Wednesday, September 30, 2009
The company also announced that it has drilled the Verhalen "C" 1H and the well is scheduled for completion in October 2009. GMX noted that the well should cost approximately $7 million, its lowest capital expenditure in the Haynesville Play to date.
Some might argue that Exco is surrendering good future cash flow and portfolio diversification to concentrate its risk in shale, but it clearly speaks to the company's belief in Big Kahuna plays like the Haynesville.
The natural gas industry is at a very important point. The arrival of shale gas has completely changed the supply paradigm for the industry. North America is awash in natural gas. The question now is what happens on the demand side?
The biggest prospect for gas is to power more electric power plants, and the incredible opportunity that presents itself is the current move to revise our nation’s energy policy to limit greenhouse gasses. This is a tailor-made situation for gas, which when burned has half the carbon output of coal and almost none of the other pollutants like mercury and sulfur.
Unfortunately, the gas industry had its head in its rear when it came time to lobby the House of Representatives and was “schooled” by the coal lobby. There is still a chance to change the policy in the Senate, but coal still has the more powerful lobby supporting an inferior and dangerous product for which it will fight to the death (think: tobacco).
If new demand drivers are not found for natural gas, the price of gas will be capped for the foreseeable and producers will be fighting a constant battle to keep a lid on production while still drilling new wells. It will not be pretty. The gas industry stands at the crossroads and the outcome of the energy/climate debate in Congress will largely determine its future, at least for the next few years.
Tuesday, September 29, 2009
First, a little bit on fracing. Here is a good explanation of the practice (the second half of the article). It, along with horizontal drilling, is the key enabling technology for the production of shale gas.
The controversy over fracing comes from the use of potentially dangerous chemicals as a small part (+/-1%) of the injection fluid mix. Now that the Marcellus Shale is being developed in earnest, there are many environmentalists and communities raising concerns over the use of these chemicals. Because there is limited information about the contents of fracing fluid – the contents change depending on the geology and the company selling the fluid – there is some misinformation being circulated by opponents of the practice. The discussion has fed a movement to limit Marcellus drilling on a local and regional level.
While drilling has taken place in the Appalachian region for 150 years (Titusville, PA was the site of the first oil well drilled in the U.S. exactly 150 years and one month ago in August 1859) and Pennsylvania and West Virginia have the second and third most gas wells in the country, respectively, the industry doesn't seem as ingrained in the region as it is in Texas and Louisiana. Appalachian residents also believe, rightly so, that the beauty of the region and the quality of drinking water need to be preserved.
Recent incidents of spills, most notably by Cabot Oil & Gas in Dimock, PA, have heightened concerns. There is no proof that fracing impacts aquifers, and incidents like Cabot’s result from surface spills and accidents. Opponents to the practice, however, do not differentiate how the damage occurred, only that it did occur.
Gas production companies hold that the practice is very safe, especially because the chemicals are injected thousands of feet below the surface and the fluid’s dangerous chemicals are used in very small quantities. One problem they have in making the argument is that they are bound by their suppliers’ confidentially agreements not to disclose the mix of ingredients because of the proprietary nature of each company’s fluid. Schlumberger and Halliburton don’t want the other to know the recipe for their secret sauce.
There has been a recent movement by E&P companies, especially Chesapeake Energy and Range Resources, to pressure their service providers to disclose the chemicals and seek new, less dangerous chemicals that do the same thing without the risk. Technically, the service providers don’t have to do disclose their fracing recipes and look for safer alternatives, but it would be in the best interest of the gas industry for them to do so. If their opacity leads to regulation of the practice, they will be forced to disclose their recipes eventually.
There is a bright light shining on the gas industry now thanks to the recent shale discoveries and the opportunity for natural gas to be used as an environmentally-friendly alternative to coal. But the future of natural gas is drilling all over the country, not just in Texas and Louisiana where people often turn a blind eye towards drilling. The gas industry is going to have to prove that it is a good neighbor and an effective steward of the land if it is going to be welcomed in new prospects.
Natural gas is poised to become this nation’s leading energy source, and it is in the best interest of everyone involved in the industry to be transparent and responsible. The “golden goose” is at hand – don’t let it get strangled by intransigence.
