Thursday, April 30, 2009
This next slide is equally telling. The chart showing electricity consumption has been at a 45 degree angle since 1990. I keep hearing that we as a nation are now different - no more McMansions and conservation is the name of the game. I think we need more than six months of data from an economic downturn to establish a real trend. Haven't we seen this before? Look at 2002 - does it look familiar? I sincerely hope we have turned the corner as a nation in terms of consumption. We are a ridiculous people with all of our excess and waste. But will there be any substantive change overnight? Gasoline prices have dropped from $4 to $2 and suddenly people are buying trucks instead of hybrids again. My point is that we are a nation bred on consumption with a yearning for excess. I think we're going to continue to use more power.
The slide below is interesting because it shows the cyclical nature of natural gas prices over the past decade compared to the rig count. Rigs have largely remained steady except in 2002 and 2008-9. Seeing the steep decline of both, it makes you realize that a trough is coming soon - the question is how much more blood will be spilled?
The final chart I thought was interesting compared oil and natural gas commodity prices since 1994. It shows that the price of gas is so much more volatile than that of oil if you don't consider the insane oil price run-up of last summer. The chart also shows that while gas is more volatile in price, oil and gas largely move together. Wall Street analysts focus on this too, as they constantly quote the differential in terms of a ratio. Note in the most recent entries how divergent oil and gas are right now. If history is any guide, something has got to give.
Wednesday, April 29, 2009
- First, Chesapeake broke the news of the Haynesville Shale last spring. Aubrey gets a big feature article in Fortune Magazine. Chesapeake gets lots of attention. But the company and its competitors suddenly find themselves having to shell out huge lease bonuses to suddenly over-informed property owners, a situation that haunts these companies as natural gas prices have dropped, challenging the economics of these new wells.
- Hooray! Over the summer, the price of natural gas shot up to around $13.50! Chesapeake looks brilliant tying up lots of new leases and beginning to drill aggressively. But Chesapeake had done such a good job of hedging natural gas prices as they rose that the company has to show huge accounting losses when reporting earnings to reflect the market value of the positions. Ouch, stung by their own foresight and success.
- Oh no! The price of natural gas falls off the cliff and everyone in the industry gets hammered, but remember those hedges - they help keep Chesapeake out of the trench. Also, the company enters into joint venture and sale arrangements with big fish like Plains Exploration, StatoilHydro and BP to monetize most of its shale positions. Chesapeake is the envy of every company in the field.
- But the company's stock price still gets hammered, which leads to enormous margin calls for CEO McClendon, who had used the value of his Chesapeake shares to borrow money, presumably to buy more shares, among other things. The margin calls in October require him to sell 31.5 million shares, or 94% of his holdings, at depressed prices (there was no "up" here, just "down").
- In December he signs a huge contract with a one-time $75 million bonus and receives a grant of $32.7 million of stock. The company also agrees to buy Aubrey's collection of maps and artwork for $12.1 million (!!!). In all, the package is worth $112 million. It's so good to have friends on the board's compensation committee.
All in all, it's been a wild ride for Aubrey. No more Forbes 400 or the Billionaire's List, but he's working his way back there. Unfortunately for him and Chesapeake, the compensation is suddenly getting lots of attention. It was ranked as one of the five dumbest things on Wall Street this week by thestreet.com.
I wasn't going to mention any of this until I opened the Wall Street Journal and saw a big article on the front page of the "Marketplace" section focused on shareholder outrage regarding the pay package. It got me thinking about my ups and downs, my good days and bad days. My own life, even on its most hectic day can't compare to Aubrey's. I can't wait to see the next act in the Aubrey McClendon Show.
From the announcement: "The Clingman Acres 11H well was tested by the state to be flowing at a rate of 17,040 Mcf/day, on a 24/64 inch choke, with 6,170 pounds of flowing pressure, from the Haynesville Shale formation. A 10 stage fracture stimulation completion technique was performed on this well. This well was completed in February 2009; however, pursuant to a confidentiality agreement with Chesapeake, Cubic is precluded from releasing any flow information until a state test has been filed of record."
The well is located in Section 11, Township 15N, Range 15W in the Caspiana Field in Caddo Parish, Louisiana, which is contiguous to the east side of Cubic's Johnson Branch acreage. Cubic has an estimated 2.8% working interest in the well.
