Wednesday, March 31, 2010

Spot price up 14 cents to $3.92

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Tuesday, March 30, 2010

Spot Price Keeps Falling

Down 5 cents to $3.78. Seriously! I'm returning to the real world on Thursday and I expect a rally to welcome me home.
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Sunday, March 28, 2010

Recent Texas Completions

  • Bartley GU #2H, NFR Energy: 7.104 MMcf/day on 27/64" choke; North Carthage Field (Bossier Shale), Harrison Co.
  • James Madison Furrh Gas Unit #2H, Penn Virginia Corp. (no test data reported - I will repost when data appears); North Carthage Field (Bossier Shale), Panola Co.
  • Baggett Gas Unit #1, XTO Energy: 0.327 MMcf/day IP on 18/64" choke; Carthage Field (Haynesville Shale), Shelby Co.
Developmental Actvity:
  • Annie Harvey Gas Unit #1H, Devon Energy; Carthage Field (Haynesville Shale), Panola Co.
  • Cornelius Evans #7H, XTO Energy; Carthage Field (Haynesville Shale), Panola Co.
  • Beckham #7R, Sojitz Energy Venture; Carthage Field, (Haynesville Shale), Panola Co.
  • Werner A #1H, Chesapeake Operating; Carthage Field, (Haynesville Shale), Panola Co.
  • Glaspie Gas Unit #1H, Devon Energy; Carthage Field (Haynesville Shale), Rusk Co.
  • Red River 589 #1H, Common Resources; Carthage Field (Haynesville Shale), Nacogdoches
  • Red River 620 No. 2 #1H, Common Resources; Carthage Field (Haynesville Shale), San Augustine Co.
  • Panthers DU #1H, XTO Energy; Carthage Field (Haynesville Shale) Shelby Co.
  • Aztecs DU #1H, XTO Energy; Carthage Field (Haynesville Shale), Shelby Co.

Saturday, March 27, 2010

Spot Price Down to $3.92

Ick. I go out of internet range for one day and gas can't hold on to $4!

I'm still without internet and the cell network is weak. When I reestablish contact with the real world and have some time, I'll work on rig counts.
Sent from my Verizon Wireless BlackBerry

Thursday, March 25, 2010

Cheniere to Receive LNG Cargo

I was interested to see short article in the morning paper yesterday noting that Cheniere Energy's Sabine Pass LNG terminal will receive a cargo of Qatari natural gas.  The ship, which will arrive April 6, has a capacity of 211,885 cubic meters of LNG.  The snippet states that the ship's capacity represents about 7.8% of the daily U.S. gas production. 

Obviously that's not good news for an already oversupplied situation.  But what struck me as interesting was that the delivery itself was newsworthy.  It shows me how underutilized the terminal is.  Perhaps the greatest fear last year in the domestic gas market was the expected influx of LNG.  While worldwide export capacity has mushroomed, not as much as expected has ended up on our shores.  I can't say that trend will hold, but it's certainly good news for the domestic production industry so far.

Coal Plant Expansion Cancelled

I was happy to see the headline that NRG Energy cancelled its proposed 657 megawatt expansion to the Big Cajun II coal plant in New Roads, LA.  Upon reading the article, I was somewhat disappointed that the reason was an inability to sell power contracts and not the recognition that natural gas is a superior fuel source.  Unfortunately, the market did not prevent Cleco Power from expanding its Rodemacher 3 coal and petroleum coke unit north of Alexandria.

New Louisiana Completions

  • Horn 8 HZ #1, Comstock Oil & Gas: 15.474 MMcf/day IP on 24/64" choke at 6,573 psi; Belle Bower Field, DeSoto Parish; S5/T12/R16; Haynesville reservoir A, serial #240367
  • Spruill 26 #1, Camterra Resources: 8.01 MMcf/day IP on 17/64" choke at 7,600 psi; Caspiana Field, DeSoto Parish; S26/T16/R14; HA res. A, serial #239734
  • Eva Culver Burnley 4 #1, Beusa Energy: 5.912 MMcf/day IP on 12" choke at 8,400 psi; North Grand Cane Field, DeSoto Parish, S4/T12/R14; HA res. A, serial #239973
  • Coval ETAL 19-11-14 H #1, Chesapeake Operating: 8.67 MMcf/day IP on 20/64" choke at 4,860 psi; Spider Field, DeSoto Parish, S19/T1/R14, HA res. A, serial #238613
I have posted an updated list with new completion information gathered throughout the week.

Yikes! Storage +11 Last Week

It is hardly a surprise given the mild weather across the country, but the weekly EIA natural gas in storage number showed an increase of 11 Bcf to 1.626 Tcf.  Last year this week, the storage bottomed out, but the five year average for this week shows a decrease of 37 Bcf.  As a result, the current storage level is 8% higher than the five year average.  Only the East region (-10 Bcf) showed a net gas withdrawal last week.  Not a pretty picture:

To get to the five year average trough of 1.478 Tcf, there has to be a withdrawal of 148 Bcf, a highly unlikely scenario. Unless there is a big (prolonged) cold snap across the country, we are in for a long summer of stories about ballooning gas inventories.  Brace  yourself for the headlines.

If you want to see why storage went up instead of down, take a gander at  these higher than normal temperatures:

I noted high temperatures in the 20's this morning in the Upper Midwest, but it might be too little too late.

Wednesday, March 24, 2010

New Comstock Middle Bossier Well

Today, Comstock Resources announced the completion of a Middle Bossier Shale well:
  • Sustainable Forest 3 HZ #1: 20 MMcf/day IP (24 hour rate) at 7,800 psi; Converse Field, Sabine Parish, Sec. 10/Township 8/Range 13; non-unitized/Middle Bossier, serial #240372
Comstock calls the field South Toledo Bend, but it is officially Converse.  This is Comstock's first completion in Sabine Parish, where the company has 22,404 gross (17,561 net) acres.  Of Comstock's planned 56 gross 2010 wells, six will be drilled in Sabine Parish.  Of the 56, 15 will be Mid-Bossier wells.

Tuesday, March 23, 2010

Water Win-Win

Exco Resources announced this week that it has entered into an agreement with International Paper to buy treated water from IP's paper mill near Mansfield, LA for use in its hydraulic fracturing operations.  The water, which is a byproduct of paper making, is normally discharged into the Red River in amounts up to 12 million gallons per day.  Instead, Exco will build a system of pipes to gather and distribute water as well as a pipeline to deposit "produced" water to a disposal site in Texas.  Because of this deal, Exco will not use aquifer (or river) water and it will significantly cut down on truck traffic.  Sounds like a win-win to me.

Cabot Shows Up

Yesterday, Cabot Oil & Gas announced results from one of its few Haynesville operated wells:
  • King Gas Unit #1H: 19 MMcf/day flow rate (unknown if this is 24 hour peak (likely) or if it is measured over a longer time), North Carthage (Bossier Shale) Field,  San Augustine Co., status #687508
The company will participate in as many as 12 wells this year, including three that are in various stages of completion now.  The CEO stated, "Cabot's acreage seems to be positioned in a second core area for the Haynesville Shale."  Second core - not exactly "home run" talk but still pretty good.  I look forward to seeing the rate for the well that Cabot reports to the state.  The King well is located on the second map below.  The first map shows where it is relative to a bigger picture.  Also note the Walters #1H, a Cabot well that was recently permitted and is spudding this month.

In a presentation yesterday, Cabot also gave its take on the Mid-Bossier Shale.  Cabot has lots of acreage in the northern part of San Augustine Co., TX that might be prospective for both the Haynesville and the Mid-Bossier plays.

Monday, March 22, 2010

Recent Texas Completions

  • Mia Austin #1H, GMX Resources: 7.279 MMcf/day IP on 19/64" choke: North Carthage (Bossier Shale) Field, Harrison Co. (previously self-reported by GMX at 14.1 MMcf/day IP on 20/64" choke)
  • Red River 620 #1-H, Common Resources: 22.084 MMcf/day IP on 29/64" choke; Bossierville (Bossier Shale) Field, San Augustine Co.
Development Activity:
  • Letourneau Gas Unit 6 #29 HH, Anadarko E&P; Carthage (Haynesville Shale) Field, Harrison Co.
  • Verhalen "F" #1H, GMX Resources; Carthage (Haynesville Shale) Field, Harrison Co.
  • Frost-Bryson GU #1H, Exco Operating; Carthage (Haynesville Shale) Field, Harrison Co.
  • Hassell Gas Unit #7H, EOG Resources; Carthage (Haynesville Shale) Field, Nacogdoches Co.
  • Mavericks DU #1H, XTO Energy; Carthage (Haynesville Shale) Field, San Augustine Co.
  • Walters Gas Unit #1H, Cabot O&G; Carthage (Haynesville Shale) Field, San Augustine Co.
  • Lobos DU #1H, XTO Energy; Carthage (Haynesville Shale) Field, San Augustine Co.
  • King GU #1H, Devon Energy; Carthage (Haynesville Shale) Field, Shelby Co.
  • Badgers DU #1H, XTO Energy; Carthage (Haynesville Shale) Field, Shelby Co.
  • Zap DU #1, XTO Energy; Carthage (Haynesville Shale) Field, Shelby Co.

