A recent law passed through the house in Colorado that will require property sellers to disclose possible third-party mineral rights ownership. That will include oil, gas, coal, and other minerals.

In Colorado, minerals are often severed and this law would require that buyers be made aware that there is a possibility someone else owns the minerals.

This act will apply to contracts made on or after the later of the applicable effective date or January 1, 2014.

The bill passed at the end of March and was introduced to the Senate in early April 2013.

You can read the full bill at www.leg.co.state.us

QEP Resources has reached a $115 million settlement in a class action lawsuit filed by royalty owners in the state of Oklahoma. The class action lawsuit was filed on behalf of QEP’s Oklahoma royalty owners asserting claims related to royalty valuations related to wells QEP operated or from which it marketed the gas.

The Settlement provides a cash payment from QEP to the class in the amount of $115 million in exchange for a full release of claims regarding the calculation, reporting and payment of royalties from the sale of natural gas and its constituents prior to February 28, 2013.

The settlement agreement also includes an updated methodology for the calculation and payment of future royalties for the life of those leases.

You can read the full filing at sec.gov

Over $20 billion in natural gas royalties were paid in 2010. That’s the most recent year the NARO has provided statistics. Pennsylvania is the most recent state to splash onto the scene. An estimated $1.2 billion was paid to royalty owners across Pennsylvania in 2012. One company, Range Resources, has paid out over $1 billion in PA by itself since 2008.

Payouts in 2010 were led by the following states:

1. Texas – $6.7 billion
2. Wyoming – $2 billion
3. Alaska – $1.9 billion
4. Louisiana – $1.75 billion
5. Oklahoma – $1.6 billion
6. New Mexico – $1.3 billion
7. Colorado – $1.2 billion
8. Arkansas – $668 million
9. Pennsylvania – $500 million
10. Utah – $350 million

The revenue is for natural gas production only. I suspect rising oil production is adding to the amount of royalties paid. Also, NARO used an average royalty of 18.75% and the royalties paid include those paid to state and federal governments.

Read more at ap.org

Schlumberger expects there will be fewer rigs active in 2013 than 2012, but there will be more wells drilled. The company reviewed its outlook for North America in its fourth quarter conference call.

But if you look at our view on 2013 for North America, we do expect the U.S. land rig count to be up between about 100 and 150 rigs in Q1, and this is based on the feedback from our customers. Now in terms of activity for the full year, we still see U.S. land rig count slightly down versus 2012, while the well count will be slightly up.

Other notable items from the call:

• Expects the liquids rig count to bounce up in the first quarter of 2013
• Do NOT see a significant recovery in dry-gas drilling in 2013
• Natural Gas production remains strong
• Hydraulic fracturing pricing is not expected to increase in 2013

As you hear locals begin to discuss rigs moving out of your area. Remember, a lower rig count does not mean there will be fewer wells drilled in your area. Operators get more efficient over time and need fewer rigs to develop their acreage.

US oil production is on pace to eclipse 1998 levels in 2012. Daily production is set to grow more than 10% year over year. Let’s put this in perspective – you have to go back to 1950-1951 to find the last year US oil production grew by more than 10% in a single year. A total of 800,000 b/d of growth is expected during the year and that has never happened in the history of the United States!

2009 was the first year the country grew production since 1991 and even then production grew at a rate of less than 1%. There was growth in the mid-1980s, but you have to go back to the 1960s if you want to see the last time the country grew production consistently. The current streak is now four years. If you’re questioning the significance of modern shale development, the past four years should prove something has changed. The country has identifiable resource that is supporting production growth for the first time in decades. Actually, new developments are doing more than support growth, they’re setting records.

The Cline Shale grabbed headlines after Devon announced impressive well results. Devon believes a typical well might produce 570,000 boe, with 85% of that being oil and NGLs. The company also pegged recoverable resource at 3.6 million boe per section (square mile). If the commercial extent of the play extends across 9,800 square miles, then you get to the 30 billion barrel number being reported. First of all, let’s say the obvious. There haven’t been enough wells drilled to know if this is a 30 billion barrel field, but even if the Cline only has 3 billion barrels of recoverable oil, it will rank as one of the largest discoveries in the U.S.