[UPDATE 9/30/09: Here is an article from Bloomberg about Schlumberger pressing its suppliers to reveal the contents of fracing fluid.]
Monday, September 28, 2009
The difference between the October and November contracts illustrates contango, which is what traders call the situation when commodities futures prices are higher than the spot prices. Contango is a natural state for commodities markets because there is an implied cost of storing and financing commodities for delivery at a future time. But 33% between months is extreme. Part of this contango is seasonal because November is the beginning of the consumption months when prices are somewhat higher, but 33% is extreme.
Many people pointed at the extreme contango as a reason that natural gas prices will increase to the $5 to $6 range before the end of 2009. That optimism is tempered by the storage situation, which is approaching full. While there is available storage, the capacity number is a theoretical one. Most of the available storage is in the “consumption” areas, especially in the east, and not in the “producing” areas. If storage is filled up before the end of the injection season (October 31 or thereabouts), the spot price should plummet. If storage doesn’t fill up, the price should hold steady and hopefully rise. Not that I’m predicting anything…
[UPDATE 9/30/09: Here is a short article from the Wall Street Journal with more information about the transition between the Oct/Nov contracts and the coming end to the storage injection season.]
I've been following the controversial AGIA pipeline because it comes at a time when the natural gas supply paradigm has been flipped on its head by shale gas. Suddenly the Lower 48 has plenty of gas and the prospect of building a $30 billion pipeline to deliver more gas from Alaska doesn't seem smart.
The situation is a complicated one. There are only a few major producers on the North Slope of Alaska and two, BP and Conoco, are proposing a competing pipeline called Denali. Exxon recently joined the AIGA project, albeit in a non-committal way. I believe along with the fear of new supply in the Lower 48 is the concern that the price of natural gas might be rather low for a prolonged period of time. If nothing changes to juice up demand, oversupply from shale deposits will be a long-term problem and will keep a damper on natgas prices. I think Alaskan producers are looking at that situation carefully.
Ultimately I think they will look at creating an LNG export center in the Valdez area. Alaska is reasonably close to the Asian market, which will pay more for gas than the North American market. Already plans are underway for an LNG export facility in Kitimat, British Columbia for these same reasons.
Just another fun story to watch in the ever changing world of natural gas.
[UPDATE 9/29/09: The AGIA vs. in-state pipeline to Valdez has become a major issue in Alaska and has prompted one official to announce a run for governor with the "all Alaska pipeline" as the cornerstone to his candidacy.]
Saturday, September 26, 2009
- Jernigan "A" Unit 4H, Devon Energy: 6.593 MMcf/day on an adjustable choke; North Carthage Field, Panola Co., TX (Bossier Shale)
Friday, September 25, 2009
In the Haynesville area, which includes some other targets, the count was up five, up four in Louisiana and up one in Texas. The table below shows the U.S gas. rig count (left axis) versus the North Louisiana rig count (right axis - as a percentage of U.S. gas rig count), showing that North Louisiana represents approximately 14.5% of the gas rigs deployed in the country. In this case I am using North Louisiana as a proxy for the Haynesville Shale because a higher percentage of the area's rigs are dedicated to the Haynesville Play.
While this transaction is not directly related to the Haynesville Shale, I note it for three reasons:
1) I believe that deals involving midstream assets will be the best way for private equity (PE) investors to invest in shale plays at this point. PE funds have lots of cash they need to spend, but they like to invest in "leveraged transactions" - deals where they can invest alongside a big slug of debt from a bank - which can be hard to do on the E&P side. But operators are still looking for cash to explore and produce, so PE funds are a good source of investment. Exco Resources recently closed a transaction with BG Group for 50% of its Haynesville midstream assets. I think there will be more deals like this.
2) Hey look, debt funding! A deal like this, which involves a new $500 million bank loan, shows that the credit markets are loosening, at least a little bit. That's good news for everyone in the economy because the market depends on banks lending new money. The $500 million loan was less than GIP's $588 million equity investment and the purchase of legacy midstream assets is not a huge stretch, but any big loan is progress.
3) It is always fun to watch the Chesapeake deal machine in action. Stay tuned because it won't be the last one.