Friday, March 19, 2010

Gas Prices Continue Slide

After an encouraging start to the year, natural gas spot prices have been slowly tanking.  Prices have dropped steadily since hovering in the upper $5 range a month ago.  Today's close at $4.02/MMBtu makes me wonder if $3's should be expected next week.  The trajectory of this year's prices (red line) is ominously similar to last year's (dark blue) on the chart below. 

It could be a long, hot summer of low prices and falling rig counts. 

Detailed Haynesville Rig Counts

By my calculations, the Haynesville Shale rig count increased by four to 165, which represents 80% of the rigs working in north Louisiana and east Texas.  The Louisiana Haynesville Shale rig count showed an increase of two rigs to 125.  I've only got two observations: 1) Sabine Parish has seen the rig count increase from four on Jan. 8 to seven this week, and 2) there is another new entrant, Eagle Oil & Gas (BP entered last week).

On the Texas side, the rig count also went up by two to 40.  EOG added two rigs this month, and Cabot and Southwestern Energy both showed up with new Haynesville locations.  Geographically, Shelby Co. strengthened its lead over Harrison Co. and Nacogdoches Co. added a couple of rigs.

China Building LNG Facilities

Chinese energy giant PetroChina is building four major new LNG facilities along the country's eastern shore, two of which are under construction. What makes this a very interesting development is that the facilities are being built without corresponding supplier contracts. 

The move seems to indicate that PetroChina believes it will be able to procure significant quantities of natural gas on the spot market rather than have to sign up to long-term, expensive supply contracts.  It also means that PC is making a big bet on gas.  This is yet another sign of the importance of natural gas for China's future.  China has been working all the angles to develop gas import capacity, be it through pipelines or LNG facilities. It has also been active in developing its own resources through offshore and shale gas exploration. 

We often hear factoids like, "China is building a new coal plant every week" to suggest that we in the "developed nations" need not worry about our own greenhouse gas emissions (and pollution) until China limits its own emissions.  But all of a sudden China seems to recognize the many benefits of natural gas and might be making real strides to limit its greenhouse gas emissions while simultanously maintaining its economic growth.  I wouldn't be surprised to see China implement a progressive energy policy in the near term while we in the U.S. are still sitting on the sidelines bickering. 

U.S. Rig Count Up Again

The weekly Baker Hughes rig count showed yet another increase in the U.S. rig count, this time up 20 to 1,427.  This is 63% higher than the low achieved in June 2009.  Of the 20 rig increase, 12 are drilling for gas and eight for oil.  By type, there are nine net new horizontal rigs, nine directional rigs and two vertical rigs.

In the Haynesville Shale region, inclusive of other formations, the count was down by two to 207.  The count was unchanged in north Louisiana and down two in east Texas.

I'll work on the detailed count this afternoon.

Iran's Gas, Our Energy Security, Etc.

I recently read an interesting article about the strategic importance of Iran's natural gas reserves.  The article argues that natural gas, not oil, will be the most important fuel source this century and Iran, with its substantial reserves, will be the Saudi Arabia of energy supply going forward.  The article discusses the tenuous relationships between major international powers, especially Russia and China, and how the U.S. might be on the outside looking in where it concerns Iran's gas.

I also believe that gas will supplant oil as the dominant 21st century fuel because of its large supply and the fact that it is available throughout the world.  But as much as the U.S. should be concerned about Iran's activities, it should also be putting the same level of resources and support behind the development of natural gas in North America. 

Unfortunately, that runs counter to the free market system of letting the market pick the right fuels at the right prices.  But I would argue that there is more to it than market economics.  In many ways we have become so used to the global economy that we have outsourced too much.  It is almost like colonialism in that we rely on others manufacture our goods, extract fuel for our use and even answer our phones in call centers.  The good news: North America has lots of natural gas.  We have to realize the strategic importance of our natural gas, both for environmental quality and national security. 

While we will not achieve full energy independence - that's not a rational goal at this point - we can exert greater control over our energy future if we commit to supporting and advancing a balanced approach to domestic drilling.  That means both citizen and governmental support as well as a commitment from energy companies that they are willing to drill for oil and gas in an environmentally responsible way as possible.  E&P companies need to invest in R&D to advance extraction technology to minimize impacts, thus giving the citizens of our country reason not to fear energy development.  Ultimately, it is about stakeholders, not shareholders. 

North America has a tremendous opportunity with natural gas.  Let's not waste it.

March Madness E&P Pool

I'm a big fan of the NCAA men's basketball tournament.  Every year I join a pool put on by some friends of friends in Chicago whom I've never met.  I even won one year (a long time ago). With each passing year I lament how little attention I have paid to basketball results from the previous five months and how my pool selections are mostly guesses.

I read this morning about another pool covering a subject about which I actually have been paying attention. Investment bank Global Hunter Securities has created a pool for E&P companies.  I haven't seen the bracket, but it sounds like a fun way to approach securities analysis. 

While I may have developed more knowledge about the E&P bracket, I'll still be hitting the refresh button relentlessly on to follow my NCAA picks.

Thursday, March 18, 2010

Sour Borscht?

I was amused to read that Russian gas giant Gazprom's CEO Alexander Medvedev expressed deep, heart-felt concerns about the environmental impact of shale gas development.  The only thing he has heart-felt concerns about is the future of his company now that abundant natural gas has created a viable spot market for gas in Europe that has undermined the oil-indexed pricing scheme for his long-term natural gas customer contracts.  It has also taken the U.S. off the table as an LNG customer. 

European shale gas may never catch on in a big way, but not having the U.S. as an LNG customer while at the same time seeing the opening of several huge LNG export facilities in the Middle East, southern Asia and Australia in the next several years means that Europe will have a viable, reasonably priced backup source of natural gas for a long time.  All of a sudden, Russia's captive market doesn't look so captive. 

Recently, Gazprom has had to postpone a large scale natural gas development and many analysts are suggesting that its two new major European gas pipelines might be unnecessary.  While the Medvedev-Putin-Medvedev contingent might be able to control things in Russia, the free market has given them a wake-up call that will require huge structural changes at Gazprom if the company is to be successful given the new gas supply paradigm going forward. 

The question of natural gas drilling's impact on the environment isn't going away any time soon.  Today the EPA announced that it will embark upon a two year project to study the impact of fracking on human health and water quality. (Check out the article if you are in the anti-Arthur Berman camp - he sounds quite rational in his defense of the practice.)  I think hydraulic fracturing is an easy hook, but there isn't much proof of environmental damage there.  Natural gas-related incidents that have occurred were surface spills or were caused by faulty casing underground.  Fracking is not a new technique and the safety of its implementation has only improved over time.  Even if the EPA blesses fracking in 2012, the naysayers will still be out there, possibly led by Alexander Medvedev, if he is still in control of Gazprom.

Forest Oil: Update

Forest Oil held its analyst day today and gave an update on its Haynesville/Bossier activities.  As with most other natural gas independents, Forest has chosen to focus its efforts on a few key plays, one of which is the Haynesville.  The company now has 103,000 gross (72,000 net) Haynesville acres after acquiring leases on 17,500 gross (12,900 net) acres in Shelby and Panola Counties, TX and acquiring a farm-in on 7,700 gross (3,800 net) acres in Sabine Parish, LA. 

The land in Sabine is near a Middle Bossier well for which the company claims a 24 hour peak IP rate of 21 MMcf/day.  I'm guessing this is the Black Stone Minerals LP 26 H #2 well (#240599; Converse Field, Sabine Parish, S26/T14/R8), but I might be wrong.  That's a pretty strong well for the Mid-Bossier and is in line with two of the wells EnCana announced yesterday.

Forest plans to complete 15 Haynesville/Bossier wells in 2010 and operate three rigs in the play, two in Louisiana and one in Texas.  Along with the Mid-Bossier well noted above, the company referenced (but did not name) another well with a 20 MMcf/day 24 hour peak IP rate.

Forest has not been very active in the Haynesville Play to date, but its results in 2010 should shed some additional light on the viability of the southern part of the play, especially in Sabine Parish, and the Mid-Bossier Shale.

