Monday, August 31, 2009
The NYMEX futures prices keep dropping too. The October contract, which was in the $3.18 range at the end of last week, dropped to $2.97. The December 2009 contract, which was holding on to $5 last week, closed at $4.83.
I don't expect to see any meaningful upward bumps in price until the storage injection season is over. Unless, of course, there is some good legislative news coming from Congress, but that will just be a news bump and not an increase based on industry fundamentals.
Last week's gas in storage figure of 3,258 Bcf implies that we are at 84% of capacity (of the conservative number). This, however, is not a precise calculation because much of the gas is stored in old salt domes and tapped out wells as opposed to easily measurable tanks, so it's difficult to know the exact storage capacity.
While 84% of capacity doesn't sound bad, early fall is a low consumption period and is the storage "injection season" for winter, so the market typically expects lots of gas to go into storage at this time of year. It's going to be a bumpy ride for gas prices until the end of October.
Sunday, August 30, 2009
The article makes the point that tax credits for purchase of natural gas vehicles might be better used by commercial fleet vehicles ($64K/vehicle) than regular autos ($12.5K/vehicle). It aslo points out the $100K tax credit for anyone opening a natgas filling station. What it doesn't point out is that it would be relatively easy to open a natgas filling station because the distribution systems for natural gas are mostly in place in most metropolitan areas.
The article points out that, while there is only one CNG model available in the U.S. - the Honda Civic GX - there are a copule of dozen available overseas. The article has a couple of links to learn more:
The article makes a lot of good points (all made before), but it's nice to see that natural gas as a vehicle fuel discussed in new (and well-read) venue.
Saturday, August 29, 2009
I noted the following recent Haynesville/Bossier Shale completions in East Texas:
- Charlie Bell Gas Unit No. 2 #1H, Forest Oil Corp: 1.431 MMcf/day on a 24/64” choke; North Carthage Field, Harrison Co. (Bossier Shale)
- Cox “H” #1H, Comstock Oil & Gas: 8.344 MMcf/day on a 26/64” choke; North Carthage Field, Harrison Co. (Bossier Shale)
- Blackstone #1, Forest Oil Corp: 0.102 MMcf/day on an 18/64” choke; North Carthage Field, Marion Co. (Bossier Shale)
- C.M. Abney “B” #22, Devon Energy: 1.684 MMcf/day on an adjustable choke; Waskom Field, Harrison Co. (this was noted in the Haynesville formation, but it did not specify shale or lime, so I’m not entirely sure how to properly classify it at this point)
- Bartley GU #3H, NFR Energy: 2.697 MMcf/day on a 20/64” choke; North Carthage Field, Harrison Co. (Bosssier Shale)
- Smith-Bird Unit Well #20H, Devon Energy: 3.695 MMcf/day on an adjustable choke; North Carthage Field, Panola Co. (Bossier Shale)
Friday, August 28, 2009
The article notes that part of this expected increase will come from raw materials since commodity prices have pretty much hit bottom. There have been positive indications of late for the energy services sector as rig counts continue to rise, albeit slowly. At least on the gas drilling side (representing 70% of the rigs in the U.S.), however, I would think that it might be hard to raise prices for a few months. As long as companies are reigning in production in response to an over-supplied and under-priced market, service companies are going to be fighting each other for business and will have a hard time raising prices.
In the Haynesville Shale region of northeast Texas and north Louisiana (which includes a few other plays), the rig count was down by two to 137. The count was down by two in Texas and held steady in Louisiana.
UNG is a way for individual investors to buy exposure to natural gas prices. Sounds like a great idea. To accomplish this goal, the fund has to buy natural gas or a related financial instrument to be able to track the price of natural gas. In this case, the fund buys futures and swap contracts on natural gas in the near month. But because of a recent flood of investors seeking to take advantage of the expected increase in gas prices, the fund has gotten too big to work properly. (It might also run afoul of certain trading restrictions that are being considered by the government, although that is not addressed in the article).
UNG has been under pressure all summer. The fund applied to the government to be able to issue new shares because it had used its allotment with the flood of new investors, but after receiving permission it decided to hold off on issuing new shares until it can work out other mechanical problems. As a result of its problems, the fund no longer accurately tracks natural gas and trades at a 16.5% premium to its net asset value. It also still owns half of the action in the gas futures market, and because its month-end trades where it has to roll into the next batch of contracts are no secret, independent traders swarm like roaches to make their own arbitrage trades to take advantage of UNG (I call them "roaches" with some admiration).
The article doesn't cover all of the woes of the fund, but it does give a pretty good overview of the jam in which the fund finds itself. Much has been said about the UNG situation over the past few months, but I thought the TIME article was one of the few that was not burdened by excessive finance-speak.
Thursday, August 27, 2009
The article has an thematic undercurrent that the inability for new biofuel projects to get funded somehow "threatens the green revolution." I think that is hogwash. Biofuels hardly represent the green energy revolution. They are a politically expedient way to win votes in the agricultural heartland. It falls under the category of, "it sounded good at the time." The notion that we can grow our way to energy independence using our foodstock is rather silly. But worse, it distracts decisionmakers from finding real solutions.
The biofuel industry as a whole requires government subsidies to be financially viable. In 2007 it received subsidies and support of $3.25 billion, more than any other energy source. According to the article, if you take all of the U.S. supply of vegetable oils and animal fats to make biodiesel, it would only amout to approximately 7% of U.S. diesel demand. That's not a solution, that's an annoyance. But that doesn't stop the industry's lobbyists who are trying to extend subsidies and increase the blending percentages.