Tuesday, April 28, 2009
More information is available on the project's website.
Monday, April 27, 2009
"Testing the Haynesville Shale in North Louisiana, EOG drilled two horizontal wells on its acreage during 2008. The Martin Timber #2H tested at a rate of 17.4 million cubic feet per day (MMcfd), gross with 4,700 psi flowing tubing pressure. The Bedsole 27#1H tested at a rate of 17.5 MMcfd, gross with 7,400 psi flowing tubing pressure. EOG has 100 and 57 percent working interest in the wells, respectively. Due to pipeline limitations, the wells are currently producing at a combined restricted rate of 17 MMcfd until additional infrastructure is in place. EOG has estimated net reserve potential of 3 to 4 trillion cubic feet of natural gas on its 116,000 net acres and expects to drill 14 Haynesville wells in 2009."
While the Haynesville Play is certainly a huge windfall to NE Louisiana and East Texas, its development needs to be balanced with its potential impacts. The issues of groundwater usage, noise, road wear and tear, etc. are beginning to appear. The state and local regulatory bodies need to balance the economic benefits with the orderly removal of the resources.
The chaotic land grab that characterized the leasing of the play must not be replicated in the production phase. The quickest way to kill the golden goose is to let it smother itself. The gas isn't going away. Lest people run around shouting that excessive regulation is going to run off production companies, I think the last line of the editorial says it best: "One area government official recounts a threat that too many government restrictions could lead one exploration company to leave a parish altogether. How that company would take the Haynesville Shale with them was uncertain."
Patience and foresight should rule the process, not greed and speed.
Sunday, April 26, 2009
Saturday, April 25, 2009
The company is not terribly forthcoming about its Haynesville activities at this point. In 2009, it plans to dedicate 35% of its $0.9 to $1.3 billion drilling program, or between $315 and $455 million, to its north Louisiana properties. In the Haynesville Play, El Paso is operating in the Holly, Bethany-Longstreet and Logansport fields. They have engaged in some Haynesville drilling, but they have not publicized the results.
The Texas count has been dropping for a while. This is the first time the Louisiana count has dropped in a few weeks, but it the count still higher than it was at the beginning of the month. The bottom line is that natural gas supply is going to be going down.
Friday, April 24, 2009
Devon estimates that it is sitting on 70 Tcf of gas in the play, but they have been very concerned over the past six months on the big picture from a corporate perspective. They are cutting spending, preserving cash and strengthening their balance sheet. This is all good stuff for Devon and it positions the company to survive the downturn in gas prices, but it doesn't lead to a lot of news on the exploration and production side.
In the six months through the end of March 2009, Devon has decreased its company-wide rig count from 112 to 32. The company's 2009 plan is for 11 horizontal wells in the Haynesville Shale, but Devon's mantra is evaluation, evaluation, evaluation. Not production. So they are going to spend money drilling, coring and testing well sites. This activity should put them in position to start a drilling campaign in earnest once gas prices pick up, which is expected by the end of the year.
The company has completed 14 Haynesville tests and has completed its first horizontal well, the Mosley 14-1H (14 Mmcfe/day initial production). Forest has one additional horizontal well completing and another two drilling. It's 2009 drilling program includes between 10 and 12 Haynesville wells. The company believes that it can drill wells for approximately $7.3 million, which is somewhat lower than the estimates of competitors.
Thursday, April 23, 2009
EnCana CEO Randy Eresman told reporters that the costs of drilling in the U.S. is cheaper than in Canada, and EnCana plans to increase its Haynesville capital budget from $290 million to $850 million. EnCana looks at the Haynesville Play as a long term benefit for the company, but he noted that to be truly money making, the shale plays require gas prices to be between $6 and $8 per MMBtu. The company admitted that it is increasing its investment in the Haynesville Shale in an effort to hold the leases, which start expiring in 2011, but the additional investment is a testament to EnCana's belief in the long-term potential of the play.
From a results perspective, Encana (which is in a joint venture with Shell Oil) reported two new Haynesville completions:
EnCana also noted that it has committed to 150 million cubic feet per day of capacity on the proposed Gulf South pipeline expansion and another 500 million cubic feet per day of capacity on the proposed ETC Tiger pipeline.