New Louisiana Completions

  • Weyerhaeuser 34-16-10 H #1, Chesapeake Operating: 12.84 MMcf/day IP on 22/64" choke at 7,069 psi; Lake Bisteneau Field, Bienville Parish, S34/T16/R10; Haynesville res. A, serial #240104
  • Poole Antrobus 16 H 1, Chesapeake Operating: 11.928 MMcf/day IP on 16/64" choke at 8,794 psi; Caspiana Field, Bossier Parish, S16/T15/R11; res. B, serial #239918
  • Dixie Farm 7-16-14 #1, Chesapeake Operating: 17.234 MMcf/day IP on 22/64" choke at 7,649 psi; Metcalf Field, Caddo Parish, S7/T16/R14; res. A, serial #240273
  • Crnkovic 22 #1, J-W Operating: 4.68 MMcf/day IP on 22/64" choke at 3,600 psi; Caspiana Field, DeSoto Parish, S27/T15/R13; res. A, serial #239838
  • Jackson Davis 23 H #1, EnCana: 14.865 MMcf/day IP on 21/64" choke at 6,669 psi; Caspiana Field, DeSoto Parish, S26/T15/R14; res. A, serial #239578
  • Una Palmer 14 H #1, EnCana: 15.392 MMcf/day IP on 25/64" choke at 7,707 psi; Caspiana Field, DeSoto Parish, S14/T15/R14; res. A, serial #239965
  • El Paso Mgmt Inc. 11 H #1, El Paso: 12.964 MMcf/day IP on 22/64" choke at 6,425 psi; North Grand Cane Field, DeSoto Parish, S10/T12/R14; res. A, serial #240054
  • Diocese of Shreveport 21 #1, SWEPI, LP: 7.1 MMcf/day IP on 8/64" choke at 9,300 psi; Red River-Bull Bayou, DeSoto Parish, S21/T13/R12; res. C, serial #238761
  • Driver 13 H #1, Forest Oil: 12.052 MMcf/day IP on 24/64" choke at 4,200 psi; Woodardville Field, Red River Parish, S13/T14/R10, res. A, serial #239182
  • George McLemore 8 H #1, EnCana: 23.544 MMcf/day IP on 24/64" choke at 8,623 psi; Woodardville Field, Red River Parish, S8/T14/R9; res. A, serial #240005
  • McDonald 1, Eagle Oil & Gas Co.: 10.473 MMcf/day IP on 19/64" choke at 4,950 psi; Converse Field, Sabine Parish, S10/T9/R14; res. A, serial #240049
I will post this information along with other updates from earlier this week on the spreadsheet.

Storage Down Only 11 Bcf

The market isn't going to like this:  the weekly EIA natural gas in storage figure for last week showed only an 11 Bcf drop to 1.615 Tcf.  While still 2.4% better than last year's number, it has fallen to 4.7% behind the five year average. 

Withdrawals were small in the East and West Regions and there was actually a 14 Bcf injection in the Producing Region.

To get to the five year average withdrawal of 1.478 Tcf in two weeks, that means storage needs to drop 137 Bcf, or about 68 Bcf for each of the next two weeks.  That seems unlikely without a big Arctic blast.  It might be a long, hot summer for gas prices.

Wednesday, March 17, 2010

So Where is That 37 MMcf/day IP EnCana Well?

Instead of doing something useful and researching the teams in the NCAA basketball tournament to fill in my bracket, I spent my only free time this afternoon trying to figure out which well from the EnCana investor day presentation IP'd at 37 MMcf/day (24 hour peak rate).  The Q&A session in Calgary yesterday seemed tame with only three or four questions for the U.S. division, and nobody asked the name of the boomer well.  I'm guessing the analysts at the New York presentation on Thursday will be a little more direct and say, "name that well!"

I'm going to hazard a guess.  If you can believe the map,  which is a very soft assumption since it is not a very technical map, I would assume the encircled 37 is in the Thorn Lake Field in Red River Parish.  If that is the case, I only find two permitted but unreported EnCana wells in that area, the Edgar Cason 12H (#239984) and the Edgar Cason 13H (#240015).  The type curve for the big well was not time oriented, so it is difficult to estimate how many days it has been flowing, but I eyeball that it has produced 750 MMcf to date. Guesstimating a flow rate of 28 MMcf/day, that would imply about 27 days of data.  I don't know the date of the type curve, but I assume it is fairly recent. That would imply the well was completed about 30 to 45 days ago, +/- early February.  From SONRIS (which is dated) and Baker Hughes rig reports, the Cason 12H well is in-test, while the 13H was still drilling as of January 29, 2010.  Therefore, I guess the boomer is the Edgar Cason 12H #1.

I hate to get all Hardy Boys on you, but I like a mystery as much as anybody else.  But I reserve the right to be dead wrong, especially since I guessed that the map information was correct. Anybody else have an idea?  Post a comment or email me (haynesvilleplay (at)  Let's see if the boys in New York ask for specifics.

EnCana: Haynesville Update

EnCana's analyst day shed light on the company's strategy and successes in the Haynesville Shale.  The 2010 strategy is four-fold:
  1. Drill for land retention
  2. Test more of the Mid-Bossier Shale (discussed in previous post)
  3. Create a "gas factory" pilot project in Q2
  4. Test lands in the southern part of the Haynesville Play with step-out drilling in the southern portions of DeSoto and Red River Parishes, LA along with tests in Shelby, Sabine and San Augustine Co., TX
Of these priorities, land retention is at the top of the list.  In the Q&A portion of the presentation, an EnCana exec said management is "infatuated with (the) land retention strategy in the Haynesville."  It should be.  EnCana declares the Haynesville Shale to be its top performing asset in the company's portfolio.  EnCana plans to drill 225 gross wells in 2010 (109 net).  EnCana, which currently operates 23 rigs in the play, will average between 20 and 25 for the year.  Partner Shell (a.k.a. SWEPI, LP) will operate between seven and ten rigs.  EnCana's 2010 Haynesville capital budget will be $1.191 billion, and it expects to average 325 MMcf/day of gas production in 2010.

The "gas factory" concept has been discussed on these pages before.  Briefly, the concept is to drill multiple wells from the same pad. Ideally, a pad located near a section line could drill eight wells in each section for a total of 16 wells per pad.  This assumes 80 acre spacing, but EnCana is looking at the possibility of 40 acre spacing.  The illustration below shows a schematic drawing for one section. If EnCana drills two sections from one pad, you would see a mirror image below.

The gas factory approach saves time and money, as EnCana can realize economies of scale and limit movements of equipment and personnel.  It can also use a single pipeline and concentrate its water sourcing and disposal activities.  EnCana has used the gas factory design with success in the Piceance formation in Colorado, if only because there are so few drilling sites in that mountainous region.  By example, from one 4.2 acre pad, EnCana is able to drill 52 wells.  Skeptics like Arthur Berman have argued that the Haynesville Shale is not conducive to gas factory operations because of the play's geology.  I guess by this time next year we will have a really big data point from EnCana to measure the concept's success.

In terms of  results, EnCana has been adjusting its completion formula in recent months to complete wells with longer laterals and more stages, two factors it feels drive better recoveries (see slide below). 

As a result of improved completion techniques, EnCana has adjusted its Haynesville type curve upward from 5 Bcf EUR to 7.5 Bcf EUR.  The curves from the most recent wells completed over the past 90 days shows this improvement.  The first thing that jumps out is the Big Mamou 37 MMcf/day 24 hour peak IP well drilled in NW Red River Parish.  The company didn't name it, but I'm sure we will be hearing more about it shortly.

Management noted that the company previously had been constrained by treating capacity, but through supporting third party gathering and treating efforts it can now flow wells unconstrained at 25 MMcf/day at 7,000 pounds of pressure.  Average 30 day initial flow rates have increased from 8.2 MMcf/day in Q4 2008 to 16.9 MMcf/day in Q1 2010, and the company hopes to edge this number closer to 20 MMcf/day.  As a point of reference, 17 MMcf/day for 30 days yields half a Bcf of gas.  At the same time, costs are coming down through efficiencies.  A couple of recent wells were completed for $7.5 million.

In one more concept that needs to be promoted more widely around the gas industry, EnCana pledged to eat its own cooking (my term, not theirs).  In other words, the company will use natural gas powered rigs, drive CNG vehicles and build a CNG filling station to service the region (I'm not sure if it will serve outside users).  Other companies, like Chesapeake and Exco, have supported similar efforts with CNG, but for natural gas to become more widely used, the industry has to take the lead in both showing the way and helping build retail infrastructure (like filling stations).