Biofuels might be able to be a small part of a larger energy portfolio, but the notion that we can farm our way to energy independence is a tale best told by well paid lobbyists to politicians eager for votes.
Interestingly, the article is from the English daily in Qatar, the nation that is producing the LNG that is supposed to swamp the U.S. any day now. Hopefully Qataris will get the message and divert LNG elsewhere (if there's room) or just dial production and export back a bit until the market picks back up.
The weekly injection into gas storage was 56 Bcf, which was 4 Bcf more than last week. But since this is the "injection season," the weekly number was actually lower than the five year average number for this time of year (67 Bcf) and quite a bit lower than this week last year (100 Bcf). The current storage level of is about seven weeks ahead of the five year average and is on track to break the record of 3,565 Bcf set in late October 2007. As the chart below shows, storage is especially high in the producing regions (+33.5% over five year average) compared to the East Region (+9.7% over five year average) where much consumption takes place.
The second half of October and the return of cold weather marks the end of the injection season, so hold on tight for a bumpy ride until then.
Pricing continues to suck wind. The spot and near month futures prices both fell below $3.00 last week and don't seem to be in a hurry to go back up. As noted before, the spread between oil and gas prices on a per Btu basis continues its wide divergence (watch the dotted black line on the chart below continue to flutter away - in a perfect world it should be close to the red and blue lines). This divergence is causing tongues to wag in investment circles as everyone tries to formulate an investment to play the spread. As I've noted before, they are similar fuels but don't trade on similar fundamentals at this point, so while gas prices will eventually move higher and oil prices might sink, there really isn't a fundamenal arbitrage play here. Not that I'm offering investment advice. The best advice I can offer is not to listen to me.
The storage capacity increase came from expanding existing caverns and adding new facilities. One of the issues the article points out is that the location of the facilities is important. Storage in the ten southern producing states is at 94% capacity. If the excess storage capacity is on the other side of the country, there might be a transportation issue.
100 billion cubic feet sounds like a lot, but when you realize that over the past two weeks 106 Bcf was injected into storage, it sounds like a lot less.
This week's storage injection was 54 Bcf. But this is the traditional storage injection period, so the amount in storage this week versus the five year average actually delcined to 18.8% vs. 21.3% last week. Not exactly good news, but it's less bad.
Wednesday, August 26, 2009
- Dean 17 #1, J-W Operating Co.: 5.600 MMcf/day on 24/64” choke at 1,500 psi; completed 4/29/09, Elm Grove Field, Caddo Parish; Sec 17/Township 16/Range 13, Haynesville reservoir A, serial #238660
- BSCMC LA 12 HZ #1, Comstock Oil & Gas: 11.242 MMcf/day on 28/64” choke at 5,550 psi; completed 4/28/09, Benson Field, DeSoto Parish, S12/T10/R15, non-unit, serial #238212
- Jackson Davis 35H #1, EnCana: 6.022 MMcf/day on 13/64” choke at 8,225 psi; completed 7/1/09, Caspiana Field, DeSoto Parish, S26/T15/R14, Haynesville res. A, serial #239536
- DeSoto Oil & Gas Trust 17 #1, Beusa Energy: 3.009 MMcf/day on 8/64” choke at 5,250 psi; completed 4/8/09, North Grand Cane Field, DeSoto Parish, S17/T12/R14, non-unit, serial #237650
- Thompson 11 #1, EOG Resources: 13.643 MMcf/day on 30/64” choke at 4,000 psi; completed 2/4/09, Trenton Field, DeSoto Parish, S11/T11/R13, Haynesville res. A, serial #239415
- Joseph Bolan 34H #1, EnCana: 7.695 MMcf/day on 11/64” choke at 7,489 psi; completed 5/24/09, Red River-Bull Bayou Field, Red River Parish, S34/T14/R11, Haynesville res. D, serial #239056
Given the over-supplied and under-priced natgas environment, this curtailment probably won't be the last we hear of before winter, voluntary or not.
Tuesday, August 25, 2009
While the article is clear that the solar steam plant would displace natural gas, I still think it's a cool use of technology. BrightSource and other competitors are targeting similar oil field projects elsewhere, including the Middle East (lots of sun, but lots of cheap gas too). As a competitor to natural gas for this function, the article cites a report that states that solar steam systems would be competitive against natural gas up to a natgas price of $8.50/MMBtu.
Hopefully the company won't take its eye off the big ball, which is large scale power generation, preferably to displace dirty coal plants.
While this article paints the solar steam technology as a viable energy source, it also points out that because it only works during the daytime, the oil field will still need a natural gas-fired steam source too. While this type of project has the potential to displace natural gas, the truth is that its viability actually depends on natural gas as a backup fuel. Ultimately, the success of renewables and alternative energy is dependent on the use of clean burning and amply supplied natural gas, both as "a bridge to the future" and as a backup energy source.
One of the most interesting points is that the strategy of buying production or creating a joint venture is likely a technique that will be repeated rather than straight acquisitions or mergers. The acquisition of Burlington Resources by Conoco a few years ago left Conoco with huge financial and accounting burdens, from which it is still trying to extricate itself. The energy industry watched the aftermath of that deal closely with a "there but for the grace of God go I" feeling. The new transaction strategy, largely pioneered by Chesapeake, provides access to the resources and the technology behind its extraction without the accounting and management burdens of typical M&A deals.
Which leads to the second point: using the gas shale techniques that are being developed in the U.S. could potentially quadrouple the gas resource in the world, says energy industry consultant PFC Energy. It's no secret that the gas is out there. The question has always been, how do we get it economically?