Thursday, September 24, 2009
Natural gas has a huge uphill battle, especially against the coal lobby. Coal is deeply entrenched in Congress. Coal has friends. There is a Coal Caucus (there isn’t one for natural gas, as you may suspect). In the first six months of 2009, the recently formed natural gas industry group AGNA spent $310,000 on lobbying, while the coal industry spent $78 million. Guess who got heard. Guess who was left out? Another issue is that there are hundreds of independent gas companies that do most of the gas drilling, while there are only a handful of big coal producers; therefore the coal industry is far more organized.
It is an interesting piece and will send a few shivers down the spines of gas fans. Check it out:
Wednesday, September 23, 2009
I'm not quite sure how that would work since the council would probably have to pass an ordinance to put the language in all new contracts. What's the difference?
- Kathryn Drake 4 H #1, EnCana: 8.064 MMcf/day IP on 19/64" choke at 5,627 psi; Holly Field, DeSoto Parish, Sec. 4/Township 14/Range 14; serial #239169
- Matthews ETAL 17 H #1, Petrohawk: 8.014 MMcf/day IP on 14/64" choke at 8,984 psi; Red River-Bull Bayou Field, Red River Parish, S17/T13/R11; serial # 239157
Well costs are continuing to come down. Exco was running $13 million/well in Q1 2009 but is down to $9 million in Q3 2009. The company expects that number to drop to $8 million per well going forward. The capex cost breakdown is approximately 50/50 between drilling and completion with completion stimulation (33%) being the costliest component. As the breakdown below shows, stimulation costs have actually come down 55% since Exco drilled its first well.
Tuesday, September 22, 2009
Monday, September 21, 2009
I've always been amused at the concept many espouse that man can destroy the earth. It's not going to happen that way. If things go really badly, man will destroy the habitat that supports human life. Then human life will die off. Thousands of years will pass and the earth will slowly restore itself. The earth will be just fine, only the human species won't be around to enjoy it.
I've been reading numerous articles recently by environmental types pooping on natural gas, specifically shale gas, as an integral part of the world's energy future. Everyone comes from their unique points of view: some bleed green, others are peak oil zealots and others have business interests in conflict. The common theme is that they are taking swipes at shale gas. I guess that means shale gas has finally "arrived."
I confess my environmental bent after reading Randy Udall's rambling article presumably about shale gas. Udall co-founded ASPO-USA, a peak oil organization. A big problem some environmentalists have is not naming the solution but identifying the enemy. Foreign oil is a great villain, but the coal industry does much more to pollute our nation than oil. The notion that we will achieve a green energy solution by becoming a nation of plug-in hybrids without fundamentally changing how electrical power is generated in this country is naïve and foolish. Udall sort of gets it, but he is mistakenly hung up on the concept that natural gas production in North America has peaked. He mentions shale gas but he never acknowledges that he is quoting dated material.
You can't talk about the great green future without mapping out the path to get there. I firmly believe that the best and most economical source of green power in the 21st century will be distributed generation supported by larger “green” installations and a baseload system of natural gas generation. In other words, the most effective sources of energy will come from small power generation sources at homes and businesses. Solar panels, biomass, windmills, whatever. But we are not there yet. We need more work to achieve a higher level of efficiency, especially in solar, before we can see widespread distributed generation at economically viable levels.
Until then we will need a baseload power source that is cleaner than coal. Even if we achieve great new sources of solar and wind energy, we will need a relatively clean backup power source. Coal doesn't fit the bill. Gas plants can be fired up quickly and can work in the background. They emit a fraction of the carbon of a coal plant and are not sources of mercury and sulfur like coal plants. And don’t get me started on coal mining and its heinous environmental impacts.
It’s cliché now, but natural gas is the bridge fuel to a green tomorrow. But I think many green power advocates are afraid of natural gas because they think that recognition of natural gas’s attributes will stifle green energy innovation like cheap gasoline stymies fuel economy improvement. But I believe the two can work together. There is no one right energy solution, especially at this time, and most green power technologies have a long way to go to become economically viable. Switching a greater share of power generation to natural gas buys the green energy movement more time to reach economic viability and all of us a better human environment.