Mid-Bossier Shale: Update from EnCana

EnCana is holding its analyst day this week, and the company's presentation is full of good information that I will mine for several posts in the next day or two.  I'll start with the update on the Middle Bossier Shale.  Recall that the Mid-Bossier is a few hundred feet shallower than the Haynesville Shale and overlays the Haynesville formation in the southern part of the play. 

EnCana was one of the first companies to publicize the Mid-Bossier and to date seems to have done the most work in the play.  Most E&P companies with leases in the Haynesville/Mid-Bossier overlay are focusing on drilling the deeper Haynesville property to hold the acreage with an eye towards developing the Mid-Bossier at a later date.  I view the Mid-Bossier as essential to EnCana's stock market value proposition.  Since the company split into two with the high growth/higher risk E&P business staying EnCana and the slower growing businesses like oil sands and refining becoming Cenovus, EnCana is eager to boost the growth of the E&P business, with a goal of doubling the size of the company in a few years.  To do that, it needs to make a stronger effort to prove and quantify the resource held in the Mid-Bossier Shale.

Based on a few producing wells, EnCana is excited about the opportunity in the Mid-Bossier.  Here is a slide showing the overlap of the the core portions of the Mid-Bossier and Haynesville Shales (where 100+ Bcf is found in each zone) that is oozing with excitement because of EnCana's large leasehold in western Red River and northern Sabine Parishes.  EnCana (and others) could realize significant cost savings through multi-well drilling from a single pad if it can access both the Mid-Bossier and Haynesville from a single pad.

The company estimates that it holds 100 to 200 Bcf per section, compared to 175 to 225 Bcf per section for the Haynesville Shale.  Well results have been strong, but production data has been inconsistent - mostly because there are so few data points - as shown on the type curves below.

A number of people have asked me about how to spot Mid-Bossier wells.  Unfortunately, it seems as though the best way is through anecdotal evidence from companies.  As far as I can tell, there are about ten flowing Mid-Bossier wells.   Below is EnCana's map, but it doesn't seem 100% complete.

EnCana provided some good completion data on some of the company's recently completed but unreported Louisiana wells:
  • Jimmy Ray Brown 9 H #1: 20 MMcf/day IP (24 hr. peak rate); Pleasant Hill Field, Sabine Parish, Sec. 9/Township 9/Range 12; Mid-Bossier, but classified as Haynesville reservoir A; serial #240294
  • Walker LTD PRT ETAL #2-ALT: 22 MMcf/day IP (24 hr. peak rate); Bracky Branch Field, Red River Parish, S28/T13/R9; Mid-Bossier, but classified as Jurassic res. B; serial #240119
  • Douciere 13 #1, operated by SWEPI, LP: 8 MMcf/day IP (24 hour peak rate); Trenton Field, DeSoto Parish, S13/T11/R13; Mid-Bossier, but classified as Jurassic res. A, serial #239225 (this well was completed a while back but still shows as "waiting on pipeline")
  • Colbert Lands 16 H #1: 4,252 MMcf/day IP on 11/64" choke at 7,200 psi; Bracky Branch Field, Red River Parish, S16/T13/R9; Mid-Bossier, but classified as Jurassic res. B, serial #238108 (this is an older well) 
Based on information in the presentation, I also made the call to reclassify the previously noted EnCana completions as Mid-Bossier:
  • Brown SW Min 10 H #1-ALT: 8,021 MMcf/day IP on 28/64" choke at 6,125 psi; Bracky Branch Field, Red River Parish, S10/T13/R10; Mid-Bossier, but classified as Jurassic res. A, serial #239707
  • Black Stone Min 12 H #1: 13,900 MMcf/day IP on 21/64" choke at 8,144 psi; Bracky Branch Field, Red River Parish, S12/T13/R10; Mid-Bossier, but classified as Haynesville res. B, serial #238131
These wells will show up on the next detailed completions list, likely to be revised on Thursday. 

More to come later on EnCana...

Tuesday, March 16, 2010

Colorado Taking Steps to Get Rid of Most Coal-Powered Electricity

Last week, Xcel Energy, a major western utility that provides power for a large part of Colorado, including the highly populated Front Range area, announced that it has struck a prospective deal with the state "to sharply reduce pollutants by retiring, retrofitting or repowering Front Range coal-fired power plants by the end of 2017 and replacing them with facilities fueled by natural gas and other lower- or non-emitting energy sources." 

The deal is in the form of proposed legislation supported by Governor Bill Ritter, a group of legislators and environmental groups called the "Colorado Clean Air-Clean Jobs Act," which will be put in front of the Colorado legislature this year.  As part of the legislation, Xcel will evaluate retrofitting or retiring 900 megawatts of coal-fired generating capacity.  It will also work with the state to develop a plan to reduce nitrogen oxide emissions from coal-fired plants by 80% over the next eight years. 

Interestingly, the press release and some media coverage was notably silent about what's in it for Xcel.  How will the capex for the new plants and retrofits be funded? Obviously ratepayers are responsible for most power plants, but I'm sure there's a sweetener in there for Xcel.  Since the legislation is called the Clean Air-Clean Jobs Act, I'm sure the state offered Xcel something in return.

Whatever the case, it looks to be a good deal for the gas industry if it passes.  Colorado has a very large gas reserve and the state's population should continue to grow strongly over the coming decades.  I spent a few days in Denver for a convention a couple of years ago.  My lingering memory was of blue clouds of pollution in the afternoon and enormous coal trains passing within blocks of the convention center.  Switching from coal to natural gas power could make both of those memories...well, a memory in short order.

Detailed Louisiana Rig Count

I have finally completed the detailed Louisiana rig count for March 12.  There was a ton of activity, but the summary numbers barely budged.  The count stayed the same at 123.  Combined with the Texas count, the weekly Haynesville rig count was 161, which is down one from last week.

Monday, March 15, 2010

Mainland Sells Out of Haynesville

Mainland Resources, which lucked on to some Haynesville acreage back in 2008 has agreed to sell its Haynesville leases for approximately $27 million to an  unnamed buyer.  The purchase only involves strata 100 feet below the Cotton Valley formation for 2,903 gross acres (1,162.3 net acres at a 40% working interest) in the East Holly Field in DeSoto Parish, LA.  The purchase price amounts to $17,500 per net acre plus about $6.8 million in past drilling and completion costs.  Mainland will retain rights to Cotton Valley and above.  The company will use the proceeds to retire debt and pursue both a Cotton Valley/Hosston program and its Buena Vista project in Mississippi. 

Not bad for a $687,596 investment two years ago. 

Texas Detailed Rig Count

I'm finally getting to the detailed rig counts for last week.  I started with east Texas, which saw a seven rig decrease overall but only a one rig decrease in the Haynesville Shale, from 39 to 38.  Last week I accidentally double counted a rig (sorry), so the table below reflects the correct data from this week and last.

I'm working on Louisiana, but it might not be posted until tomorrow.

Interesting Marcellus Transaction

I was very interested to see the announcement this morning that CONSOL Energy, one of the largest coal producers in the U.S., has agreed to buy Dominion's gas-focused E&P business for $3.475 billion in cash.  CONSOL already has a gas subsidiary, CNX Energy, but this purchase signals a strategic shift to increase the company's exposure to natural gas in a big way, as gas will represent 35% of the company's pro forma revenue. 

Dominion's E&P business is focused in the Appalachian region and has just under 500,000 acres in the Marcellus Shale (98% held by production) in Pennsylvania and West Virginia.  Combining that with CNX's acreage gives CONSOL/CNX 750,000 Marcellus acres.  Along with the acreage, CNX bought Dominion's E&P business, which is one of the oldest in the region.

CONSOL's press release makes a big effort to show that the company is a "diversified energy company with a balanced portfolio of coal and natural gas."  The transaction makes lots of sense from a geographic perspective since both coal and gas are +/- 5,000 vertical feet apart under the much of the region.  But most importantly for CONSOL, it likely represents a nod to the fact that thermal coal is not the future, especially because the largest part of CONSOL's current business is supplying coal to power plants. On the surface, it looks like a smart strategic move.  I wonder if any of the other Big Four coal companies will make a similar move.

Devon's Yard Sale Going Well

Along with Petrohawk, Devon Energy is unloading a bunch of assets so it can focus more on its North American onshore drilling program.  Last week, Devon announced that BP has purchased the company's deepwater Gulf of Mexico leases, its Brazilian business and its interest in the ACG field in Azerbaijan for $7 billion.  Along with the boatload of cash, Devon also transferred some expensive drill leases to BP.  As part of the deal, Devon also bought into BP's Kirby oil sands project in eastern Alberta, Canada for $500 million with a commitment for an additional $150 million of carry.  Devon will take over as operator of the Kirby project, which appears to offer some synergies with Devon's Jackfish properties immediately to the south.