The next few years are going to be exciting in the energy industry. Natural gas will become a more abundant resource all over the world, and I think this change will lead to significant geopolitical changes down the road. But the big point that the blog post makes at the end is that those who take the plunge into shale gas now will be the winners down the road. Chesapeake is likely to make another big JV deal before the end of the year. The question is which major, from which country will be the partner?
Monday, August 24, 2009
Today, the Henry Hub spot price decreased another 3.2% to $2.69. This is the lowest price in a long time - at least seven years. I'll let the news media give you the "lowest price since XXXX" story since that is more sensational. Better news is that the near month futures price (in this case gas for September delivery) increased 5.3% to $2.95. It's a sad day when a natgas price below $3 is good news.
- Anthony Forest Products 28 #1, Chesapeake Operating: 8.899 MMcf/day on 14/64” choke at 6,418 psi; Bethany Longstreet Field, Caddo Parish; Sec. 28/Township 15/Range 16, Haynesville reservoir A, serial #239454
- Lee 16H #1, Chesapeake Operating: 9.863 MMcf/day on 22/64” choke at 4,250 psi; Bethany Longstreet Field, Caddo Parish; S16/T15/R16, Haynesville res. A, serial #238640
- Blackstone ETAL 31H #1, Chesapeake Operating: 5.279 MMcf/day on 18/64” choke at 4,241 psi; Spider Field, DeSoto Parish; S31/T11/R14, Haynesville res. A, serial #239119
- Conway Harris 22H #1, EnCana Oil & Gas: 18.427 MMcf/day on 21/64” choke at 8,335 psi; Red River Parish; S22/T14/R11, Haynesville res. D, serial #239250
- Joseph A. Dill 33H #1, EnCana Oil & Gas: 8.902 MMcf/day on 18/64” choke at 7,569 psi; Red River-Bull Bayou Field, Red River Parish; S33/T14/R11, Haynesville res. D, serial #239038
- Sample ETAL 8 #1, Petrohawk Operating: 22.071 MMcf/day on 24/64” choke at 7,951 psi; Thorn Lake Field, Red River Parish; S8/T14/R11, Haynesville res. A, serial #239051
- Rex Young 6H #1, Questar: 25.507 MMcf/day on 28/64” choke at 7,700 psi; Thorn Lake Field, Red River Parish; S6/T14/R11, Haynesville res. A, serial #239383
- Charlie Bell Gas Unit 2 #1H, Forest Oil: 1.431 MMcf/day on a 24/64” choke; North Carthage Field, Harrison Co.; Bossier Shale
- Cox H #1H, Comstock Oil & Gas: 8.344 MMcf/day on 26/64” choke; North Carthage Field, Harrison Co.; Bossier Shale
- C.M. Abney B #22H, Devon Energy: 1.684 MMcf/day on an adjustable choke; Waskom Field, Harrison Co.; Haynesville (I assume it’s the shale and not the lime, given the 15,214 total feet)
- Blackstone 1, Forest Oil: 0.102 MMcf/day on an 18/64” choke; North Carthage Field, Marion, Co.; Bossier Shale (given its depth of 11,020, I assume it is a vertical well)
Saturday, August 22, 2009
American Exploration Corp. is a thinly traded over-the-counter stock that commenced operations in 2008. The company plans to explore in the U.S. but is a Calgary-based company. Its strategy is to target opportunities in the interior salt basins of the Gulf Coast Region to find characteristics similar to those of the Haynesville Shale.
Jefferson County is in the southwest portion of the state, bordering the Louisiana. According to company materials, the prospect is 2,500 feet thick (the Haynesville Shale is between 150 and 300 feet). The company wasn't very clear on it, but it appears that the prospect is between 18,000 and 19,500 feet deep (the Haynesville Shale in NW LA is +/- 11,250 feet deep), which means that drilling costs and complexity likely would be higher than in LA/TX.
Earlier this summer, Mainland Resources announced a lease nearby in Mississippi for the same purpose. Interestingly, Mike Newport, CEO of Mainland, is a technical adviser to American Exploration.
I'm not sure what either company will find, but godspeed to them both. It would be further proof that North America is awash in natural gas.
Friday, August 21, 2009
Everyone is looking at the same data: natgas consumption is down, surplus storage is filling up and production keeps increasing. Experts are waiting for the storage to be full and the pipelines backed up. That's about the only way to get the producers to stop pumping gas. Since many producers are hedged at $6 to $7, they aren't feeling the pain the way the guys at the wellhead feel it.
Analysts are talking about spot gas at $2.25 to $2.5o in September. The December futures contract has fallen to $5.03, down from $6 recently, so much of the optimism about the ship righting itself before the end of the year is fading.
It got so bad today that the ratio between oil and natural gas got to 25x (oil had an OK day). the 19 year average is around 9.35x, as shown on the graph below from an article by CNBC (the graph is sort of useless because there are no X axis labels, but I believe it's a date range from 1990 to the present). I've already stated my belief that oil and gas now trade independently so the growing gap in this ratio will not force gas prices to rise or oil prices to fall, but it's interesting to see the divergence.
The article cites a very interesting report by investment banking firm Tudor Pickering and Holt that focuses on wind power in Texas. The report is a good read , and it helps laypeople like me understand the mechanics of incorporating wind power into the electricity grid (it's in presentation format but it actually is approachable and reads well -if you don't think stock analysts have a sense of humor check out the icon for nuclear power on page 9).