Sunday, September 20, 2009
I noted a few recent completions this weekend:
- Hall 34 H #1, Samson Contour Energy E&P, LLC: 7.7 MMcf/day at 20/64” choke at 4,600 psi; Sligo Field, Bossier Parish, LA; Haynesville reservoir A, serial #239461
- New Horizons #7H, XTO Energy: 6.906 MMcf/day IP at 22/64” choke; North Carthage Field, Panola Co., TX (Bossier Shale)
- PEC Minerals Gas Unit #2, XTO Energy: 6.873 MMcf/day IP at 48/64” choke; North Carthage Field, Panola Co., TX (Bossier Shale)
Friday, September 18, 2009
Then I saw a "clean coal" ad on TV by one of the tentacles of the coal lobby and felt ill.
The ad campaign is part of an advertising and lobbying blitz sponsored by the American Natural Gas Alliance (AGNA) to lobby the U.S. populace and lawmakers in advance of the energy policy debate. The campaign is led by the ad firm Grey (here is a quick article about the campaign and the other mercenaries working on the campaign). Check out the web site newnaturalgas.org.
Goodrich Petroleum released information on a few new wells today. The company has a joint venture agreement with Chesapeake Energy for a portion of its acreage, so some of these wells get reported as Chesapeake wells. Please keep in mind that all of the wells below are self-reported on a 24 hour IP, so the production rates below might be higher than the later official reports.
- Johnson 10H #1: 17.0 MMcf/day on 22/64” choke at 7,500 psi; Bethany-Longstreet Field, DeSoto Parish, serial #239645
- Dixie 31H #1: 14.4 MMcf/day on 22/64” choke at 6,600 psi; Bethany-Longstreet Field, Caddo Parish, serial #239735
- Trosper 2H #1: 11.7 MMcf/day on 22/64" choke at 5,800 psi; Greenwood-Waskom Field, Caddo Parish, serial #239841
- Bohnert 25H #1 (I think this is actually 28H, not 25H): 7.5 MMcf/day on 16/64” choke at 5,300 psi; Longwood Field, Caddo Parish, serial #238486 (if it is the Bohnert 28H)
- Swiley 4H: 7.0 MMcf/day on 20/64” choke at 5,300 psi; Beckville Field, Rusk Co.
- Beard-Taylor 1H: 6.5 MMcf/day on 21/64” choke at 5,100 psi; Beckville Field, Rusk Co.
Goodrich is currently running five rigs in the Haynesville Play, four in the Bethany-Longstreet Field (LA) and another in the Beckville Field (TX). Once the Beckville well is completed, the rig will move to the Greenwood-Waskom Field (LA), and all of the rigs will remain in Louisiana for the rest of the year.
The rig count in the Haynesville area of E. Texas and N. Louisiana, which includes other formations, increased by eight to 145. Both Texas and Louisiana saw four rig increases.
I started thinking the other day about the changes in the Haynesville rig count versus the national rig count. I wanted to see how they've changed relative to each other. I took a crack at a comparison, below.
I used the north Louisiana rig count as a proxy for the Haynesville Play since the Texas figures include lots of other fields. The green line is the U.S. gas rig count, and the blue line is the percentage N. LA represents of that figure. It is not a 100% apples-to-apples comparison because the NLA rig count is inclusive of all rigs (although don't believe there are many oil rigs are drilling in N. LA) and the green line is just gas rigs. Nevertheless, it gives some indication that since the Haynesville Shale was first publicized in March 2008, the N. LA rig count has risen steadily while the national count has dropped in response to economic conditions and plummeting gas prices. It also gives a good indication why national production has not fallen as much as expected with the significant drop in rig count.
The article cited above doesn't go into too much depth about the specific regulations, but they don't sound much different than some of those passed by the Louisiana Office of Conservation. They generally concern road use, noise, light and the use of public water.
Given the row between the north Louisiana municipalities and the Office of Conservation over well site regulations, I was expecting something a little more radical, something more befitting of the grand question of state vs. local control. But it seems like the question of who regulates the operations around well sites will remain a gray area for the near future.