This sale combined with an earlier sale of Gulf of Mexico deepwater assets has brought the running total for Devon's asset sale to $8.3 billion.  With some Gulf of Mexico shelf interests, offshore Chinese interests and some smaller international properties still on the block, Devon looks to clear between $9.6 to $10.3 billion from its yard sale, which eclipses the originally announced estimate of $4.5 to $7.5 billion.  Devon either set the bar really low or the deal making environment is stronger than expected.

Proceeds from the sale will be used to fund E&P capital expenditures as well as to reduce debt (happy bankers) and buy back stock (happy shareholders).  Devon's capital budget for 2010 is $4.4 to $4.8 billion, and about 40% ($1.7 B to $1.9 B) is allocated to gas shales.  Along with the Haynesville Shale, Devon owns interests in the Barnett, Woodford and Horn River shales.

Devon's asset sale is similar to Petrohawk's in that it allows Devon to focus more attention and capital on its onshore activities. But the big difference from Petrohawk is that the assets being sold are very different from a risk/reward perspective.  Devon is selling high risk/ high reward projects that might yield a future home run but will require significant capital investment and uncertainty, while Petrohawk is selling dependable near-term cash flowing assets.  But what they are both doing is concentrating their companies' risk in fewer assets. I don't mean to sound judgmental, but it's a pretty big strategic shift for both companies.

LA Mineral Board March Lease Auction Results

The Louisiana Mineral Board held its monthly sale of state mineral leases last week. For the seven properties in the Haynesville Shale region, the winning bids varied from $1,850/acre to $18,214/acre, but the average lease bonus was $9,502 across the seven parcels.  All winning bids included a 25% royalty.

The average lease bonus is slightly lower than the average for February ($10,871) and January ($9,807), but it is difficult to compare results because the quality and quantity of lands being autioned varies from month to month.  The main take-away is that the average bonuses have been in the $9,500 to $10,800 range for the past three months, which is a fairly tight range.  Please keep in mind that the bids listed below were the highest bids and therefore the winning bids. Other bids may have come in lower.

GMX Resources: Update

GMX Resources reported its first quarter earnings last week.  Because the company's acreage is highly concentrated on the Texas side of the Haynesville Shale, I look at GMX as a "suicide player" in the Haynesville.  The company, which is a relatively small player, doesn't have a terribly strong balance sheet and was forced to cut back from seven operating rigs to one when commodity prices were crushed and the financial markets were still locked.  GMX added a second rig in October 2009 and added a third in January 2010, but its operations are still somewhat scaled back and increasingly concentrated in the Haynesville Play.

GMX completed 11 Haynesville wells in 2009.  The average 30 day production was 5.136 MMcf/day, but the company reported that it has been operating its wells on restricted chokes "to avoid excessive closure pressure during early flow time."

The company also reported that it has started using a larger diameter wellbore, moving from 4 1/2" to 5 1/2".  As GMX says:
"The larger 5 1/2" casing facilitates a reduction in perforation cluster spacing which will improve the capability of stimulating the entire lateral length, all the while keeping the total number of frac stages at current levels. Data suggests that improved well performance is related to the reduction in perforation cluster spacing and with the larger casing, improved well performance is anticipated without an increase in stimulation cost."
The wider diameter wells take longer to drill at this point (44 days vs. low 30's/high 20's for narrower hole), but GMX expects to lower the drilling time to around 35 days.  The company began this program on December 28, 2009 and the first wells, Verhalen "D" #3H and Bosh 19H, should show results in April 2010.  Blocker Heirs #20H, Verhalen "E" #6H and Blocker Ware #8H are currently drilling using this new technique.

GMX's capital budget for 2010 is $175 million, the bulk of which will be spent drilling Haynesville wells.  The company expects to drill 20 Haynesville wells and two Cotton Valley wells.  GMX is actively looking at potential transactions to lower the capex spend, including participation agreements, farm-ins and acreage exchanges.

GMX uses an interesting term to further delineate the Haynesville Shale acreage, "capital core."  The first map below shows the "capital core" with an overlay of the current rig locations as of 3/8/10 and GMX's leasehold.  The second map is presented to show GMX's belief in the strength of the western side of the "capital core."  Since all of the company's Haynesville property is here, let's hope they believe in it.

GMX reported one well that I have previously not noted:
  • Verhalen "E" #1H: 8.3 MMcf/day IP (24 hour peak) on 18/64" choke at 3,870 psi; North Carthage Field (Bossier Shale), Harrison Co.

Petrohawk Yard Sale: Two Down, One to Go

Petrohawk announced today that it has found a buyer for its producing assets in the Terryville Field in northern Louisiana.  The company agreed to sell the assets, which are located in Claiborne and Lincoln Parishes for $320 million to a private company. 

As we've noted before, Petrohawk is selling assets to concentrate its attention and capital on its shale gas properties, specifically the Haynesville and Eagle Ford Shales.  The company is raising capital by selling future cash flow.  The bet is that Petrohawk can reinvest the new capital and earn a greater amount of future cash flow.  The Haynesville Shale is a strong opportunity, but Petrohawk is exposing itself to risk in the short-term, especially if natural gas prices tank badly. 

Sunday, March 14, 2010

Louisiana Completions (From Last Week)

Last week I added a bunch of Louisiana completions to my database, but I didn't have time to post the results, so here they are:
  • Huckabay 31 #1, Petrohawk Operating Co.: 8.613 MMcf/day IP on 14/64" choke at 8,450 psi; Red River-Bull Bayou Field, Red River Parish, Sec. 6/Township 12/Range 10; Haynesville reservoir B, serial #239975
  • Leroy Adcock 17 H #1, EnCana Oil & Gas (USA), Inc.: 17.003 MMcf/day IP on 22/64" choke at 9,942 psi; Martin Field, Red River Parish, 17/T13/R8; res. A, serial #239794
  • Tensas Delta A #1, Petrohawk (WSF): 8.684 MMcf/day IP on 14/64" choke at 8,178 psi; Elm Grove Field, Bossier Parish, S1/T15/R12; res. A serial #239852
  • Conger 15-18-12 H #1, Chesapeake Operating: 6.502 MMcf/day IP on 12/64" choke at 6,520 psi; Haughton Field, Bossier Parish, S15/T18/R12; res. A, serial #239947
  • Hosier 35-15-11 H #1, Chesapeake Operating: 10.296 MMcf/day IP on 14/64" choke at 8,921 psi; Swan Lake Field, Bossier Parish; S35/T15/R11; res. A, serial #240019
  • Alexander 34-16-16 H #1, Chesapeake Operating: 8.311 MMcf/day IP on 20/64" choke at 6,555 psi; Greenwood-Waskom Field, Caddo Parish, S34/T16/R16; res. A, serial #239761
  • Bowlin 35-16-16 H #1, Chesapeake Operating: 11.179 MMcf/day IP on 22/64" choke at 6,550 psi; Greenwood-Waskom Field, Caddo Parish, S35/T16/R16; res. A, serial #240251
  • Bagley 33 H #1, Coronado Energy E&P Co., LLC: 11.630 MMcf/day IP on 17/64" choke at 6,650 psi; Bethany Longstreet Field, DeSoto Parish, S33/T14/R16; res. A, serial #240254
  • EDWL 12-14-15 H #1, Chesapeake Operating: 10.032 MMcf/day IP on 16/64" choke at 8,514 psi; Caspiana Field, DeSoto Parish, S12/T14/R15; res. A, serial #240155
  • Dalton 4 #1, Camterra Resources, Inc.: 6.172 MMcf/day IP on 14/64" choke at 7,350 psi; Caspiana Field, DeSoto Parish, S4/T15/R14; res. A, serial #239821
  • L E Lum ETAL 11 #1, Indigo Minerals, LLC: 2.106 MMcf/day IP on 64/64" choke at 1,075 psi; Logansport Field, DeSoto Parish, S11/T12/R16; res. A, serial #240018
  • Funston 1-12-16 H #1, Chesapeake Operating: 16.603 MMcf/day IP on 22/64" choke at 8,552 psi; Logansport Field, DeSoto Parish, S1/T12/R16; res. A, serial #239885
  • Briarwood 26 H #1, Chesapeake Operating: 12.852 MMcf/day IP on 22/64" choke at 7,650 psi; Red River-Bull Bayou Field, DeSoto Parish, S26/T13/R13; res. C, serial #240048
  • Sustainable 23 #1, SWEPI, LP: 6.000 MMcf/day IP on 8/64" choke at 8,800 psi; Red River-Bull Bayou Field, DeSoto Parish, S23/T13/R13; non-unitized, serial #239246
  • Carmel Lake 16 #1, SWEPI, LP: 9.701 MMcf/day IP on 18/64" choke at 9,701 psi; Red River-Bull Bayou Field, DeSoto Parish, T16/T13/R12; res. C, serial #239680