So far EOG has tested two Haynesville wells that have yielded an average of 17 Mmcfe/day. The company plans a total of 14 Haynesville wells in 2009, and they believe they are sitting on a potential 3 to 4 Tcfe of gas reserves in the play.
The project is still on target for a 2011 completion and is expected to cost between $1.0 and $1.2 billion.
Wednesday, April 22, 2009
- Roos #32H (Petrohawk is lead partner, Questar has 28% working interest): 24.8 Mmcfe/day initial production, Bossier Parish
- Golson 32H #1: 23.0 Mmcfe/day IP, Bienville/Red River Parish line
- Shelby 31H #1: 21.7 Mmcfe/day IP, Bienville/Red River Parish line
Questar also provided a summary (although about a month old) of activity surrounding its acreage:
This image says it all. Rig counts in U.S. dropped to 975, down 30 from last week and 852 from this time last year, the first time the number has been below 1,000 since 2003. The good news is that the rig count in north Louisiana was unchanged and is actually up four this week to 75. The news is less positive for the 6th district of Texas, which encompasses the Haynesville Shale. There the rig count dropped by four to 66 rigs. That number is down eight rigs from two weeks ago.
What’s most telling is how steep the drop-off is. Rigs are dropping so fast, Chicken Little has to be nervous. What it really tells me is that there will be a sharp drop in supply, especially in natural gas, in the next 6-9 months (unless, of course, LNG floods the market as some predict), which should lead to a commodity price increase. When prices do pick up, there is going to be a mad scramble to restart rigs and assemble crews. It’s going to be chaos and it will likely set the proverbial stage for another boom-bust drilling cycle. Remember the old on the bumper sticker, “Please God, Just Give Me Just One More Oil Boom. I Promise Not to Blow it Next Time”? Yeah, right. Just like semiconductors, oil and gas is a highly cyclical industry that is dangerous for investors.
On top of this news, Halliburton, which had hoped to prevent any layoffs, ended up cutting 2,000 jobs, or 12% of its North American work force.
Below I've copied a few maps from the presentation showing the activity, both by Goodrich as well as its competitors. It's interesting to note the sheer number of Haynesville penetrations on the maps. While it's a terrible gas price environment, the exploration companies are continuing to drill.
Tuesday, April 21, 2009
In his presentation, he said that Chesapeake expects gas prices to return to return to $7.50 to $9.50 possibly by the end of this year.
In the slides below, Petrohawk has isolated what it believes is the "core" area (the darker shaded area) of the Haynesville Play through drilling tests.
Petrohawk plans to drill between 75 and 80 wells this year, completing about six per month. Interestingly, the slide below has a graphical decline curve for the first eight months or so on a real number basis, rather than percentage basis, for their average IP of 18 Mmcfe/day.
"Petrohawk utilized eight horizontal rigs on average in the Haynesville Shale during the first quarter, not including spudder rigs. A total of 15 operated and 16 non-operated wells were drilled. Of the operated wells, 11 were on production at the end of the quarter. Additionally, five operated wells drilled in late 2008 were put on production, bringing the total number of Haynesville Shale wells completed by the end of first quarter to 28. The average initial production rate for operated wells completed during the quarter ranged from 3.3 Mmcfe/d to 24.8 Mmcfe/d, averaging 17.1 Mmcfe/d. The average initial production rate for all operated Haynesville Shale completions to date, excluding two previously reported wells that were mechanically compromised, is approximately 18.0 Mmcfe/d.
"Spud to spud times are currently averaging 60 days, with total spud to first production times averaging 80 days. Drilling efficiencies are being gained by increasing the size of the intermediate casing used, from 7 to 7 5/8 inch. This has allowed for a larger hole size while drilling the lateral, which in turn has resulted in significantly higher rates of penetration. The Company has also undertaken more progressive angle-building in the curve, and thicker geosteering targets, which have also contributed to decreased drilling days. Drilling and completion costs are currently ranging between $9.0 million and $10.5 million per well, based on average lateral lengths of 4,300 feet with 12 to 14 fracture stimulation stages per well. The Company is targeting development well costs between $8.5 and $9.5 million per well.