Mainland contributed 8,500 acres to the venture while American contributed 5,000. Mainland will be the operator and contribute 80% of the initial drilling costs (drilling and completion) for a 51% working interest in the venture. The remaining costs will be split 51% Mainland/49% American. I'm not quite sure how the economics work: American contributes 37% of the land and 20% of the costs for a 49% ownership interest? I've got to get in on a deal like that. I'm guessing that American's land might be better quality acreage, but that is not clear from the release.
That American and Mainland would get together is no surprise. Drilling a complicated horizontal well at the depth required in Mississippi (the shale there is thicker but deeper underground) will require lots of capital and expertise. Also, Mike Newport, CEO of Mainland, is a technical advisor to American Exploration, so I figured it was just a matter of time before they joined forces.
Thursday, September 17, 2009
Here is a good article from Bloomberg framing the issues and the mountains the industry must climb. All I can say is if Aubrey McClendon and the natgas CEOs are successful in getting the gas industry well represented in the bill and can create some new demand drivers for natgas, they will have earned their massive paychecks and I won't make any more negative comments about egregious pay packages (not that I ever did in the first place).
This price spike is probably as much due to investors' warmer feelings about the economy and the fundamentals of gas as it is to activities of traders who seem to have declared a bottom. Whatever. Keep it coming.
The widespread use of CNG in vehicles is going to have to start with fleets and municipalities that have the critical density of vehicles in a geographic region and the wherewithal to build fueling stations. Once the fueling stations proliferate, the general public can get in on the CNG fun.
The only good news is that the margin by which the current gas in storage number exceeds historical trends is narrowing slightly each week. The bad news is that storage is going to be pushing maximum capacity in a few weeks. It will yield an all-time storage record, but the question is will it max out?
Wednesday, September 16, 2009
link to the whole presentation.
I've pasted the new and old curves below, but you can see that pretty much all of the inputs have changed over time. Notably, the initial production numbers have changed and the assumed price of gas has decreased from $7 to $6/Mcf. Interstingly, the resulting curves are steeper. The decline in year one went from 81% to 84% and in year two from 32% to 40%. The economics didn't change all that much because the initial production was higher, but it feeds into the assumption that the Haynesville Shale wells deplete quickly.
Goodrich also updated its production map of the Bethany Longstreet Field in Caddo and DeSoto Parishes with new results. While these results are published elsewhere on this site, I like to see these maps to keep things in geograhpic perspective.
Not being a geology professional, I can only weigh the competing points at the surface level, but I've been struggling to reconcile why so many companies would be investing billions of dollars in something that, according to Berman, is be so uneconomical. You can read the specific points if you're interested, but there were a few takeaway points for me:
- The authors contend that Mr. Berman's analysis was superficial and based on data that was not properly parsed. They dig a little deeper based on information from their company's internal database.
- "The cost of superficial analysis has very real consequences in terms of energy policy today like never before." That line really struck me. Previously I didn't pay a whole lot of attention to the argument, assuming it was largely theoretical and the truth would be apparent in new wealth (or losses) to investors in a few years. But the stakes are so much higher at this time, given what is going on in Washington.
- "Unlike conventional reservoirs, the economics of shale plays highly favor operators that invest in engineering and ongoing experimentation in optimizing their drilling, completion, and stimulation practices." The authors state that the best operators produce 40% more than the average operator from equivalent quality acreage and four to five times more than inefficient operators. That's a strong statement. I'll bet that there are lots of people out there who knew this before they signed their leases. There will definitely be some winners and some losers.
- Because of the technological and skill differences between operators, there might be an opportunity for the better operators to acquire leases that lesser operators release once the original terms expire.
This transaction was a "distressed sale" because the company was facing a reduction in its borrowing base and likely would have ended up in default. It likely was a better for shareholders deal to sell out at a lower price than risk the damage a loan default would cause. Many energy industry observers have been expecting more mergers and acquisitions in this low price environment, but it hasn't really played out that way.
I wonder if this the beginning of a wave of energy M&A transactions involving PE companies. The PE world has been looking at the energy industry, especially natural gas because of the depressed commodity prices, so I would not be surprised to see more announcements in the next three months, especially since some of the fog of uncertainty surrounding natural gas is beginning to clear.