New Texas Developmental Activity

I did not note any new completions in Texas this week, but I did see the following developmental activity:
  • Findley Gas Unit #1H, Penn Virginia Corp.; Carthage (Haynesville Shale), Harrison Co.
  • Rollie Simms Deep GU #1H, NFR Energy; Carthage (Haynesville Shale), Harrison Co.
  • Blocker Ware #23H, GMX Resources; Carthage (Haynesville Shale), Harrison Co.
  • Sempra Energy Gas Unit II #1H, XTO Energy; Carthage (Haynesville Shale), Panola Co.
  • Harris Stewart #1H, Noble Energy; Carthage (Haynesville Shale), Shelby Co.
  • Husband 1, Valence Operating; Carthage (Haynesville Shale), Nacogdoches Co. (this permit also covers Cotton Valley, Travis Peak, James and Petit, so I'm not sure what the ultimate target will be)
  • Grizzly 1, Crimson Exploration; Carthage (Haynesville Shale), San Augustine

Friday, March 12, 2010

Rig Count Mixed Again

The weekly Baker Hughes rig count showed another increase in U.S. rig count, rising by 11 to 1,407.  Almost all of the new rigs, ten, are drilling for oil wells, while one is drilling for gas.  Of the net 11 rig increase, there was an increase of 18 vertical wells and seven horizontal wells, while there was a decrease of 14 directional wells.

In the Haynesville region, inclusive of other formations, the net rig count was down two to 209, with a four rig increase in north Louisiana and a six rig decrease in east Texas.

I will work on the detailed rig Haynesville count but it probably won't be published until the end of the weekend.

Thursday, March 11, 2010

Storage Down 111 Bcf

The weekly EIA working gas in storage number decreased by 111 Bcf to 1.626 Tcf.  This decrease is almost exactly in line with last year (-111 Bcf) and the five year average (-109 Bcf) for this week.  The current storage level is 4.2% below last year's number and 1.2% higher than the five year average. 

Targeting the five year average of 1.478 Bcf to exit the withdrawal season at the end of March, that means we need to see a 147 Bcf withdrawal over the next three weeks, or an approximate average of 50 Bcf per week.

All things considered, the storage withdrawal number was pretty good.  Last week's cold weather seemed mostly in the southeast, where there is a lot of coal-generated power. 

Wednesday, March 10, 2010

New Louisiana Completions

There were 15 new Louisiana completions that I noted today.  I updated the spreadsheets (the new information is in a lovely salmon color), but I don't have time to list them all in this post.  I'll do it in the next few days.

I Feel Another Coal Rant Coming On

Coal is getting under my skin again. Two things in particular are bothering me: coal ash and the myth of “clean coal.”

In catching up on articles this past weekend, I read an article in Sierra magazine about the problems associated with the coal ash ponds created by the huge coal-fired electric plant in Colstrip, MT. As coal is burned, it leaves behind a certain amount of residue, but unlike the wood in our fireplace, coal ash is filled with dangerous heavy metals and toxins, including mercury. Some of the ash is turned into building materials, but much of it wastes away in holding ponds along with sludge from srubbers that remove a portion of the pollutants from the smokestacks. Unfortunately these ponds lead to even more pollution as the chemicals in the water both leech into the groundwater and evaporate into the air.

I also saw a piece in the New York Times about the difficulties in cleaning up the massive coal ash spill in Kingston, TN. This massive spill in 2008 made us all aware of the dangers of these holding ponds. Outside of the sheer magnitude of the cleanup (the article notes that the disaster spilled “5.4 million cubic yards of coal ash across 300 acres into the Emory River and an affluent shoreline community near Knoxville(,) enough ash to cover a square mile five feet deep.”), the cleanup crews are having trouble finding appropriate dumping grounds for the sediment. The spilled ash is horrible stuff, filled with heavy metals that can lead to cancer, and not many landfills can handle it, especially not in these massive volumes. The one landfill that does take the sludge, located in tiny Uniontown, AL, has received so much rain lately that it has to deal with 100,000 gallons of tainted water per day as a result. The cleanup contractors are looking across the southeast for sites to process the tainted water, including in my home state of Louisiana. That situation is not yet resolved.

It is hard for me to believe the environmental furor over hydraulic fracturing for natural gas, a practice that has not created a single documented instance of groundwater contamination, when there are hundreds of these toxic retention ponds at coal plants all over the country, many of which are classified by the EPA as “high hazards” or disaster sites (see map below). I can certainly understand the desire to avoid other potential new hazards, but the outrage directed towards fracking, especially in the Northeast, would be much better spent preventing the spread of toxic pollution associated with coal-fired power plants.

Which brings me to the oxymoron of “clean coal.” It makes my head hurt to try to find two words that go less well together. That large scale carbon sequestration and storage (CSS) has not yet been demonstrated is fairly well known, but what happens if it is finally possible? The amount of carbon captured for storage from coal generating plants would be huge. We would quickly run out of places to store it. On top of that, coal plants would have to burn lots more coal just to power the CSS process. Talk about a win-win for the coal industry!

Even if the carbon problem could be solved, if only partially, we’d still have coal plants spewing other greenhouse gases and toxins and leaving behind thousands of tons of coal ash.

I’ve said it before: the coal industry is like the cigarette industry. It creates a profitable but toxic product. It invests as much in lobbyists and lawyers as the product itself. Its survival is based on stall tactics, but the longer it survives, the more people it poisons.

“Clean coal” is a fictional tool created by the coal lobby to further the industry’s existence. In truth, the only clean coal is that which is left in the ground. While the natural gas lobby has made some strides in Washington, the coal boys are still kicking. These days they have a new best friend in Warren Buffet, whose company, Berkshire Hathaway, acquired Burlington Northern Railway, the company that powers many of those miles long coal trains snaking across the west. When the bulk of your revenue comes from hauling coal, you want to keep the strip miners scraping and the electricity plants burning coal. It makes Burlington Northern’s “The cleaner road ahead” media campaign seem quite ironic:

As the advocacy battles heats up in D.C. this spring as energy policy is debated, we will hear no end about “clean coal” and just how wonderful coal is. My thoughts immediately will shift to toxic coal ash and emissions filled with CO2, mercury, SOx, NOx and the like. I sure hope policy makers share these same thoughts.

Gas Intrudes on "Oil Day" at CERAWeek Conference

At the annual CERAWeek energy conference in Houston, oil has long been king.  The first day is dedicated to oil with gas and power being relegated to later days of the conference.  The Financial Times pointed out that at this week's conference, natural gas intruded on oil's day

The occasion for the intrusion was a speech by Jim Mulva, CEO of ConocoPhillips called "Natural Gas - The Gift," which touted gas as not just a "bridge fuel" but a major component of our nation's energy future.  Mulva's presentation was in some contrast to Energy Secretary Stephen Chu's speech in which Chu praised natural gas as a bridge fuel towards renewable fuel sources.  Chu also acknowledged that it will be very hard to replace oil as a transportation fuel because of its physical advantages such as energy density and ease of transport.

Many gas fans complain about remarks by Secretary Chu, but I'm relatively pleased with his progression from being "agnostic" about the best energy sources for our future to at least singing the praises of natural gas.  We quickly forget that a very important role of the government in developing policy and helping fund development of our nation's energy future is walking the fine line between supporting the best fuels and technologies and picking the winners.  The latter is a definite no-no.

Tuesday, March 9, 2010

EIA Short-Term Outlook

The Energy Information Administration released its monthly Short-Term Energy Outlook for the U.S. today.  Below are some highlights for gas fans:
  • Consumption:  The EIA estimates that first quarter 2010 natural gas consumption will be 3% higher than last year and 17% higher than the five year average.  Last month's report estimated a 1.3% year-over-year decline for the first quarter.  The big difference has been cold weather, especially in the south, where natural gas use for power generation was up 10% over last year.
  • Production:  The EIA estimates natural gas production will decrease by 2.7% in 2010 and increase by 1.1% in 2011.  We'll see about that one.  The report's author didn't sound too confident about that projection either.
  • LNG imports:  While LNG imports are expected to be higher in Q1 2010 compared to last year, LNG imports for the year are expected to decrease by 45%, or 560 MMcf/day.  That's an interesting, although not unsurprising, observation given the amount of LNG export infrastructure coming online in key export nations this year.  Last year, experts predicted a tidal wave of LNG in 2010, but with the shale gas boom causing frightening storage constraints in the U.S., it is likely that the LNG exporters will continue to look elsewhere for customers.
  • Gas in storage:  The EIA expects the quarter to end with a working gas in storage balance of 1.549 Tcf, which is 3.5% higher than the five year average.  Given the current balance of 1.737 Tcf, that represents a net withdrawal of 188 Bcf over the next few weeks. 
  • Price: The EIA estimates that the Henry Hub spot price for gas will average $5.17/MMBtu in 2010 and $5.65/MMBtu in 2011. 