"Petrohawk continues to employ the same basic completion procedures utilized in 2008, with some refinements. Lateral lengths are targeted at between 4,300 and 4,600 feet, with frac stages spaced approximately 325 feet apart. Each stage is comprised of four perforation clusters, two feet in length, and spaced approximately 80 to 85 feet apart. The Company utilizes a slickwater technique as well as either ceramic and resin-coated proppant, preceded by 100 mesh sand. The longest lateral length drilled to date has been approximately 4,700 feet with 14 stages of fracture stimulation. Even though these procedures have delivered outstanding well performance, Petrohawk continues to evaluate these procedures and plans to test variations on these methods to maximize well economics.
"Recently drilled wells have tested several new development areas away from Elm Grove Field. The Company will conduct its 2009 program on locations in excess of 40 miles apart in both north-south and east-west directions, including portions of Caddo, Bossier, Red River and DeSoto parishes. East Texas development will primarily be directed through a joint venture partnership with EOG Resources, which expects to increase the drilling activity in the joint venture area during the year.
"In addition to its existing infrastructure from operations in Elm Grove Field of northwest Louisiana, Petrohawk has completed construction on more than 50 miles of 16 inch gathering lines as well as approximately 330 Mmcf/d of treating capacity to service new production from the Haynesville Shale. The Company expects to construct an additional 112 miles of gathering pipeline and an additional 420 Mmcf/d of Company-owned treating capacity by the end of 2009.
"Additionally, Petrohawk has finalized an agreement with Regency Energy Partners to secure space on Regency's Haynesville Expansion Project to transport 400 Mmcf/d from the area. The Haynesville Expansion Project is expected to be completed by year-end 2009. Not including the incremental transportation space added by the Regency Energy Partners project, Petrohawk's total takeaway capacity builds to 850 Mmcfe/d during 2009, with additional takeaway capacity available on a non-contracted basis. Additionally, the Company has acquired firm transportation on other pipelines that it expects will provide sufficient take-away capacity for future Haynesville Shale production."
In the third part of the interview, Simmons was asked about the emerging shale plays in the U.S. Simmons has a pretty dim view of the potential new supply created by these plays, in part because of a lack of data. He considers most of the frenzy about shales to be overblown at this point, noting, "I’ve never seen the industry hype something crazier."
Simmons points to the production growth statistics in the Barnett Shale, noting that much of the increase in production is linked to the addition of new wells. He also notes that peak initial production comes almost immediately and production declines quickly because of the way the operators frac the wells, so the wells don't have long-term productive lives. He doesn't see a sustainable supply increase coming from the shales, but he said we really won't see any real numbers until the states report production numbers from Q3 2009.
I'm not going to get into a Peak Oil argument, but it's hard to tell whether he is pooping on shale plays to support his argument about Peak Oil or if he is on to something. In any case, what is true is that the numbers just aren't in to support either side. Check out the interview. The questions about the shale plays are at the end.
Monday, April 20, 2009
The company also offered a snapshot, shown below, of what it considers to be the competitive wells near its leased property. Most of these wells aren't yet reporting, but neighboring results look pretty decent.
It's always interesting to see a company's take on explaining the geology of the Haynesville Shale. As with other competitors, Comstock is seeing drilling costs of approximately $8 million per well.
Since XTO plays in all of the major shale basins in the U.S., it is able to offer a comparison of drilling costs and expected returns based on different prices of natural gas. Haynesville is clearly the most expensive shale play to drill ,with well costs averaging $8 million, but the play is able to overcome these high costs and provide good returns even if gas prices are low.
Berry has drilled and tested four vertical wells in the Haynesville Play. Initial production numbers (shown graphically on the slide below) from four wells, Doyle Harris 6, Hazel Brynes 8, Meek Haynes 8 and Hazel Brynes 9, are not terribly impressive compared to some other neighboring figures shown on the map below.
* Baldwin 14H: 4,620' Lateral 12 Stages 1st Sales est. 4/25/09
* Verhalen A2H: 4,198' Lateral 12 Stages 1st Sales est. 5/07/09
* Blocker Ware 19H: 4,446' Lateral 12 Stages 1st Sales est. 5/30/09
* Blocker Heirs 12H: 4,934' Lateral 12 Stages 1st Sales est. 6/08/09
* TJT Simpson 1H: 4,606' Lateral 12 Stages 1st Sales est. 6/18/09
GMX is pretty excited about these wells. They note that the Blocker Heirs 12H has nearly reached total depth, and all other wells have casing cemented and are ready for completion. The company president Ken Kenworthy stated, "production from these five completions could double our current production in June, 2009." Clearly getting these completions done right is the company's highest priority.