Devon has four rigs running in the area as of the fourth quarter of 2012. The most recent horizontal well completed in the play produced 450 boe/d over a 30 day period. The company has over 550,000 acres targeting the play in Fisher, Mitchell, Nolan, and Sterling counties. The first three wells were drilled in Sterling County, but the company will continue to step out from there in the coming months. The area is also prospective for the Mississippian and Wolfcamp formations.

How Does 30 Billion Boe Compare to the Bakken and Eagle Ford?

The USGS has estimated the Bakken Shale holds more than 4 billion boe of recoverable resource. Industry estimates peg that number at anywhere from 6-10 times higher (24-40 billion boe).

The most common Eagle Ford estimates are 7-10 billion boe, but industry estimates stretch as high as 20 billion bbls of liquids and 150 tcf of gas. That’s more like 40-50 billion boe, so you see there’s a pretty large margin for error in reserve estimates.

Oil prices in the U.S. can vary substantially. Prices can change quite a bit within the same state. Much of the value of a barrel of crude is determined by its type or makeup. Crude type isn’t the focus of this article, but it’s worth reviewing.

Light-Sweet crude is generally the best. Heavy crudes like those produced in Venezuela or Utah require more complicated refining processes. For that reason, heavy crude is worth less. Condensates, very light crudes, or even natural gasoline trade at a discount to your typical light-sweet crude. “Sweet” means the crude has a low sulfur content. Begin producing sulfur and the value of the crude goes down. WTI is a light-sweet crude and is likely what you see reported in the news. It’s considered the benchmark in the U.S. Almost all crude oil traded in the U.S. is priced at a discount or premium to WTI.

Now, on to logistics. There’s a factor that can have significant influence on the price of crude and it has more to do with Fedex than a geology (maybe Fedex doesn’t move much crude, but you’ll get the picture). Transportation and the ability for crude to make it to refineries is essential. In the U.S., most of the country’s refinery demand is in the Gulf Coast. Even then, not every refinery is created equal. While WTI might be the preferred crude type, a refinery might be set up to handle heavier crudes (low API gravity) and taking a light-sweet crude might be inefficient. For that reason, a refiner might pay less for WTI than it would otherwise. The important take away is: if the crude can’t get to market, it is not worth much.

Growing U.S. Oil Production Puts a Strain on Infrastructure

U.S. oil production is growing. Growing at rates that have analysts touting the potential of the U.S. being the world’s largest crude producer. That’s amazing when you consider what the same analysts have been saying a few years. Most were singing a tune similar to that of peak oil theorist.

It’s like most good things. There are obstacles. Production growth means new infrastructure is needed. Oil companies need ample transportation capacity to move product to market

Typically, oil is transported by:

• Pipeline (Cheapest)
• Rail
• Truck (Most Expensive)

When there is a shortage of pipeline capacity, operators will move crude by rail to the various refinery centers in the U.S. Trucks are used for shorter distances. Moving oil from North Dakota to Louisiana by truck simply doesn’t make economic sense. When you don’t have reasonable pipeline, rail, or truck options, prices get ugly.

Oil Prices Vary Widely

In 2012 alone, WTI, which is priced in Cushing, OK, has traded at as much as $25 less than Brent crude. Brent is a comparable crude, but is priced outside the U.S. It’s an interesting discrepancy. Almost 25% of the world’s crude is consumed in the U.S., but the benchmark crude in Cushing, OK, is tens of dollars cheaper than international equivalents. If that doesn’t tell you we’re in the middle of a U.S. oil boom, I don’t know what will.

Let’s go back to what I said earlier. Most U.S. crude is priced a some premium or discount to WTI. If the crude needs to travel through Cushing, you can bet it’s going to trade at a discount. How big can the discount be? In November of 2012, oil prices in the Permian Basin (West Texas) were trading at a discount of more than $20 to WTI. At several points during 2012, oil in North Dakota’s Bakken Shale traded at discounts that large. That means crude in West Texas and North Dakota sometimes sells for as much as $40 less than similar crude oil in Europe or even closer to home – Louisiana.