The conclusion of the report is a little scary for gas fans. The bottom line is that wind powered generation is going to cut into gas powered generation rather significantly. The report assumes wind would replace gas 75% of the time, which could lead to a reduction of between 0.5 and 0.6 Bcf/day of natural gas use in the state of Texas. Currently the state uses around 3.2 Bcf/day, a figure expected to rise to 3.3 Bcf/day over the next few years, so that would be a big drop.
One thing to remember, however, is that the report was written based on the current economics for power generation. In other words, there is no economic cost for externalities like pollution or carbon generation.
Two pie charts from the TPH report, shown below, jumped out at me. They show that natural gas represents 65% of the installed capacity in Texas, but in 2008 it only generated 43% of the state's energy (ERCOT stands for Electric Reliability Council of Texas, which is the name of the electricity grid that covers most of the state). Coal, which represents 16% of the installed capacity, generated 37% of the state's electricity. The bar chart below shows that Texas is "gassy" compared to the rest of the country, but there is still more natural gas installed capacity than coal installed capacity in the U.S. (around 40% for natgas vs. 30% for coal). Clearly, the U.S. has unused natural gas power generating capacity. It would cost very little to start burning more gas and less coal. We wouldn't have to build new plants as the coal lobby suggests.
I realize that the two fuels are functionally different and often serve different uses for utilities. For instance, because natgas plants can start up quickly they will always be favored for peak demand. But I don't think wind will spell doom for gas just yet. Ultimately the real contest is still gas vs. coal.
In the Haynesville Shale area (which includes other formations), the rig count increased by three to 139. The three rig increase was in East Texas, while the figure was unchanged in Louisiana.
Thursday, August 20, 2009
There was a good piece in the Wall Street Journal on the subject (link should be good for seven days). Not a ton of new information but the article points out that the oxymoron "clean coal" research gets high billing. I'm all in favor of cleaning up coal, but the best way to do it is to stop burning it. "Clean coal" is a farce.
The natural gas folks underestimated the strength of the coal lobby. As natural gas lobbyists spread the "clean and abundant" message, I wonder if the coal folks will help gang up on foreign oil and get on the bandwagon to push natgas for transportation as a defensive move to keep gas out of the power plants. This is just my speculation, but we've seen strange bedfellows before.
The coal folks are fighting for their lives and are using every arrow in the quiver. Cost of coal vs. gas is the one they tend to focus on. But coal is going to be waging its own cost/supply battles in the years to come. Let's all say it, "PEAK COAL." I can't resist.
What scares traders and producers is the chart below showing working gas in underground storage. The red line is the actual gas in storage and the shaded band is the five year rolling average. The red line busted through the band a couple of months ago and is not likely to go back inside for a while. That's the unhappy sign of oversupply.
- Headrick HZ #1, Comstock Oil and Gas: 14.804 MMcf/day on 26/64" choke at 5300 psi; completed 3/29/09, Bethany Longstreet Field, DeSoto Parish; Sec. 14/Township 13/Range 16, Haynesville reservoir A; serial #238715.
Another takeaway point of the article (although unstated) is the decreasing importance of hurricanes to natural gas prices. Since most of the new gas production is inland, Gulf of Mexico storms will not significantly interrupt natural gas flows. A very large percentage of our nation's oil, however, still comes from the Gulf, and an even larger percentage of our refining capacity is within 100 miles of the coastline, so our national energy security is still in danger. Just not so much natural gas.
Tuesday, August 18, 2009
It appears that GMX is adjusting its well economics to use a higher production profile for its Haynesville Shale wells. As the two charts below illustrate, the newer profile is for a 6.5 EUR well versus the previous 5.4 EUR well. The company has found success with longer laterals with greater fracture stimulation events and is seeing higher initial production rates. The purple line on the charts indicate the expected production over ten years from a Haynesville well, which is more than double those in the Fayetteville and Barnett shales.
I tend to be a graphic person who sees more in an illustration than on a chart of numbers, so I found that the following three maps that the company provided did a great job of illustrating the progress of the Haynesville Shale to date. The first map shows GMX's interpretation of where the core area lies (and where the company has leases). The second map overlays color coded initial production rates, and the third generally shows where the producing companies are represented.
"Natural gas industry" doesn't quite roll off the tongue as easily as "oil and gas industry" but we should all get used to saying it. Next step is finding a word to replace "oilfield" and "oilpatch." "Gasfield" and "gaspatch" just don't sound right.
Cheniere Energy, which is a developer and owner of LNG ports in south Texas and Louisiana, has some interesting information in its recent investor materials that help Regular Bobs like me understand the LNG industry. The basic premise behind LNG is to convert natural gas, which is only feasible to transport in its natural state in pipelines, to a liquid state that is easier to transport to allow for shipment all over the globe. LNG allows the natural gas market to become more like that for oil.
To grossly simplify things, natural gas is piped from the production fields to a facility where it is supercooled through a process called liquefaction and loaded on monster tankers to be shipped all over the world. Once it gets to a destination, it is offloaded, regassified, stored and then transported to the end user. It all sounds very simple, but it is extremely expensive to build the liquefaction and regassification plants along with the additional storage facilities and many new pipelines. Over the past decade, huge amounts of capital have been invested to make the LNG market a reality. Massive facilities have been built and much new liquefaction capacity will be coming online for the next few years, as shown on the chart below from Cheniere. It is staggering.
list of OECD nations).
Until the shale boom of 2008, conventional wisdom in the U.S. held that natural gas was a limited resource worldwide and it would have to be imported, much like oil, because we would surely run out of the stuff. For the past decade, there was a boom of developing these expensive ports to receive, regassify, store and ultimately transport LNG all over the country. The U.S., while a fairly minor player on the LNG consumption side, has one of the world's largest natgas storage networks. As a result, when gas is stacked up elsewhere, it can usually find a home in a tank on our shores.