Thursday, April 16, 2009
Additionally, the new wells they are drilling will be flow constrained: "Until natural gas prices strengthen, the company plans to limit production from most newly completed wells in the Barnett and Fayetteville shales to 2 Mmcf per day and in the Marcellus and Haynesville shales to 5 and 10 Mmcf per day, respectively, in addition to the approximate 400 Mmcf per day curtailment."
Yikes. Chesapeake looks at this curtailment as a deferral, which is technically correct. This action accomplishes two things for them: 1) the company can continue to drill new leases to hold them by production and 2) it doesn't have to sell gas at an unprofitable price (which will also help staunch U.S. supply, which should help improve price).
More on Chesapeake's thinking: "The company is able to make this decision because of its strong financial condition and extensive natural gas hedging positions. In addition, because of the steeply declining production profile of new natural gas wells and the upward trending slope of the NYMEX natural gas futures curve, Chesapeake believes deferring production and revenue to future periods with higher natural gas prices creates greater shareholder value than selling production into the current unusually low priced natural gas market."
Chesapeake has resumed 7,000 barrels per day of oil production from previously curtailed oil wells, so I guess it's not all doom and gloom for them. Check out the press release because it has good graphic data on the economics behind deferring production.
Below is a great graphic that summarizes the capital budgets of each company in the Haynesville Shale (size of dot) and how much of that budget is allocated to the Haynesville Play (vertical axis). I love it when someone can depict a lot of information in an easy to understand graphic.
There was also an interesting graphical depiction of the capex behind well cost, showing the that companies are reducing costs by squeezing suppliers and speeding time to market for the gas. The bar chart shows the different components of the costs of a well. While it's nice to see a breakdown, the category titles are vague, and the reader is left wondering whether or not land acquisition costs are included in the well economics.
GMX engaged in a lengthy discussion of hedging. Having locked in good forward selling prices is vital for the survival of the E&P companies. There are a few good slides in the presentation addressing this, but I won’t go into that detail. GMX also comes out saying that they are confident that gas prices will rise (although I read a quote by Dan Pickering of Tudor Pickering Holt & Co, an influential analyst, noting that there are lots of people talking about $2 gas by the fall (note: he didn’t say that he was predicting this)). GMX quotes a Bloomberg article that notes that a survey of 20 analysts sees gas trading at $7/MBtu in January 2010 and January 2010 futures are trading at a 49% premium to the current price.
Finally, I have included a couple of slides showing current drilling activity in the Haynesville Play. Note that the second slide has good detail by company for the Texas side of the play.
In GMX Resources' presentation at the Developing Unconventional Gas (DUG) conference earlier this week, the company published some good detail on the well economics. In a later post, I'll show a chart with pro forma well capital expenses (the cost side). Below are a few slides showing some of the key inputs into the revenue side of things, including decline curves (from a hypothetical well with 5.4 Bcfe EUR and three different cost scenarios), some daily production data on GMX well Baldwin #17H, and some return scenarios based on different cost and gas price assumptions.
Wednesday, April 15, 2009
On the surface, I agree with some of the points made (i.e. fully accounting for the acquisition of the land) and disagree with others (i.e. amortizing the cost of debt in individual well costs), but I'm sure there is a large degree of truth in these analyses. But it is important to note that these analysts are looking at the companies from the outside-in and don't have all of the information the producers have (i.e. real time production information and individual well decline curves), and sometimes analysts place a higher value on reporting something before the crowd or being controversial than they do on being 100% right (they're selling something too!).
Quibbles aside, there is a growing chorus of voices that suggest the economics of the Haynesville Shale may not be as rosy at current prices as we're being led to believe. This isn't a huge surprise. It is well known that these horizontal wells are expensive, and the leasing frenzy created some very high lease costs for producers. Because companies are under the gun to drill on the leases because they only have 3-5 years to hold the leases by production, the price of natural gas isn't going to be the ultimate determination of whether or not they drill.