Callon Petroleum: Update

I listened to the Callon Petroleum conference call to get an update on the company's efforts in the Haynesville Shale.  Recall that Callon, which had concentrated its business in the Gulf of Mexico, changed its strategy in 2009 to refocus on terrestrial activities in the Permian Basin and the Haynesville Shale. 

Callon leases 404 net acres (70% of 577 gross acres) in Bossier Parish.  The company hasn't filed for any permits, but eyeballing the map below, it looks like the acreage is in Sec. 1, Township 16, Range 11 (let me know if I'm wrong - unfortunately, the big picture map and the blow-up don't really match, so it's hard to tell).  No Haynesville units have been formed for this section to date. 

Callon's acreage should host seven wells, and the company has contracted a rig to start drilling two wells before the end of the year (Callon will be the operator).  The rig has two wells to drill for other companies before it gets to Callon, so don't expect Callon's first well to spud before summer.  The company expects to have both wells completed and producing in the fourth quarter.  Callon's current plans are to complete two wells per year on this acreage for the next three years.

In terms of economics, Callon estimates well costs of $9.0 million and estimated ultimate recoveries (EUR) of 6.4 bcfe per well.

Monday, March 8, 2010

Cubic Energy Back Out of the Ditch

Kudos to Cubic Energy. The company announced today that it is back in compliance with the AMEX stock exchange.  For the past seven months, the company has fought being de-listed from the exchange, which it only recently joined after trading as an over-the-counter bulletin board stock. To salvage its listing, the company renegotiated its debt agreement with Wells Fargo and it acquired $30.9 million in drilling credits from Tauren Exploration.  Not a lot of companies that fight de-listing win, so it's a good day for Cubic.

(I never quite understood the drilling credits transaction, which occurred back in November 2009.  The press release was clearly written by lawyers who had no interest in informing the public of the details behind the affiliated transaction, as both Cubic and Tauren are controlled by Calvin Wallen, III.)

Cubic got in trouble this summer when Wells Fargo reduced its fully drawn $20 million borrowing base to $7.5 million back when natural gas prices were in the $2 range.  The new debt agreement actually increases the company's borrowing base to $25 million.  The rate stayed the same (prime +2) but the company had to issue Wells five million warrants to purchase Cubic stock at $1 (it closed today at $1.32).  I'm sure there were also lots of banking fees involved to make it even more painful for Cubic.

Unfortunately, being an independent E&P company almost invariably makes you a borrower in this business environment.  Bad economic times coupled with a poor commodity price environment make you a victim-in-waiting unless you have a very strong balance sheet.  With the incredible amounts of spending on the Haynesville Shale over the past couple of years, most of the active producers had to fund these expanded operations by selling equity and taking on new debt.  The trick now for these companies is to generate positive cash flow through operations rather than borrowing.  With the rapidly sinking price of natural gas, it gets harder every day.

A Missing Louisiana Completion From Last Week

  • Huckabay 31 H #1, Petrohawk Operating: 8.613 MMcf/day IP on 14" choke; Red River Parish, Red River-Bull Bayou Field, S6/T12/R10; res. B, serial #23975
I will hold off posting the revised LA completions spreadsheet with this new information until later in the week.

Sunday, March 7, 2010

New Texas Completions

  • Peace #1H, Noble Energy: 6.250 MMcf/day on 18/64" choke; Carthage Field (Haynesville), Shelby Co.
  • Louis Weiner Sawmill #12H, XTO Energy: 6.997 MMcf/day IP on 20/64" choke; Carthage Field (Haynesville), Panola Co.
  • Scott R. McGee #12H, XTO Energy: 9.728 MMcf/day IP on 48/64" choke; Carthage Field (Haynesville), Panola Co.
  • Kain GU 1 #1, Samson Lone Star: 1.585 MMcf/day IP on 16/64" choke; Waskom Field (Haynesville), Harrison Co.
Development Activity:
  • Mia Austin #6H, GMX Resources; North Carthage Field (Bossier Shale), Harrison Co.
  • Letourneau Gas Unit 6 #28HH, Anadarko; Carthage Field (Haynesville), Harrison Co.
  • Orediggers DU #1H, XTO Energy; Carthage Field (Haynesville), Shelby Co.
  • Fightin' Illini DU #1H, XTO Energy; Carthage Field (Haynesville), Shelby Co.
  • Buckeyes DU #1H, XTO Energy; Carthage Field (Haynesville), Shelby Co.
  • Utes DU #1H, XTO Energy; Carthage Field (Haynesville), Shelby Co.
  • Timberstar-Blackstone GU 1 #1H, Southwestern Energy; Carthage Field (Haynesville), Shelby Co.

Friday, March 5, 2010

Rig Count Mixed

The weekly Baker Hughes rig count showed a 23 rig increase in the U.S., bringing the total to 1,396 rigs.  Of the net new rigs, 21 are drilling for gas and two are classified as miscellaneous.  The weekly numbers showed a net increase of 16 horizontal rigs and 12 vertical rigs and a net decrease of five directional rigs.

Based on my analysis of the individual rigs, the Haynesville rig count decreased by one to 163.  Looking at the Texas Haynesville rig count, I noted few changes. In total, there was one new rig at work on Haynesville wells, bringing the total to 40.  There was one well over which I hesitated, the Marathon Oil Martinsville #1H.  It is classified as deep Wildcat but seems to be in an area of James Lime wells.  Marathon indicated that it plans three to four Haynesville/Bossier wells in 2010, but I opted to keep this one off the list. There was a similar well drilled over the past couple of months called USA Double H #1 for which I made the same decision.  I'll track completions to see how that is ultimately classified.  If anyone knows anything more about this well, please let me know.

The Louisiana rig count decreased by two to 123.  I did a little retroactive addition that might cause a little confusion.  I added a Lower Cotton Valley well that I've been wrestling with for a few weeks. I've finally concluded that it is a Haynesville well.  The well (Leonard Farms 32 #2-ALT, Exco Resources) is included on the detailed spreadsheet as new, but it should have been added several weeks ago. I've updated the table below retroactively, but I have not amended old posts. 

Southwestern Energy: Update

Southwestern Energy held its quarterly conference call recently and updated its progress in the Haynesville Shale.  The company has 42,300 net acres (about 69,000 gross) prospective for the Haynesville and Middle Bossier Shales in southern Shelby and northern San Augustine Counties, Texas.  To date it has completed five Haynesville wells and one Mid-Bossier well (11.3 MMcf/day).  It is in the process of completing another (Red River 620 #1H - operated by Common Resources) and drilling two more (Red River 619 #2 and Owens #1H - both are operated by Common Resources).

In terms of recoveries, Southwestern is booking a EUR of "just over 5 Bcf."  Well costs are about $10 million per well and don't vary between Haynesville and Mid-Bossier targets.  Wells right now are being completed with 14 frac stages.  When asked about the possibility of limiting choke sizes to improve ultimate recoveries, Southwestern's management replied that because it has only completed seven wells to date, the company has little data to understand how choke sizes impact recoveries. It is open to the concept but will wait to see if other operators are successful with the technique.

Capital expenditures in the East Texas region will be about $231 million, which represents 11% of the company's 2.1 billion budget.  But that capex includes wells to be drilled in other formations, most notably the James Lime.  Southwestern is targeting 21 to 26 Haynesville/Mid-Bossier wells in 2010, but some will be non-operated. The company stated that if commodity prices plummet as they did last year, capital spending will be trimmed. 

Southwestern is a big operator in the Fayetteville Shale and has land in the Marcellus Shale.  On its conference call, management indicated that breakeven natural gas prices for those two plays are in the $4 range, while wells in the Haynesville Play have a breakeven in the $5 range.  Seeing that the Henry Hub spot price of natural gas crossed below $5 on February 21 and hasn't looked back, it looks like it will be yet another interesting and stressful year in the Haynesville Play.

Thursday, March 4, 2010

More on Gazprom...

...and then I'll stop.  Before then, I wanted to share an interesting editorial I read on the Russian energy giant Gazprom's woes.