Given the explosion in domestic drilling that has led to huge increases in U.S. natgas supply, producers cast a wary eye towards LNG. At the same time, investors who have funded these massive port projects get a queasy feeling looking at the new shale finds. So far, the ports are seeing fewer cargoes than expected.
The slide below is very interesting because it shows the worldwide quantities and flows of LNG. The "nameplate capacity" is approximately 37 Bcf/day (blue boxes below), but assuming lower utilization rates, there is approximately 30 Bcf/day of available LNG in the world. Current consumption outside of North America (green boxes) is +/-26 Bcf, which implies that there could between 4 and 11 Bcf/day available to the Americas. Right now North America is importing about 2.5 Bcf/day. Given the number of proposed and under construction projects (yellow and green dots), that potential overcapacity isn't likely to decrease any time soon.
I was pleased to see news that China might be normalizing its domestic natural gas prices to make imports from pipelines and LNG more attractive. Combined with greater investment in gas power generation, China could become the destination for much of that excess LNG.
One advantage of LNG is that it makes natural gas more of a worldwide commodity, available to those without direct pipeline access. It also acts as a mechanism to redistribute excess supply. While I fear the excess supply arriving on our shores, theoretically supply will follow the highest prices and not just be forced to find the last open parking place in the lot. Since prices for gas are much higher in Europe and Asia, don't expect much LNG to come to the U.S. except to be dumped (which is, of course, the worst case scenario for domestically produced gas).
As countries all over the world come to appreciate the benefits of natural gas, I am of the belief that in a normalized worldwide economy a happy medium will be achieved where LNG is able to find a home at a decent price and will not be a long-term source of anxiety for U.S. natgas producers. My short-term outlook, however, is not as bright.
Monday, August 17, 2009
Fake grass roots groups are being formed now to rally, misinform and infuriate the troops to disrupt the climate and energy debate this fall. Let's only hope both sides are equally well funded so they can just shout at each other in front of eager cameramen outside the decision-making venues. Hopefully, unlike reality television, this angry, misinformed mob strategy just a fad political tactic that will just fade away quickly, leaving only the faint taste of burned rubber in our mouths.
The prime concept behind the paper is that because shale is now a commercially viable source, North America has an abundance of natural gas, a message that is only starting to filter down to decision makers and the general population. The paper is wide in its breadth. While it primarily advocates for the use of natural gas as a bridge fuel until the next generation of clean, efficient fuel is commercially viable, it also advocates greater study into the impacts of natgas and for improved technology for carbon sequestration and the like.
Some of the proposals might meet with controversy, but this report helps push the proverbial ball forward. Gas is abundant, clean and domestically produced, thereby creating jobs at home and lessening our dependence on foreign countries. It's a win-win-win for the U.S.
Much of China's natural gas is produced domestically but it is starting to receive shipments from Turkmenistan via PetroChina's Pan-Central Asia pipeline project and from LNG imports. Wellhead prices in China are on par with those in the U.S. but are about half those of imported gas. While China is unlikely to allow free market pricing, the goal of increasing wellhead costs is to normalize the price difference between the domestic and imported gas.
The price increase will improve profitability for domestic producers and make the imported gas more appealing. While there will be some pain for gas users, the timing for the change seems good. Because China's economy is improving and natgas prices are currently very low, a price increase won't drastically harm users.
Ultimately, the goal is to increase the use of natural gas because it burns cleaner and will lessen China from some of the political issues associated with importing oil. Does any of this sound familiar? China is seldom the first nation to think and act progressively, but when it does take a step in the right direction, it usually does it in a big way.
On a side note: a price change in China should make it a more attractive LNG destination, and I'm certainly in favor of anything that prevents LNG dumping on U.S. shores.
Sunday, August 16, 2009
Much has been said about the federal stimulus program, but to me this is a win-win project for all involved. Shreveport gets new infrastructure, a new CNG public transportation project is implemented (a cheaper and more environmentally friendly fuel), and Shreveport area residents won't have to smell more stinky diesel buses.
- Marvin Gulley #21H, XTO Energy: 2.957 MMcf/day on 18/64” choke; North Carthage Field, Panola Co. (Bossier Shale)
- Mohon GU #13H, NFR Energy: 6.41 MMcf/day on 23/64" choke: North Carthage Field, Harrison Co. (Bossier Shale)
Friday, August 14, 2009
There is much speculation, especially from financial types, that natgas prices will be in the $6/MMBtu range by the end of 2009. This is based on everything from the price of futures contracts, the relationship between natgas and oil prices and the expected reduction of natgas production (mostly because of decreased rig counts). A year ago I would have been disappointed by $6 but at the current price of below $3.50, but...
This week's Energy Information Agency data came out and showed the total amount of gas in storage increase to 3.152 trillion cubic feet, 19.6% above the five-year average and 23.1% above last year's level. The price chart, below, shows that natgas prices have been steady for quite a while. It also shows that the oil price equivalent per MMbtu is now triple that of natural gas. The second table shows wellhead prices over the past six months.
Much has been said about the growing spread in the ratio between gas and oil prices, and many people believe that this divergence will cause natgas prices to increase to correct the gap. Looking at it as an outsider, however, I believe that reasoning behind this suggestion is faulty. The basic assumption by many is that the prices will move back together to harmonize with long-term historical trends, but I believe that the relationship between the two commodities is much more complicated than that in the short-term. The drivers of the two commodities are different, and the global economic downturn has exacerbated these disparities.