The underlying suggestion (and statement by some) is that producers are putting out rosy numbers to boost their stock prices. There is a problem here: if this is true and the economics are false, these companies would have their shorts sued off by angry investors. There is certainly a precedent for this and there are entire law firms that do nothing but handle investor class action suits. These companies are smarter than this. Aren't they? OR do they know they are drilling non-economic wells for the purpose of holding leases by production but are producing glowing reports of successes so the stock market doesn't kill them while the price of gas is so low? Ultimately it is good in the long run for a company to spend now to hold the lease rather than lose it because they are too afraid of stock market analysts. OR are these wells actually economically successful and this is a smokescreen by individuals who have a bully pulpit on the Internet? I don't know.
Another bottom line conclusion: this might be a cautionary note for people who are still on the fence about leasing and are on the verge of getting "force pooled." If the returns are not going to surpass the costs, these land owners will get nothing, while the people who did sign leases will at least get their royalty percentage. Royalties are paid upfront. Those who are force pooled get paid on the back end, and if the well is not a money maker the back end is just that.
This is interesting because water use and water rights are going to be huge issues for this country in the 21st century. Water will be especially important as we 1) continue our westward migration in to more arid lands and 2) global warming looms with the potential for unexpected (and heretofore unknown) weather changes. While the Haynesville Shale doesn't have the same water issues as you might see in Colorado or Wyoming, there will be lots of wells that will require a great deal of water. I think it is wise to get ahead of this issue, especially in consideration of the externalities of drilling. If we are to secure our nation's energy future, we will have to drill in the U.S., and that will lead to unintended surface impacts. Best to be proactive rather than reactive. Did you ever see the Jack Nicholson movie Chinatown?
From the Funding Opportunity Announcement:
"Applications for responsible domestic production of oil and natural gas are sought to:
- Develop and demonstrate long-term cost-effective on-site or central processing facility water treatment operational performance and cost data in emerging shale gas plays such as the Marcellus, Fayetteville, Haynesville, or Woodford. Demonstrations shall be conducted at a size that is easily scalable to field operations. - Develop watershed resource flow modeling to support water supply and disposal issues related to siting and permitting for shale gas development.
- Develop cost-effective pretreatment methods to treat or remove constituents from produced water or hydraulic fracturing flowback water to improve downstream treatment and/or re-use options for shale gas development.
- Develop and demonstrate cost effective produced water management methods that use a systems approach, consider lifecycle analysis, demonstrate extraction of high-value products from produced water and create value or additional benefits on the upstream and/or downstream side of the produced water treatment to improve overall economics."
Monday, April 13, 2009
From the Mainland release:
"A number of USGS and US Department of Energy resource assessments have been commissioned over this area over the last decade. All report the deep gas potential of the area, pointing to the Upper Jurassic as a favorable exploration target. According to public records, no wells have been drilled to test the Haynesville Shale formation in the target region to date.
"Company President Mike Newport states, 'We have data that suggests the potential Haynesville Shale in this region could be similar in nature to the gas bearing Haynesville Shale in northwest Louisiana. Our geological team believes that this could be just as productive as the groundwork that’s been laid in the Louisiana play.'"
Friday, April 10, 2009
First, the LA Public Service Commission did not act on Entergy's request to shelve the project for three plus years, but the previous application is pretty much dead (article from New Orleans CityBusiness).
Second, mea culpa - I was railing against the use of coal as the fuel for the converted plant. In fact, it was to be petroleum coke, a refinery byproduct. I got the exact fuel wrong, but it is still a dirty fuel and would be subject to intense upcoming carbon regulation. Entergy is now considering using a combined cycle gas turbine, a more efficient way of generating power with natural gas. Much better!
- The geology and geography of the play is very favorable: the deposit is widely distributed and the shale has good geologic features: little faulting, high pressure, high temperature, naturally occurring porosity, etc. It is also located among existing drilling infrastructure and has access to expanding takeaway infrastructure.
- Goodrich estimates that there are 3.5 million acres in the play and assuming half of it is under a 3-5 year lease scheme that leaves 1.75 million acres that must be drilled or lost. Assuming a 640 acre unit, that implies 2,734 new wells over the next 3-5 years. Right now there are 60 rigs averaging 6 new wells a year. That implies 360 new wells per year, which means that it would take 7.5 years to drill the 1.75 million acres. In other words, the exploration companies are going to need to pick up the pace of drilling because they have a huge incentive to drill and drill quickly.