Many PE companies really like "distressed situations" and the gas industry is full of them. PE companies are sitting on mountains of investor cash and they are on the clock to make investments (most funds have a deadline for investment, otherwise they have to return money to investors and forgo substantial investment fees). But PE companies nearly always require lots of patient debt to make deals, so the demolished state of the financial industry has really put a damper on new investments. Now that banks are starting to come out of their foxholes to make some (very conservative) loans, the PE guys are very anxious to "do deals."
So far there have been several PE-backed pipeline investments (see Regency Energy) but not as many riskier deals on the upstream side of the business. Investments in E&P might be more difficult because these companies can be harder to "lever up" with debt, especially when commodity prices are volatile. An E&P investment would require a PE investor to pony up lots of equity cash, something they are reluctant to do. But if the choice is doing an equity-heavy deal versus not doing a deal, they are going to spend the money and do the deal. Trust me, it's how they get paid.
There are several private equity backed businesses out there, mostly startups, that are making noise. One of note is NFR Energy, which combines Nabors Industries and energy PE specialist First Reserve Corporation. The company has been very active in drilling Texas Haynesville Shale wells. Earlier this year famed PE investor KKR invested in East Resources, a Marcellus Shale operator.
It will be interesting to see if PE companies make investments in the Haynesville Shale. PE-backed companies tend to be very aggressive because the aim is to sell the company or have an IPO within five years. Since most of the Haynesville land has been leased, PE money might end up with smaller companies playing the fringes or in infrastructure projects. Or they might wait until leases start to expire and invest then. We'll see. Yet another interesting story to follow in the Haynesville Play.
Tuesday, September 15, 2009
This sad news shows just how dangerous rig work is. Many of us who own a little piece of what's underground often don't fully appreciate the danger above ground to those involved in the everyday exploration and production of minerals. Our thoughts go out to the families of these men.
My enthusiasm was short lived as I recalled the Energy Information Administration’s Short-Term Energy Outlook, which came out last week. The EIA expects the Henry Hub spot price of natural gas to average $2.32 in October and rise somewhat towards the end of the year. This depressed price projection is due directly to gas in storage, which the EIA expects to reach a record of 3.84 Tcf by the end of October (it is at 3.4 Tcf today). The Henry Hub spot price expectation for 2010 is $4.78, which is disappointing. Of course, it’s just a prediction, not a crystal ball reading.
On the supply side, the EIA expects LNG imports to increase in 2009 by 110 Bcf to 460 Bcf. The LNG import figure is expected to increase by 200 Bcf in 2010 to 660 Bcf.
The consumption numbers for the first half of the year were pretty ugly, but they show signs of improving in the second half. As the chart below shows, the EIA expects natural gas consumption in 2009 to be down 2.4% compared to 2008 and flat in 2010 compared to 2009.
I believe electricity generation is natural gas’s greatest growth opportunity. As the chart below shows, the EIA expects electricity consumption to be down 3.3% in 2009 compared to 2009 and up only 1.2% in 2010 over 2009.
The second project is an expansion of the Regency Interstate Gas Line (“RIGS”) project that is still under construction. The expansion, called the Red River Lateral, will extend the reach of the new pipeline 12.5 miles (36” pipe) into the western portion of Red River Parish, currently a hotbed for big fat wells. The slide below does not show the Red River Lateral, but you can see where it will come from. I’ll post a drawing of the extension when I find one.
The second glimmer of hope is an improvement in manufacturing. Earlier this month, the Institute for Supply Management's manufacturing index (below) showed a sharp spike, rising from the mid-30's to 52.9. A number above 50 means the manufacturing sector is expanding. The index has not been sustainably above 50 since mid-2007. This is good news to me because manufacturing and industry are big natural gas users. (Here is an interesting feature article from the Sunday New York Times)
As I've said before, there are lots of reasons natural gas prices are down, but one of the biggest is the recession and the decrease in demand. I view the above developments as very positive to the fundamental demand for natural gas. It will not be an overnight recovery, but the first step in turning the aircraft carrier is changing the direction of its momentum.
Monday, September 14, 2009
I read an article today noting that Goldman Sachs analysts predict that natgas prices will rise to $6 this winter and $7.50 next summer because of production declines. While I want to believe this, I don't think we've seen the kinds of production declines we've expected with such a drastic decrease in rig count. Producers have cut back, but they are focusing on fewer, bigger wells, so production hasn't dropped as much as people were expecting it to six months ago. Plus, if prices start to rise, producers are going to open the spigot on the wells they have choked back over the past few months. Until demand picks up to a sustainable level, I think "turn the dial" production increases are going to beat back price increases.