Having touched on Gazprom twice in a week, I'm starting to feel like I'm harping on the company a bit (especially for a site looking at LA/TX), but it represents a really interesting story to me. Gazprom is the Old Guard in so many ways.  It is a vestige of the post-Soviet world:  it had so much power, but it was unprepared for changes caused by the market.  It became a giant machine that can't see its own feet.  Now it will have to scramble to stay relevant.

The energy industry, especially the natural gas business, is changing rapidly in front of our eyes.  How these changes erode the power of the lead footed giants like Gazprom is really fascinating.  As the editorial points out, it can survive and thrive, but to do so it will have to change significantly. 

New Louisiana Completions

  • Dickson 37 #1, Petrohawk Operating:  8,234 MMcf/day IP on 14/64" choke at 7,754 psi; Cedar Grove Field, Caddo Parish, Sec. 37/Township 17/Range 13; Haynesville reservoir A, serial #239530
  • Sustainable Forest 5 #1, EOG Resources: 12,638 MMcf/day on 24/64" choke at 6,359 psi; Ten Mile Bayou Field, DeSoto Parish, S5/T11/R12, res. A, serial #240172
  • Yarbrough 1 #1, EOG Resources: 12,042 MMcf/day IP on 20/64" choke at 5,351 psi; Trenton Field, DeSoto Parish, S1/T11/R13; res. A, serial #240182
  • Black Stone 3 #1, EOG Resources: 9,699 MMcf/day IP on 22/64" choke at 4,508 psi; Trenton Field, DeSoto Parish, S3/T11/R13; res. A, serial #240236
  • Ninock 12 H #1, Petrohawk Operating: 19,873 MMcf/day IP on 24/64" choke at 8,606 psi; Red-River-Bull Bayou Field, Red River Parish, S1/T13/R11; res. B, serial #239506
  • Whitney Corp 2 H #1, EOG Resources: 4,358 MMcf/day IP on 14/64" choke at 7,140 psi; Converse Field, Sabine Parish, S2/T9/R14; res. A, serial # 239675
I also noted the following well that is classified as Lower Cotton Valley Res. A.  In researching the well, I have come to believe it is actually a Haynesville well.  It's located in a section that is a Haynesville unit, but its vertical depth is actually slightly deeper than the depth of a Haynesville well located in the same section.  There are other productive Cotton Valley wells in the area, but I think they are shallower.  I'm not hip to all of the geology, but it smells like a Haynesville well to me. I'll put it on the spreadsheet until someone can tell me differently. 
  • Moon 27 H #1, Petrohawk Operating: 8,965 MMcf/day IP on 14/64" choke at 8,382 PSI; Elm Grove Field, Bossier Parish, S22/T16/R14; Lower Cotton Valley Res. A, serial #240080
For those who follow the completions spreadsheet, please note that I am fixing a boo-boo.  I mistakenly included an undrilled well (JESTMA 15 serial #240445) as a completion.  In actuality the completion was JESTMA 22 #240030, which was already on the board.  I deleted JESTMA 15 (which had JESTMA 22's completion data).  Mea culpa.

As a new feature, I have shaded cells with new information on the completions spreadsheet, both new completions and updated data on existing completions.  I will also keep the updates of the spreadsheets to no more than twice per week (Thursday and Sunday/Monday).  I'll try to do two colors for those who only check once per week.  I'll do the same for Texas completions and only update that spreadsheet once per week on Sunday/Monday.

Storage down 116 Bcf

The EIA weekly storage report for last week showed a decrease of 116 Bcf, or 6.3%, to 1.737 Tcf.  That figure is about on par with the withdrawal from last year (-101 Bcf) and the five year average (-124 Bcf).  Currently the storage figure is 3.9% lower than last year's figure and 1.2% higher than the five year average. 

The five year average storage level for exiting the withdrawal season is 1.478 Tcf.  Assuming this happens the last week of March (reported first week of April), there are four weeks remaining to withdraw 259 Bcf of gas, a weekly average of 65 Bcf.

By region, the largest percentage withdrawal was in the East Region (-7.9%), the largest of all the storage regions, while the West and Producing Regions saw withdrawals in the 4% range.  Currently, the Producing and East Region storage levels are 4% and 1% below the five year average, respectively, while the West Region is 22% above the five year average.  While the West Region percentage number seems shocking, it is by far the smallest storage region with 296 Bcf currently in storage.

I have to admit that I was a little disappointed in the withdrawal.  I seem to remember a pretty wintery week last week, but I'm getting my blizards confused.  In actuality, temperatures were considerably warmer in the Northeast and upper Atlantic Coast regions, which are particularly big users of gas.

Wednesday, March 3, 2010

Gas vs. Wind in Texas

Yesterday the Wall Street Journal had a very interesting piece on the impacts of wind energy to the electricity grid and how wind generators are getting a free ride in some respects.  The story looks at Texas and how its grid operates.

The natural gas industry points out that if a gas or coal electricity producer misses its daily power generation estimates, it has to pay for backup generation. If a wind power generator falls short of daily predictions, it doesn't have to pay for backup generation.  If they miss their estimates, they skate, placing a greater burden on other producers.

This is a thorny issue for natural gas because the increase in wind-generated power has led to a direct decrease in natural gas-generated power.  As wind has increased from 2% to 6% of state power generation, gas has dropped from 46% to 42%, a 1:1 correspondence.  Ultimately, the expansion of wind in Texas displaces natural gas production rather than coal production, thus diminishing the positive environmental impact of wind.  (This impact of wind on gas consumption, specifically in Texas, has been discussed here before.)

This is pure economics.  Because coal is cheaper than gas as a fuel source, coal plants get turned on before gas plants, which end up only taking care of peak energy needs.  The decision is purely a $/ton of coal calculation and does not take into account the externalities of burning coal, from pollution to higher levels of carbon dioxide in the atmosphere.  Legislation to impose some kind of price on carbon (tax, cap and trade, cap and dividend, etc.) will change this calculation, but for now the burden falls on natural gas.

BP Gets into Eagle Ford Shale

Yesterday BP announced a 50/50 joint venture deal with privately held Lewis Energy of San Antonio, TX to explore Lewis' 80,000 acres in the Eagle Ford Shale in southwest Texas.  Lewis currently operates one rig in the play and may add another one.  Details are a little murky at this point as to who will be the operator and the value of the deal, which I've seen range from $160 million (WSJ) to $200 million (Reuters UK) for the 50%, which implies a valuation of $4,000 to $5,000 per acre. 

I think we will see a few more of these types of deals between smaller independents and major integrated energy companies in the various shale plays of North America.  The question is whether the joint venture or the corporate acquisition (i.e. Exxon/XTO) will be the preferred deal type.  I'm guessing the former, but we'll see.

The announcement came as part of BP's larger discussion of corporate strategy.  In reviewing the document, I'm struck by a few things. First, the supermajor integrated energy companies are wildly complex beasts.  It seems simple enough when thinking upstream-midstream-downstream, but the devil is in the proverbial details.  Presenting the big picture strategy makes you think of the depth of these companies. 

Second, while the Eagle Ford deal was not the big news of the day, it stuck out to me as being the piece that didn't really fit in with the rest of the upstream puzzle.  Companies like BP depend on large fields and mega projects.  Just look at some of the projects in our backyard (the Gulf of Mexico):  Horn Mountain, Mars, Mad Dog, Na Kika, Atlantis.  These are huge wells with billions of dollars of capital invested.  Compare that to developing hundreds of onshore natural gas wells in Texas and Louisiana.  We think these wells are expensive, but $7-9 million is a rounding error for a company like BP.  This kind of "whack-a-mole" development is a different discipline for a big company.  In its strategy presentation, BP points to "low cost 'factory' production" as its way of achieving scale in a shale play, but what if it turns out to be more hunt and peck like Arthur Berman suggests?  It will be interesting to see how they perform against the natural gas independents.

Third, in reviewing BP's strategy, you realize how important alternative energy will be for supermajors going forward.  Being somewhat cynical, I've dismissed the TV commercials for Exxon and BP as make-nice P.R., but these are energy companies with a very long term time horizon, not just oil and gas companies.  If all they do is produce hydrocarbons, they will severely limit themselves in the future and end up like the dinosaurs from which they now extract oil. 

Right now it seems as though the alternative energy push has been more about P.R. than progress, but I am starting to believe that these companies realize the importance of investing real R&D funds in finding/creating new energy sources.  I'm interested to see where the real alternative energy innovation originates.  Will it be places like Silicon Valley, where the Bloom Energy fuel cell has been attracting fawning media attention, or the supermajor energy companies, which seem to be producing more slick TV commercials that fully developed alternative energy products?