If you are tracking your royalty payments (you should be), $40 is likely more than you were getting for the whole barrel ten years ago.

We suggest tracking prices just to make sure you catch any potential problems. You can track oil prices in several places, but Plains All American Pipeline has an easy to download pricing bulletin that is published every day. Check it ever so often to see if your royalty checks are similar. It’s worth noting, Plains is quoting physical prices, so it’s very likely your operator will be realizing better prices. With significant volumes, operators make term commitments on pipelines and realize prices better than physical spot prices.

Oil pricing dynamics are not the topic of discussion at most homes, but don’t fret.  Use the sources quoted above and do spot checks a few times a year (at a minimum). At the end of the day, it’s in everyone’s best interests to see oil pricing discounts shrink. The big discounts we see today will shrink, but it’s going to take time. Bring on the pipelines!

Natural gas prices hit 2012 highs in October, so it’s a good time to learn more about where they are headed. Natural gas storage levels are still on pace to set records in the next few weeks, but prices are up 88% from lows near $2 per mmbtu in April. Even though $3.50 is the best number we’ve seen in the past few years, it’s a lot better than what a lot of us saw on our royalty checks throughout the summer.

Laredo Petroleum’s CEO shares his thoughts on the natural gas industry in the video below. He believes somewhere around the $4-5 per mmbtu will be the norm going forward. After this past summer, I think many of us would be very happy with $5 natural gas.

Oil and gas drilling conflicts with landowners are undoubtedly on the rise. The sheer number of mineral owners has grown tremendously over the past ten years as operators have leased millions of acres of land from North Dakota to Pennsylvania and Texas. The combination of lease negotiations, surface disturbance negotiations, drilling operations, and everything midstream (pipelines, processing facilities, etc.) open numerous opportunities for conflict.

In Texas, the Eagle Ford Task Force met to address many of the issues challenging landowners. The discussion included everything from eminent domain to abandon wells and surface owners who don’t have mineral rights.

Polly McDonald from the Texas RRC said it is mostly people who don’t own mineral rights that have conflicts with the oil companies. If you are getting royalty checks and they want to lay a pipeline across your land, you get defensive.

A TIPRO representative commented: “Some of this stuff is just too complicated for Joe Q. Citizen to handle without legal help.”

Current issues being addressed across the state included:

• Abandoned wells – New legislation passed in 2009 makes rules more stringent for operators who aren’t producing from a well, but have not abandoned it and reclaimed the surface. As the law goes into full effect this year, we expect you’ll see more wells abandoned than before
• Eminent Domain – A recent decision in Texas Rice Land Partners Ltd. and Mike Latta v. Denbury Green Pipeline-Texas LLC makes way for landowners to challenge whether a pipeline is actually a “common carrier” that moves product for multiple companies. If it’s only used by one company, the rights of eminent domain don’t apply.

And I’m betting this is just the beginning. With millions of new royalty owners, there will likely need to be new legislation and court resolutions for disputes in several states.

Read more about the Task Force meeting at fuelfix.com

Rigs continue to shift away from natural gas plays like the Haynesville to liquids-rich plays like the Eagle Ford Shale and Bakken.

Since the end of 2010, more than 100 rigs have moved out of the Haynesville in East Texas and North Louisiana. It’s likely many of those rigs are now engage in Eagle Ford drilling. More than 250 rigs are drilling in the South Texas play as of September 2012.

The takeaway is that an Eagle Ford gas well produces half the amount of gas a Haynesville well produces. Move into the oil window where 90% of rigs are drilling and Eagle Ford gas production per well drops 80% from that of a Haynesville well.

It’s just one data point, but you get the picture. Wells drilling for oil mean less gas coming to marketing. This fall doesn’t look to have much promise, but a normal winter combined with declining production in 2013 should make for a gas market that makes royalty owners happier when those monthly checks arrive.