But what do I know? I'm not a well paid Wall Street analyst. Heck, I don't even get paid for this! I hope they're right. Stock market analysts, for as smart and well informed as they are, can be wrong. Now, if Goldman is trading on this expectation, I would have much greater confidence.
Sunday, September 13, 2009
There were a couple of interesting big picture news stories this weekend:
- Gorgon LNG Project: The big Australian gas field and proposed mega-LNG project got lots of press in the Wall Street Journal this weekend with a small feature article on Friday and a news item (dated tomorrow) noting that the project is expected to go ahead. The second article gives a good 10,000 foot overview of the Australian natgas production market, which is a big provider of LNG to Asia. Australia also has an oversupply problem, but for them it manifests in a race to develop fields and lock up LNG customers before their competitors do. Without long-term contracts, there is no point of developing a new field. It will be interesting to see how the proliferation of natural gas impacts the global pricing and supply market and how long it takes for other nations to find new uses for natural gas.
- Clean water: A little off topic, but the New York Times had a long front page feature on how clean water laws are neglected across the country. While the story is national in scope, it focused particularly in the Appalachian region where coal mines have polluted the water for generations. Lest we who live in the south get too haughty, the article points out that 70% of the Texas water systems and 23% in Louisiana are in violation of the Clean Water Act. Pretty scary stuff. It’s a very long feature resulting from exhaustive research, but the relationship between water and gas drilling will continue to be a major issue. (Generally, I think access to clean water is going to be one of the big issues of the 21st century, not only in developing nations but in North America as well.)
Saturday, September 12, 2009
Friday, September 11, 2009
Interestingly, the futures price ended down sharply, losing 8% to close at $3.00. For the first time in a few weeks, the spot price and the near month futures price are not significantly out of alignment.
In the Haynesville Shale area, which includes some other fields, the net rig count was down three to 137. It was up six in north Louisiana (to 95) but down nine in East Texas (to 42).
A key issue for a transition from coal to natgas is supply stability, and electric companies are starting to get comfortable that the supply of gas will be sustainable going forward. One of the positives of coal is the relative stability of supply and price. Between big shale finds and the infrastructure to import LNG, natgas supply will become greater and more sustainable. Additionally, as new gas fields are explored and pipeline and storage infrastructure is constructed, the aggregate gas storage capacity will increase, helping offset issues of peak demand.
Coal still costs less than natgas, around $2.24/MMBtu for coal vs. $3.83 for gas in the second quarter of 2009, but one analyst calculates that coal's share of the electrical generation market has dropped from 49% to 45% this year. He noted that for the last twelve months through June 2009, coal-fired generation fell 12.7%, while gas-fired generation fell 0.3%. This year's statistics might be an anomaly, but I think it is indicative of a long-term trend.
Thursday, September 10, 2009
First, the article talked about traders who are taking advantage of the steep contango with gas prices. This link better describes contango, but it is a situation where the future prices for a commodity are significantly higher than the current prices. This allows an entity, be it a hedge fund, electrical generator or trader, to buy gas at low current prices (spot price is $2.68/MMBtu today) and lock in a sale at a higher future price (October 2010 price is $5.89/MMBtu). The gas is stored somewhere for a year and then delivered to the buyer.
The contango trade and the diminished natgas consumption creates the second big moneymaking opportunity: natural gas storage. As storage facilities, which are everything from tanks to empty salt domes, fill up they can charge a premium for storing more gas. Gas storage rates are not regulated, so the market price reflects the degree of the need that is being satisfied.
The third profitable area is in natural gas liquids (NGL) separation. Petrochemical producers are using NGLs like ethane as a feedstock in making plastics, and companies that provide a process called fractionation are doing well. Usually this feedstock comes from oil, but because the ratio of prices of natgas and oil, which are usually aligned, has separated badly (the normal 6:1 ratio jumped to 37:1 on Friday before recovering to the mid-20s), natgas products are much more attractive. Many in the market believe that gas will remain cheaper than oil on a per energy unit basis for a while so the fractionation business might be a good place to be. While this creates new customers for natural gas products (although NGLs are not present with all gas), it is dependent on continued low prices of natgas.