Oil and natural gas have different basic uses: oil mostly is a transportation fuel, while natgas powers electrical plants, industry and homes. Therefore in practical application they are not readily substitutable. If oil prices spike, we can't flip a switch and use natgas to power our cars (until T. Boone Pickens gets his way). Oil is a worldwide commodity and is shipped all over the globe from a few dominant sources. Because it is mostly transported by pipeline, gas tends to be a regional fuel with regional pricing dynamics. LNG tankers will help spread the fuel to a greater audience, but that doesn't change the fact that in the U.S. natural gas is mostly a domestic product (remember I'm only concerned with U.S. wellhead prices).
Because of the North American supply/demand dynamics and the fact that natgas is not readily substitutable with oil, I believe the price of gas is independent from that of oil and its short-term recovery is almost entirely dependent on the improvement of the U.S. economy. It will not be a self-healing situation to catch up to the price of oil. Sure, hurricanes and the actions of commodities and futures traders will make an impact, but the economy is the fundamental driver. Almost everything else is noise.
In the Haynesville region of North Louisiana and East Texas, the count also increased by two, one each in TX and LA.
The Economist is a highly respected no nonsense British journal that is long on facts and short on ads. It's a great magazine ... if you have time to read it. But make time to read this article - it's very short by Economist standards - and share it with your friends.
Thursday, August 13, 2009
• Midyett-Gulley 12H: 6.5 MMcf/day, North Carthage Field, Harrison Co., TX
• New Horizons 7H: 6.9 MMcf/day, North Carthage Field, Harrison Co., TX
- Elva 25, Chesapeake Energy: 10.071 MMcf/day at 6,756 psi; Lake Bisteneau Field, Bienville Parish; Section 25/Range 16/Township 10, Haynesville reservoir A, serial #239490
- CLD 23H, Chesapeake: 12.693 MMcf/day on 20/64” choke at 6,581 psi; Caspiana Field, Caddo Parish; S23/R15/T12, Haynesville res. B, serial #237856
- Holmes A H2, Comstock Resources: 16.203 MMcf/day at 5,050 psi; Belle Bower Field, DeSoto Parish; S20/R13/T16, no Haynesville unit, serial #238961
- Martinez 14H, Chesapeake: 4.251 MMcf/day on 22/64” choke at 4,650 psi; Logansport Field, DeSoto Parish; S14/R11/T15, Haynesville res. A, serial #239259
- Elmwood Land Co. 33H, EnCana Corp.: 10.011 MMcf/day on 21/64” choke at 4,891 psi; Bracky Branch Field, Red River Parish; S33/R13/T9, Haynesville res. B, Serial #238485
- Black Stone Mins Co. 13H, EnCana: 10.674 MMcf/day on 17/64” choke at 8,250 psi: Bracky Branch Field, Red River Parish; S13/R13/T10, Haynesville res. B, serial #238493
I think Mr. Huntsman should be heartily congratulated for his progressive thinking and for his use of natural gas in energy policy. Unfortunately/fortunately he is now the U.S. Ambassador to China. Maybe he can bring natural gas enlightenment to China, as that nation certainly can use it.
Crimson is the former GulfWest Energy. It has a private equity sponsor, Oaktree Capital Management, but it is a public company that is traded over the counter. The company acquired 11,500 acres in the Haynesville Shale in 2008 from Smith Production. The acreage is in Shelby, San Augustine and Sabine Counties, TX. The land is also prospective for the James Lime, Mid-Bossier and other plays. The company believes its Haynesville property has 200 potential drill sites.
While the company is relatively small, it has operations in a number of fields in Texas and Louisiana, but I think it smells a big opportunity with the Haynesville Shale. Crimson's Haynesville reserve is three times larger than that of any of its other fields. The company hasn't invested much capital this year (the capex budget for 2009 is $17.5 million, but 40% is allocated to the Haynesville Play), but that may be a factor of commodity prices and market conditions. But given the company's small size it might depend on partnering with larger companies to drill the shale, as 200 wells at current Haynesville economics implies well costs of greater than $1.6 billion.
In any case, we'll keep our eyes open for results from Crimson's first well in the 4th quarter.
Wednesday, August 12, 2009
These strong results are mostly a result of EnCana changing its completion program from eight fracture intervals to 12 to 14. As a result, the company talked about shifting its estimated ultimate reserves (EUR) model from 6 Bcf to 9 Bcf (!!!). The company only has data on three to four wells at this time, so they haven't settled on anything yet, but that's a big change. Well costs are around $9 million, but the company hopes to see that slip into the $8.0 to $8.5 million range.
EnCana will probably be able to provide some data on its foray into the Mid-Bossier Shale (above the Haynesville) in its third quarter (November) earnings report.
EnCana is starting to take more of a leadership role in promoting the use of natural gas in North America. As Canada's leading producer, this is not a surprise - the only surprise for any of these companies is why they waited so long. There were two slides in EnCana's recent investor presentation that addressed increasing the use of natural gas in both the transportation and electric generation fields. The two slides below summarize the environmental impacts of introducing 25 Bcf/day into each use. The bigger environmental gain comes from increasing the use of gas in power generation (second slide). But the bigger political gain, which is not specifically addressed in the first slide comes from decreasing the use of foreign oil in transportation. The slide assumes that natural gas is substituted for foreign, or "off continent," oil. It's nice to see that dark red pie slice shrink.
In any case, the article is interesting and it shows that natural gas is finally getting the right kind of national press. The article's conclusion: using natural gas rather than coal for electrical generation is the fastest, cheapest and most effective way to lower our carbon footprint.