Read more about rig movement at wsj.com

Chesapeake is back at the negotiating table with many Ohio mineral owners. The cash strapped company is looking to alter terms of its leases to allow for 1,280-acre drilling units. That’s double the size of the typical unit (640 acres).

Long laterals are not new in shale plays. The majority of Bakken Shale wells are drilled with horizontal laterals that extend 10,000 ft and much of North Dakota wouldn’t be economic without the mega-units. With improvements in horizontal well control, 0perators are extending their reach beyond 640 acres across many of the U.S. shale plays. While the technical risks of failure rise with longer laterals, companies are able to hold more acreage (lowers land acquisition costs) and access more of the reservoir with a single well (should result in better production rates).

It is simply too early to know if proposed long reach laterals in the Utica Shale are the result of a better understanding of geology or a ploy to hold larger swaths of acreage. While 1,280 units are needed for a commercial well in parts of the Bakken, the need for longer laterals is yet to be determined in other shale plays.

The one bit of intelligence that should be followed closely is well results. If you own enough land to stand firm at the negotiating table, try to wait until production results from extended lateral wells are released. I say “try” because operators will likely renegotiate most leases, in areas like Ohio, before long-lateral wells are ever drilled.

If you’ve been contacted by Chesapeake or any other operator to amend your lease, share your experience at MineralRightsForum.com.

Read more about the Wall St. Journal’s investigation at wsj.com

An Ohio court ruling could have major ramifications for wells that are completed using horizontal drilling and hydraulic fracturing. My guess is there are close to ZERO Utica Shale wells that are commercial without fracking and most will be drilled utilizing horizontal wells.

In Harrison County Ohio, Jewett Sportsmen & Farmers Club, Inc. filed an injunction against Chesapeake Energy et al. regarding development of the Utica Shale on their property. In the case in question, the surface owner moved for an injunction on all activity after the operator had built two well pads and planned to drill up to 16 natural gas wells.

The court decided in favor of Jewett (surface owner) due to language that is common in older leases written when coal mining was the concern. The deed uses the phrase “through AND under” when referring to rights to access minerals on the described land. If you’d like, jump to the full judgment HERE.

Why Worry About Mineral Deed Language “Through and Under”?

In Ohio, the language “through and under” was used to limit surface activity directly related to mining. It kept mining companies from using a certain tract of land as the removal site for coal mined outside the premises. A landowner might not mind the operator producing their coal, but they didn’t want the whole town’s coal (exaggeration) produced from their property. It essentially protects the landowner from operations on their property that are larger than needed to produce the coal under their property. If you’ve seen the equipment used in mining, you understand why you might not want more than needed on your property.

A Limitation to Rule of Capture? – Kind Of

The court ruled the operator had the right to access natural gas within the property boundaries of its lease, but did not have the right to access natural gas or hydrocarbons located in adjacent tracts of land. The company COULD produce oil and gas from adjacent tracts as long as activity, the horizontal wellbore and fractures, stayed within the boundaries of the property exclusively (rule of capture). If activity extends beyond the boundaries of the premise, minerals can not be produced through this location. That’s where the wording of this deed limits what can be produced from the property. It’s not a direct challenge to “Rule of Capture”, but it does limit the ability to produce oil and gas from certain properties.

The court decision might have been different if the deed read “through OR under”, but the term AND was a sticking point in the final judgement. This language was common for mineral owners who wanted to protect surface disturbance on their property and in this case it’s Jewett protecting against surface disturbance related to oil & gas operations.

Deeds and Mineral Reservation Language Related to Surface Locations Just Got More Important

The judgement does not keep the operator from constructing a well pad on adjacent property, that doesn’t have the same language in its deed, and producing minerals related to this judgement. It does limit Chesapeake’s ability to drill across multiple tracts of land from this property. The language used in the deed is fairly common in mining areas, but there isn’t an easy way to judge how big of an impact this could have on operators in Ohio. If the decision is upheld in higher courts, surface locations will be forced to locations that don’t have the same “through and under” language in their deeds.

