-FTA figures. In the case of FCX, there are separate petitions from Main Pass Energy Hub using the same facility capacity.
Dominion's Cove Point is in the mix for at least 1 bcf/d.
Not all of this export capacity will be utilized. Nonetheless, from nothing today, even Russian gas giant Gazprom (OTCMKTS ADR: OGZPY) is estimating that the United States could control 8% of the global export market by 2020. The flow of rising surplus shale/tight production will be moving internationally without having an appreciable impact on domestic pricing and zero effect on domestic availability.
Here's the biggest impact from all of this. It is going to be a world-changing scenario.
Global spot market purchases should account for 50% of total trade by 2020, up from 28% today. As LNG trade becomes a regular fixture, hubs worldwide will be established, with pricing having less to do with long-term pipeline contracts and more to do with 30-day or less one-time exchanges. The whole issue here is about guaranteed volume.
Four huge changes are underway on the global stage:
This last point is the main reason international LNG trade is so attractive. This morning, gas is priced at about $2.75 per 1,000 cubic feet at the NYSE pricing hub of Henry Hub in Louisiana. But it is the equivalent of $6.74 at the UK National Balancing Point, and more than $7.50 for Platts JKM (Japan Korea Marker, the main Asian benchmark). Arbitraging contracts and delivery points is going to make some people a lot of money.
And a major rise is transpiring in Mexican demand for U.S. pipelined natural gas as well as LNG. It's up more than 300% in less than three years and should reach 4.6 bcf/d by 2024.
Finally, I'd like to make some comments on hubs. LNG is going to provide the development of a genuine international trade in gas, with prices progressively separating from those for crude oil. Currently, main locations like Henry Hub and Baumgarten in Austria are the result of primary trunk pipeline interconnections.
Yet there are 22 main trading points in the United States, another three in Canada, and nearly 100 worldwide.
With LNG providing the rise of genuine spot markets and a wider array of pricing points, the importance will move from the impact of transit to the importance of usage. Henry Hub is already becoming less significant. For example, Dominion's South Point in western Pennsylvania already has more contracts.
From today's dependence on the intersection of main pipeline systems, hubs will be prioritized by two elements:
Please understand the importance of what we are rushing into: nothing less than the emergence of an integrated global natural gas market.
Years ago, I counseled North American producers that before too long, the volume they brought out of the ground in Texas, Arkansas, Pennsylvania, or Alberta would impact the price end users would pay for gas in places like Singapore.
That scenario is now playing out... quickly.
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