Even more interesting, perhaps, is the history and economics of Exxon's huge gas field and LNG operation in Qatar. Exxon has invested $30 billion in developing the North Field in Qatar, which contains 900 Tcf of gas, and four gigantic gas liquefaction plants. The economics are shockingly good because while liquefaction is expensive, the gas is not that expensive to produce and the gas is "wet" and therefore provides billions of dollars worth of propane and butane that subsidize the gas. The net result is that Exxon can put out 1.6 Tcf per year of LNG and have the pricing power to be able to undercut anyone anywhere on the planet. One shipment of Qatari LNG on one of Exxon's specially designed gigantic tankers equals one twelfth of the U.S. daily supply of gas.
I've been critical of Exxon's long history of dismissing natural gas, but the company is a savvy political and business player. They have no love of natural gas (or the environment), but they see oil as a limited resource (company oil production is down 12% over the past three years) and an opportunity in natural gas. When a company as smart and strong as Exxon sees the opportunity, they line up the ball, pour billions of dollars behind it and hit it right down the middle of the fairway. Putting it another way, Exxon might be the last one to board the boat but there is little doubt the company is going to take the captain's wheel once they do board.
I'll have more to say later this week about LNG, but this is a good, quick primer on the subject.
Tuesday, August 11, 2009
Of course, the discovery seems to be purely political. The key people in question are senators representing swing votes in the energy legislation, many of whom happen to come from emerging shale gas states like Pennsylvania, Louisiana, Michigan, Arkansas, Kentucky, Texas and Oklahoma. Other swing votes come from Colorado and North Dakota, two more states that benefit from domestic drilling.
But the two biggest obstacles to shale gas being a game changer in the energy legislation are 1) its newness and the unknowns that come with new discoveries and 2) the powerful, rich and deeply entrenched coal lobby, which overlaps many shale states, especially in the Appalachian Marcellus Shale. In total, the coal lobby influence reaches into more than 20 states.
Between its new lobbying effort and the growing awareness of the shale gas discoveries, the natural gas industry will finally have a seat at the table in Washington. It is still an uphill fight, but the fight is on
P.S. Kudos to both Colorado senators, Mark Udall and Michael Bennett, who are working hard to keep natural gas on the proverbial front burner in the energy debate.
Always fun is Regency's map of key Haynesville and Bossier completions. Given the prolific nature of many Haynesville wells and the fact that the regional rig count continues to rise (or at least remain steady), Regency is very excited to get their new project online. Please note that this map is one of the few that delineates the Bossier Shale (in pink).
In reading through Regency's earnings call transcript, I couldn't help but to think about where pipeline companies stand vis-a-vis the expected impact of the 50% decrease in working rigs over the past 12 months. I've mentioned before that pipeline companies are quick to point out in times of decreasing commodity prices that their business is based on volume and throughput, not prices. Given the prolific nature of shale plays, these companies have to be salivating because they get to do their two favorite things: 1) transport lots of gas and 2) build new pipelines. But if the decreasing rig count leads to the expected drop in supply, where does that leave the pipelines? Supplies drop, therefore throughput drops. I guess the storage business stays strong. It should be a temporary problem, but with lots of expensive new pipelines coming online, it has to make for some uneasy times for management and investors.
I've read two additional articles by him, one on his blog that is a follow-up to his earlier article poo-pooing the Haynesville economics, and another that challenges the economics of Barnett Shale wells. I should note that the second article, which was originally published in World Oil magazine is posted on a peak oil web site.
As always, I provide the disclaimer that I am no expert on the subject, but in the interest of presenting all sides of issues related to the Haynesville Shale, I think it is important to consider and understand contrary opinions, especially on the subject of economic viability.
The Marcellus was made public in January 2008, just a couple of months before the Haynesville "went public" and it has generated a great deal of excitement. Because it is so large and is not an area with a great deal of production infrastructure, it will take more time to develop than fields in Louisiana and Texas. But Chesapeake Energy, which declares the Haynesville Shale to be the largest gas deposit in North America, says that the Marcellus will eclipse the it in 2020.
With all the concern about increasing gas supply and depressed prices, having an enormous gas field even closer to a large proportion of North America's end users might be a concern for those with a vested interest in the Haynesville Shale. Personally, I'm an optimist and a long-term thinker (at least I try to be). I subscribe to the "rising tide floats all boats" theory and believe that the strength of the Marcellus combined with the gas shales of Haynesville, Barnett, Fayetteville, Horn River, etc. will conclusively prove that natural gas is a viable alternative to oil and coal as a fuel. Ultimately, I think our energy survival depends on a "portfolio approach" where we use all manner of fuels for our energy needs, but I believe natural gas can be the backbone to this portfolio.
1. Environmental impact
2. Impact on water resources
3. Air quality
Monday, August 10, 2009
GMX Resources announced a new well today (although it’s not noted in the company’s release, I believe the wells are in Harrison County, TX:
- Holt 1H (formerly the K5 1H): 9.3 MMcf/day initial production (24 hours) rate at 25/64” choke at 4,156 lbs of flowing casing pressure.
Next up are the TJT Simpson 1H, which is scheduled for a frac treatment later this month, and the Verhalen “B” 1H, which is currently being drilled and is expected to be completed later this month.
Later this week, I'll dig deeper into GMX's recent operational report.
[UPDATE 9/30/09: The Holt well flowed at a rate of 5.7 MMcf/day for the first 30 days of production, according to a GMX press release.]
- Sample 4 #2 (serial #238828), Sec. 4, Township 14, Range 11: this well has been producing since March 2009 and has already produced 2.3 Bcf, which equates to 13 MMcf/day. Petrohawk estimates a EUR in the 13 to 15 Bcf range.