NiSource Inc and Hilcorp have entered a strategic partnership to jointly develop the Utica Shale. The newly formed venture, Pennant Midstream, will invest $300 million in midstream infrastructure in 2012. The company will construct new gathering infrastructure and NGL processing facilities in northeast OH. In the first phase of development, the partnership will construct:

• 50-miles of 20-inch gathering pipeline facilities
• 200 mmcfd cryogenic NGL processing plant in Ohio

In a second JV, NiSource will participate with Hilcorp in developing acreage in northeast Ohio and western Pennsylvania. The acreage trading hands wasn’t disclosed, but Hilcorp will remain the operator and will manage development. The upstream JV is anchoring the midstream projects with long-term commitments.

The entire midstream project is expected to be in service in the third quarter of 2013.

Read more at nisource.com

Chesapeake Energy’s Appalachia division has agreed to cover the cost of the state of New York’s investigation and will let more than 4,400 Marcellus Shale leases covering more than 250,000 net acres be renegotiated. That will be a significant price to pay for acreage that was initially leased for signing bonuses of just a few dollars per acre. Note to NY mineral owners  – without hydraulic fracturing, those leases are worth less than $2-3 per acre. Make sure you vote.

Bonuses increased to more than $1,000 per acre in other areas of the Marcellus Shale and leases are generally more elaborate than they were just a few years ago (environmental clauses, restrictive terms, etc.). If the company truly plans to renegotiate, this is a costly decision. If each acre is re-leased at $1,500 per acre, this will cost the company almost $400 million in lease bonuses alone. Add higher royalties, costly lease provisions, etc, and this decision could have a half a billion dollar impact.

We explored the details of the planned arbitration last month in an article titled Chesapeake’s Force Majeure Gas Lease Case in NY. Chesapeake was attempting to extend leases by declaring the ban on hydraulic fracturing in New York a ‘Force Majeure’ or an act of God event. That event kept the company from meeting the terms of its leases and the company had hoped to extend its opportunity to develop the leases. With arbitration looming, the company has agreed to simply renegotiate with New York landowners.

With the inventory of wells Chesapeake has plans to develop across all of the major shale plays, it will be interesting to see if they actually attempt to re-lease this acreage. This could very well be a situation where the company doesn’t believe it was going to develop the acreage in a timely fashion even if the fracking ban was lifted.

Goodrich Petroleum announced an impressive well in the Tuscaloosa Marine Shale. The Encana operated well (Anderson 17H-1) in Amite County, MS, produced over 1,000 boe/d over a 72-hour test period. 975 b/d and 425 mcf/d to be exact. The well was produced with a 15/64 choke and over 2,100 psi of flowing pressure.

Goodrich has leased and acquired a position of approximately 120,000 net acres targeting the Tuscaloosa Marin Shale at an average price of $225/acre.

The company has plans an operated test well and another from Encana in Amite County. In addition, Goodrich will test a Tuscaloosa well in Wilkinson County, MS.

Read the full press release at goodrichpetroleum.com

Chesapeake Energy’s Hogshooter discovery well is going down in company history. The well broke records in its first week online. In the first eight days, rates stretched to more than 7,305 boe/d. The Thurman Horn 406H well was drilled to a vertical depth of 10,000 ft, with a horizontal lateral of 4,900 ft. The well produced 5,400 b/d, 1,200 b/d of NGLs, and 4.6 mmcfd of natural gas. That’s a lot of hydrocarbons for an onshore well and the 5,400 b/d of oil set a record for CHK.

The company has only completed two Hogshooter wells to date. The first (Meek 41 9H) was drilled five miles from the Thurman well and produced 1,300 b/d of oil, 365 b/d of NGLs, and 1.4 mmcfd of natural gas in its first 27 days of production.

Two additional wells are waiting to be completed – the Zybach 6010H and the Hamilton 39 10H. The company has 30,000 net acres prospective in the play. Mostly, the acreage is held by deeper Granite Wash wells drilled in previous years. Current plans are for 65 additional wells going forward.