- It is a very difficult market to drill because capital is so constrained and drilling is very capital intensive.
Bottom line is that while it is very doom and gloom right now, the economics of the Haynesville Play are very appealing (even in this low gas price environment), and the E&P companies need to drill their leases quickly or face losing them starting in the spring of 2012.
Tuesday, April 7, 2009
The 24 hour production rate from the well was a somewhat disappointing 4.1 MMcf of gas and 525 Bbls of load water at a flowing casing pressure of 3,150 psi on an 18/64th inch choke. It's not terrible, but other neighboring wells are doing better. The company believes that the well may have been damaged during drilling or completion and is working with its contractors to see what's going on.
From the company's release: "St. Mary has 10,000 net acres with potential for the Haynesville Shale in Louisiana, 4,200 of which are located in the Spider Field. The remaining 40,000 net acres of the Company’s total 50,000 net acres are located in East Texas. St. Mary’s second Haynesville well has commenced drilling in northern San Augustine County, Texas. After coring the Haynesville section, this well will be drilled down to the deeper Cotton Valley Lime formation for evaluation purposes. St. Mary currently expects to complete the well as a vertical Haynesville test."
We've been eagerly waiting results from St. Mary and are somewhat disappointed (I'm sure they are too!). Hopefully they can get things straightened out and see some better results.
Sunday, April 5, 2009
I was interested to see the list of bill co-sponsors. I'm disappointed that no Congressmen from Louisiana or east Texas helped sponsor a bill that will so significantly help an industry in their state. (Note: the closest sponsor was Rep. Michael Burgess (R) from north Texas - somewhere between the Barnett and Woodford Shales.) The Haynesville Shale should be a significant economic driver, especially for Louisiana, and our politicians should act accordingly.
Friday, April 3, 2009
Souki notes that there were a number of technical issues in 2008 that kept LNG exports from gas producing nations low. Now that these hurdles have been eliminated, there should be a glut of LNG in the market. Based on rates being offered these days, don't expect the price of natural gas to go much above $4 for the near future. If storage facilities fill up, the oversupply might result in gas prices going as low as $2/MMBtu.
As a result of the LNG glut, oversupply will continue to be an issue, but demand is going to be the driver of recovery. As has been noted over and over again, the price of natural gas isn't going to recover until the economy picks up again.
Sure, they don't want to be a slave to energy prices, but it's going to happen to them anyway - it's their business - and on top of that they've got a mechanism in place to pass on the price hikes to their customers.
The project is on hold for at least three years, so I'll get off my soapbox for now.
There has been a huge amount of capital invested in LNG infrastructure to facilitate the import of liquefied natural gas (it arrives in a frozen state and is reheated to a liquid state and then put in pipelines for delivery or storage). The U.S. has an enormous amount of LNG receipt infrastructure and the largest storage capacity in the world. Several long-term projects have recently been completed or will be completed soon. While demand has been low lately, many nations that are drilling for gas and loading it in ships are desperate to sell it to anyone. This could lead to LNG flooding the market. This expectation is probably one of the main reasons the price of natural gas in the U.S. has stayed so low.
The big LNG producers are Algeria, Australia, Indonesia, Nigeria, Oman, Qatar and Russia, as well as Trinidad and Tobago. Some of these are developing third world countries that desperately need the cash. As a result, they will produce it and ship it no matter how low the price is.
The three largest buyers of LNG in the world, Korea, Japan and Spain, currently have plenty of supply on hand because of a mild winter, lower demand and a new natural-gas pipeline in Europe tapping natural-gas fields in Algeria. The excess supply is likely to end up in the U.S. because we have so much supply infrastructure. And it's not just a bunch of foreign companies dumping LNG on our shores. Most of the big integrated oil and gas companies have a presence in the industry. Exxon, most notably, has a very large operation in Qatar.
LNG can have a frightening impact on the price and supply of natural gas for years to come.
Thursday, April 2, 2009
The act was a result of lobbying by T. Boone Pickens, who released a statement that included the following comments:
"America`s national and economic security depends on moving off foreign oil as quickly as possible. Natural gas is the cleanest, most abundant, most economical domestic fuel to replace imported diesel. The U.S. has enough natural gas reserves to last us more than 118 years-we should turn to it as an immediate replacement for foreign oil in fleets and heavy duty vehicles. A battery can`t move an 18-wheeler-the technology isnt there yet. Natural gas buys us a bridge to the future.