- Matthews ETAL 17H #1 (serial #239157), S17/T13/R11: this well has been on a restricted choke of 14/64" but flow rate and pressure have increased to the point where it was producing 8.9 MMcf/day at 9,035 lbs flowing casing pressure on the reduced choke. Petrohawk intends to keep this well on a restricted choke to test decline rates versus other area wells with more open chokes to see if it wants to apply this technique to other wells.
Petrohawk is currently running 12 rigs in the Haynesville Shale, but it expects to increase this number to 16 by October.
Most recently, it focused on the 110,000 acres it leases around Carthage, TX. In drilling, coring, mapping and analyzing results, the company has de-risked 74,000 of the 110,000 acres in this area and has pinpointed 800 potential drilling sites. A couple of completions the company noted:
- A 118H: 5 MMcf/day 24 hour initial production; Carthage Field, Panola County
- Smith Bird 20H: "greater than 6 MMcf/day" 24 hour IP
In terms of its initial production rates, the company executives went out of their way to explain that they have been choking back wells during completion because they believe it will help ultimate recoveries. They made it fairly clear they could produce stronger IP rates if they want. I imagine they want to placate investors and analysts who are seeing eye-popping IP numbers from other companies.Next, the company will move south and examine its holdings in San Augustine and then Shelby Counties where it leases around 47,000 acres. Outside of these areas, the remaining leasehold is largely held by production.
As with other companies, Devon is seeing greater production efficiencies ("60% improvement in drilling efficiency") and lower drilling costs (about $7-9 million per well).
This is good news because it provides a water solution that is not dependent on the existing aquifers, which are being stressed by competing users. It also provides a ready source of water in an area where it is not feasible to draw water from the Sabine or Red rivers.
Currently, IP discharges 12 million gallons of treated water per day into the Red River (which is odd because IP sources the water via pipeline from the Sabine River). EXCO will receive the water via a three mile pipeline and plans to use between two and five million gallons per day.
I noted two recent Texas Haynesville/Bossier Shale completions this week:
- Fogle Trust #3, NFR Energy: 0.663 MMcf/day IP on 48/64” choke; North Carthage Field, Harrison County; Bossier Shale
- Red River 164 #1, Common Resources: 13.418 MMcf/day IP on 22/64 choke; Bossierville Field, San Augustine County; Bossier Shale
- Berry 24H -001, Chesapeake Energy: 9.531 MMcf/day initial production on 16/64” choke; Caspiana Field, Caddo Parish; Section 24/Township15/Range15, Haynesville Reservoir A; Serial #239611
- Hutchinson 10H, Questar: 9.12 MMcf/day IP on 20/64” choke; Elm Grove Field, Caddo Parish, S10/T15/R12, Res. A; Serial #238997
- Blackstone 25-11-15H 001, Chesapeake Energy: 6.097 MMcf/day IP on 18/64” choke; Logansport Field, DeSoto Parish; S25/T11/R15, Res. A; Serial #239083
- Chesapeake Royalty 30-14-12H 001, Chesapeake Energy: 16.45 MMcf/day IP on 20/64” choke; Caspiana Field, DeSoto Parish; S30/T14/R12, Res. A; Serial #239209
- Frith 29-14-12 001, Chesapeake Energy: 13.922 MMcf/day IP on 18/64” choke; Caspiana Field, DeSoto Parish; S30/T14/R12, Res. A; Serial #239232
- Peacock 13-15-15 001, Chesapeake Energy: 9.468 MMcf/day IP on 20/64” choke; Caspiana Field, DeSoto Parish; S30/T14/R12, Res. A; Serial #238618
- Phillips Energy 1H 001, Chesapeake Energy: 8.977 MMcf/day on 16/64” choke: Caspiana Field, DeSoto Parish; S30/T14/R12, Res. A; Serial #239571
Saturday, August 8, 2009
EOG Resources generally has been on the PR sidelines in regards to the Haynesville Shale, but in its second quarter earnings release last week, it trumpeted some of its Haynesville Shale results with a little extra energy. The company has about 116,000 net acres and is currently running four rigs. The rig count will increase to ten in 2010.
The company reported five wells, all in DeSoto Parish, LA. EOG reports that the initial production rates are pipeline restricted rates and have the possibility for higher IP rates. Here are the wells and IP rates:
- Johnson 6#1: 14.3 MMcf/day
- DN Bell #1: 14.4 MMcf/day
- Thompson 11#1: 14.9 MMcf/day
- Lafitte 34 #1: 15/7 MMcf/day
- Billingsley 35 #1: 14.6 MMcf/day
In another nod to the increasing attention to outsized IP rates that several companies are promoting, EOG published a bar chart comparing the company’s Haynesville Shale achievements to those of several competitors showing that more than 90% of its wells have had IP rates greater than 10 MMcf/day.
Friday, August 7, 2009
This is a big deal because the more LNG that comes to the U.S., the more downward pressure on natural gas prices. It will be interesting to keep an eye on countries like Russia and Qatar as their LNG ports ramp up.
In the Haynesville Shale region, the rig count increased by seven, a 5.5% rise, to 134. Of the increase, one was in Louisiana (to 88) and six were in Texas (to 46). Given the net four gas rig increase nationally and the net seven increase in the Haynesville Play, it implies that without the Haynesville Shale there would have been a decrease of three gas rigs nationally.
Thursday, August 6, 2009
XTO, which has 100,000 acres in the play, reported that the economics in the Haynesville Shale are still attractive. Additionally, the company reported that it is seeing operational efficiencies in the play as it drills more wells.