Don’t expect news of huge lease bonuses or high royalty rates. The Hogshooter is prospective across the Texas Panhandle and parts of Western Oklahoma where the Granite Wash has been producing for years. Most mineral owners have leases that are held by production from the deeper Granite Wash formation. The big bonus will be bigger royalty checks as these wells come online.

Also, keep in ear open for future results. Other companies in the area have had good wells and some not so good wells in the Hogshooter. A few data points aren’t enough to proclaim the Hogshooter a wide spread resource play. It could very well be a more conventional target.

The Eagle Ford Shale story has been fun to watch over the past few years. While there are many shale plays struggling at with low natural gas prices, the Eagle Ford’s liquids yields are supporting economics.

There are over 280 rigs active in the South Texas Region as of May 2012.  Almost 210 of those are drilling for oil. Add in the rigs that are supported by condensate and NGL production and around 90% of drilling targets liquids. It’s easy to see why operators have shifted capital from dry gas to plays like the Eagle Ford. Chesapeake, a leading natural gas producer, plans to spend 30% of its 2012 budget in the play.  That will swell to 40% in 2013.

The activity is followed by production and new expectations. The EIA estimated the play produced 500,000 b/d of liquids in April 2012 and Valero’s CEO expects the play will produce 500,000 b/d of crude by year-end 2012. In reality, we’re probably between both numbers. New analyst projections peg total production potential of the play between 1.1 and 1.8 Million barrels per day. That’s in a total US market that produced a little more than 5 million b/d a few years ago. The Eagle Ford alone might grow US supply by 25% or more!

The Best is Yet To Come

John Walker of Enervest spoke at a conference earlier in the week and he believes we’re still very early in understanding the shale plays. He said a recent well was completed and then shut-in for 45 days. The well produced at initial rates of almost 100% more than an adjacent well. 100% more! As the play truly hits its stride. Expect to see more announcements related to operational efficiencies, improved well results, and increases in recovery of hydrocarbons. That’s all good for mineral owners and operators alike.

Range Resources tested reduced cluster spacing on two wells in a producing unit in the Marcellus Shale.

Range Marcellus Acreage Map - Click to Enlarge

The results are intriguing to say the least. Production came online at roughly double rates of wells that didn’t receive the treatment. The Marcellus has already proven to be resilient to low natural gas prices and an uplift in individual well performance of 100% will only further entrench the Marcellus as a leading shale gas play.

In the first quarter of 2012, Range wells across the board averaged 6.6 mmcf/d and 252 b/d of NGLs and condensate. One well in the liquids-rich portion of the play was completed with the reduced cluster spacing and came online at a peak 24-hr rate of 108 b/d of condensate, 501 b/d of NGLs, and 7.1 mmcfd of ethane rich natural gas. The well had a lateral length of 2,752 ft and was completed with 14 stages.

Improvements like these are exactly what you want to see in a time of low natural gas prices: Good engineering and operational gains make our minerals more valuable.

Chesapeake and StatoilHydro’s landowner court case in New York is now going to both federal court and arbitration. The case is over whether or not a state moratorium on hydraulic fracturing is sufficient to declare “force majeure”. Chesapeake acquired leases covering thousands of acres in New York at low prices. Many leases signed before the Marcellus rush included lease bonuses of just $3 per acre. When you consider bonuses that have reached above $5,000 per acre in the better portions of the play, you begin to understand why Chesapeake will fight to hold its current leases. If the company is forced to re-lease, it will potentially cost billions of dollars.

The first lawsuits were filed in April of 2011 and more followed. In one case, all but 2 of the 150 leases will be going to arbitration. The leases signed included an arbitration clause. Be sure you’re prepared to go to arbitration if you sign a lease with an arbitration clause. Many landowners were hoping the limits of force majeure would not fall within the scope of their arbitration clause, but the judge ruled it does.