I’m happy for these folks making money in a down environment, but their success depends on natural gas prices being cheap for the foreseeable future, something I don’t want to see come to fruition.
The bad news is that the storage numbers are still well above average, but the good news is that the injection amount was not above the norm for this time of year. In fact, the variance percentage has decreased slightly. More good news is that the gas was injected in the right place. By geography, storage levels are highest in the so-called Producing Regions (+32.4% variance above five year average) and are lowest in the consuming East Region (+9.6%). Of the 69 Bcf injection this week, 80%, or 55 Bcf, went into storage in the East Region.
Wednesday, September 9, 2009
- Broussard 5 #1, J-W Operating Co.: 2.8 MMcf/day IP on 24/64” choke at 1,600 psi; Elm Grove Field, Bossier Parish, Sec. 5/Township 16/Range 12; completed 4/13/09, serial #238891
- Pennywell 15 #1, J-W Operating Co.: 4.4 MMcf/day on 14/64” choke at 3,500 psi; Caspiana Field, Caddo Parish, S15/T15/R14; completed 6/2/09, serial #239106
- Kelley ETAL 19 H #1, Chesapeake Energy: 9.875 MMcf/day on 16/64” choke at 7,225 psi; Caspiana Field, Caddo Parish, S19/T15/R14; completed 7/12/09, serial #239582
- Hunt Plywood C #7, KCS Resources (Petrohawk): 20.8 MMcf/day on 24/64” choke at 7,790 psi; Caspiana Field, DeSoto Parish, S35/T15/R13; completed 7/19/09, #239145
- Justice 13 H #1, Chesapeake Energy: 6.327 MMcf/day on 12/64” choke at 7,124 psi; Logansport Field, DeSoto Parish, S13/T11/R15; completed 7/7/09, serial #239344
One thing that was interesting was the discussion of the southwestern portion of the Haynesville Play that dips into Shelby and Nacogdoches Counties, TX. There is new leasing activity in the area, and Petrohawk is taking a partnership approach, working with a couple of companies that don't have much Haynesville exposure, Newfield and Noble, along with EOG Resources. Other participants in the area are XTO, Common Resources and Devon. The company has completed two wells and two more are waiting to be fracked. The slides below give more detail, but in the coming months we will know more about the area's potential.
Petrohawk is still very excited about its core Louisiana proprties, but with the low natural gas prices it seems to have narrowed its focus on the wells that are most economically feasible, located inside the circle below.
The image in question, below, is the “Coal Flow” diagram for 2008. It shows the sources of all coal in the U.S. and all of its uses. For most industries, the right side would look like a plate of spaghetti of multiple end users, but for coal it looks like a fat log of one big user.
Think about it: if legislation passes that creates incentives for utility companies to use gas over coal, the coal consumption level will drop immediately, and no other consuming industry will be there to pick up the slack. If production doesn’t drop accordingly, suddenly you’ve got a colossal supply problem and you know what happens then. Sound familiar natgas fans?
The coal industry now has a supply issue of its own as the chart below points out. The chart shows the electric power sector’s coal stocks for the past five years (in thousands of short tons) through May 2009. As the chart shows, the May 2009 figure of 198 million ST is 39.3% higher than the average storage number for the same month of the previous four years. Comparatively, natural gas storage is about 18% higher than the five year historical average. But while gas is easier to transport than coal, coal is easier to store than gas (just make the black mountain higher and wider), so you don’t hear as much about the coal stockpiles.
If it weren’t for cheap coal to power electrical plants, I’m guessing many coal mines would have been shuttered a generation ago. Now, the coal industry is entirely dependent on the electric utilities and probably does everything but shine their shoes each morning. The energy/climate legislation is the battle for the coal industry’s life, and it will fight like a cornered wildebeest. Just like the tobacco industry, which has been fighting for its life in the courtroom for the past decade, coal is going to throw every conceivable resource at this proposed energy legislation to pull out a win. It will be ugly, and I wouldn’t bet against the coal industry.