"The NAT GAS Act will provide the immediate incentives and long-term stability for companies to seriously move from imported diesel and gasoline to domestic natural gas. Last month, AT&T announced a program to replace 8,000 vehicles - one fifth of its fleet - to run on natural gas. I know that this legislation will motivate many others, from major corporations and municipalities operating fleets to individual owner-operators, to choose a truly American fuel at the pump."
This is a huge step in the right direction. In my opinion, moving to a natural gas standard for vehicles is absolutely necessary for the future of this nation. It is a domestic fuel that is cleaner and less costly that oil.
We as a nation need to think big. I propose a national conversion to a “natural gas standard.”
Our economy is oil-driven, much of it because of our transportation needs. Buses, cars, trains, utility generation – convert these things to a natural gas standard and we would employ a cleaner, more economical fuel and one that can be 100% home grown. The NAT GAS Act (H.R. 1835), proposed yesterday in Congress, is a great way to start this process.
Being a free market economy, the government cannot specifically dictate this change. But the government needs to recognize the potential of natural gas. Right now, the price of gas is low because of high supply and the knowledge that natural gas production is poised to increase dramatically. There is this huge, barely tapped supply beneath our feet. The government can use market incentives to implement a conversion to a natural gas standard. With increases in demand coupled with the increases in supply, the market price for gas should trend towards one that makes production economically feasible while keeping retail consumption at a reasonable price.
It might be tempting to dismiss the Pickens Plan as self-serving, given T. Boone Pickens’ investment in natural gas and wind technology. Same with CNG NOW or the American Clean Skies Foundation, they are both outgrowths of companies trying to commercialize their products to a wider audience. We dismiss these ideas at our own peril, however. I think there is great validity to these concepts.
What can the federal government do to help the market adopt natural gas? It can create incentives for the conversion of oil and coal uses, such as incentives to convert cars and buses to natural gas or develop incentives (tax credits, carbon trading?) to convert aging coal plants to natural gas. To achieve widespread consumer vehicle use, car makers first must see a market for natural gas cars. The government can set targets and create a “carrot” or “stick” incentive for successful achievement of the goal. There also has to be a retail infrastructure to sell natural gas to consumers. This can be achieved through numerous ways that can make both Republicans and Democrats happy.
There is lots of talk about a green jobs revolution, and I think natural gas should be considered part of it. It’s great to have a long-term vision, but we need a solution now. Forget the notion that biofuels will save us. They use up valuable farm land (and throw off the economics of producing our own food!), consume valuable water to grow and require petroleum to harvest. There is no reason to import food so Midwestern farmers can produce overpriced/subsidized fuel for cars. “Clean coal” would be great if carbon sequestration could be achieved and on an economically feasible basis. Right now, it’s not possible. I’m a great believer in solar, geothermal, wind and other alternative energy, but we are far away from a viable solar car or truck (not just a rechargeable battery operated car) and we need a solution now. Energy success will come from a balanced energy portfolio, largely balanced by alternative energy sources, to help offset resource price spikes as well.
Natural gas is the way forward for reasons political, economic and environmental. The United States can become a cartel of one. We live in a global economy, but I see no reason not to be self-sustaining when it comes to our energy needs. There is no one silver bullet solution, but this is the best we've got.
From an article in New Orleans City Business:
"The utility says the move was based on “significant uncertainties in the economics of the project,” stemming from the recent decline in natural gas prices, changing federal energy policies and the current financial crisis.
"The utility estimates that canceling the project will cost about $300 million.
"The Public Service Commission last month rescinded its approval of the project, which called for converting Entergy’s natural gas-powered plant in Montz to run on coal and petroleum coke, directing the utility to present a report showing its plans remained economically feasible.
"Environmental groups have staunchly opposed the project, noting that it would lead to an increase in greenhouse gas emissions and that new federal carbon regulations could mean the project would wind up costing ratepayers significantly more than advertised. "
Wednesday, April 1, 2009
• Capacity for the pipeline is expected to be up to 1.8 Bcf/d
• The scheduled in-service date is fall 2012
• Two proposed compressor stations, each with 35,000 HP of compression