Now, the landowners will choose an arbitrator, Chesapeake will choose an arbitrator, and the arbitrators will choose an arbitrator. Any decision must be unanimous between the three. That makes negotiations difficult.

On the landowners side, there are 32 leases in a separate case that will be going to federal court. The leases lack an arbitration clause and there should be a judgement before the end of 2012. If the courts side with the landowners, the other landowners will have much more negotiating power in arbitration. If the courts side with Chesapeake, it will be difficult to negotiate much in arbitration…..

Force Majeure – unforeseeable circumstance that prevents someone or an entity from fulfilling a contract

Shell finally announced the location of its highly anticipated cracker plant in the Appalachian region. Shell was courted by Ohio, Pennsylvania, and West Virginia, but eventually decided on locating the plant in Monaca, Pennsylvania.  All three states were lobbying for the location of the multi-billion dollar facility because it will be the first plant of its kinds built in the area in decades and will likely support thousands of jobs during construction. The complex will include an ethane cracker and potentially polyethylene and mono-ethylene glycol units. All the aforementioned products are used in manufacturing.

The plant is also important for northeast mineral owners who want to make sure they continue to receive the best prices possible for the natural gas liquids (NGLs) produced from the Marcellus & Utica Shales. NGLs are more closely tied to oil prices than natural gas prices.  With gas prices below $2.30 in early 2012, operators are looking to maximize the value of produced liquids (NGLS & oil). Local demand will only help. Prices for NGLs should remain linked to oil as long as there is significant demand in the region and producers have viable transportation options (pipelines).

“We are very pleased to have signed this site option agreement,”  Dan Carlson, GM, New Business Development, Shell Chemicals. “This is an important step for the project, and we look forward to working with the communities in Pennsylvania, and gas producers across Appalachia, as we continue our efforts to develop a petrochemical complex.”

Natural Gas prices hit 10-year prompt month lows of $2.30/mmbtu this week and there doesn’t look to be anything coming in the next several months that should change the current outlook.

Oil & gas companies with significant exposure to natural gas prices have been lowering capital budgets for 2012 and shifting dollars from dry-gas targets to oil and liquids-rich plays. That will only magnify at $2 natural gas prices. Many companies made corporate acquisitions, leased acreage, and drilled billions of dollars in wells that need much more than $2 natural gas to pay back. The one saving grace for the industry is that there is significant opportunity in oil plays like the Eagle Ford Shale, Bakken Shale, and in West Texas. If operators shift enough activity to oil, we should begin to see a significant shift in supply over the rest of the year, but we’ll be fighting an up hill battle with mild weather leading to record storage levels coming out of this winter.

The opportunity for companies to explore for oil doesn’t mean much for the individual mineral owner and our checks will suffer this year if you’re in a dry-gas area like the Barnett, Fayetteville, Haynesville, or Marcellus shales. Add typical declines of 60-90% in production during the first year of a wells life in those plays and you might be surprised by how much less your checks are this year. For mineral owners in parts of the Haynesville where signing bonuses of $10,000 plus were paid, it is quite possible they received the bulk of today’s value of their minerals in their signing bonus. That’s varies widely from the historical norm and likely means prices will have to get better.

Natural Gas prices have been on a steady decline since hitting $13/mmbtu in 2008 and had fallen to almost $3 at the end of 2011. The current 12-month strip, that’s what the futures market is telling us prices will be, is a paltry $2.82/mmbtu. That’s a 35% drop in prices from last year. Combine the price drop with typical declines and you should prepare for gas royalty statements that are half of what you made last year.

We can debate whether it should be called Fracking or Frac’ing for decades to come, but a new UT Study concludes that hydraulic fracturing does not in itself cause drinking water contamination.  The University of Texas Energy Institute study was not funded by industry dollars.

The study noted that contamination is usually related to above ground spills or a mishandling of wastewater. All in all, it means the “Fracking Scare” is just a scare. As long as oil & gas business conduct business as safely as possible, just like every other business in the country, our drinking water is safe.

Read more at chron.com

U.S. oil production has experienced a more than 30% decline over the past 50 years. Compared to natural gas that has blossomed since the dawn of the boom in the Barnett Shale, that’s a stark difference. The primary reason for the delay is oil is just beginning to bear the fruit of technology application.

From a geology perspective, there is simply more gas in the ground and companies were chasing the prize of trillions of cubic feet of gas (Quadrillions have been mentioned!). Right now, it looks as if history will show the new shale gas education applied to oil plays. The Bakken Shale is the most advanced and the plays’ production has risen from essentially zero to over 500,000 b/d today. The disclaimer is the Bakken had been targeted before the most recent horizontal drilling revolution, but it wasn’t what it is today. Not close.

Bentek, a energy research firm, believes West Texas and the Eagle Ford will have production grow to 2 mmbbls/d by 2016. That’s double what the whole state produced per day in 2005. With almost 2/3′s of U.S. rigs active in oil plays, West Texas and the Eagle Ford will not be alone in boosting the countries oil production.

Read more on the NBER study at fuelfix.com

Apache announced it is acquiring Cordillera Energy Partners III (the third built and sold Cordillera success story) for $2.85 billion. The acreage position covers 254,000 net acres in the panhandles of North Texas and Western Oklahoma. When backing out production, the deal equates to an acreage price between $7,000-9,000/acre. Cordillera has 18,000 boe/d of net production in the area, with almost 72 mmboe of proved reserves.

Apache - Cordillera Granite Wash Map

The motivation for the deal wasn’t current production or proved reserves. It was the potential of multiple stacked pay zones. 3P (possible) reserves are estimated to reach as high as 300-400 mmboe from more than 14,000 potential drilling locations. 50% of the acreage is already held by production, which will be a manageable number for a company the size of Apache.

Drilling in the area targets multiple zones of the Granite Wash play, but Apache will also target the Cleveland, Tonkawa, and Marmaton formations. Stack pay zones mean the area is prospective for gas, as well as oil, condensate, and NGLs. Cordillera’s current production is more than 50% liquids.

Apache’s strategy has long been that of acquire and exploit. The company has supplemented its onshore acreage significantly in the past couple of years with acquisitions in West Texas from BP and now Cordillera acquisition in the Granite Wash.

Chesapeake Energy is slashing natural gas spending and re-directing rigs and capital dollars toward liquid-rich plays like the Eagle Ford and Utica shales. Chesapeake is also planning shut-ins of 0.5 Bcfd and will increase that amount to 1 Bcfd if prices don’t begin to recover.

The company is targeting a natural gas rig count of 24 by the second quarter of 2012. That’s down from an average of almost 75 gas rigs in 2011. There are only ~2,000 rigs active in all of the U.S. onshore market, so a 50 rig change is very significant.

Spending in dry gas plays will decrease from $3.1 billion in 2011 to $900 million in 2012. A more than 70% decrease year over year.

The areas impacted the most will be the Barnett and Haynesville shales, where the number of active drilling units will decrease to 6 in each play. The company will drop to 12 active rigs in the dry gas region of the Marcellus Shale in Northeast Pennsylvania.

Capital that would have been spent in dry gas plays will now be re-deployed in liquids-rich plays that deliver higher valued oil, condensate, and NGLs.

This reallocation will result in increased expenditures in certain of Chesapeake’s liquids-rich plays, including the Eagle Ford Shale, Utica Shale, Mississippi Lime, Granite Wash, Cleveland, Tonkawa, Niobrara, Bone Spring, Avalon, Wolfcamp, and Wolfberry. The company estimates that approximately 85% of its 2012 total net operated drilling capital expenditures will be invested in its liquids-rich plays.

We don’t accept Bank Sight Drafts. I can’t say I never have, but I don’t make it a practice.  If your land is highly prospective, you can bet they’ll do their research first and will have money in hand.

When you sign a bank draft you are allowing a company that might or might not operate and might or might not have done its homework have rights to your minerals. The funny thing is this isn’t a new issue and likely isn’t the last time we’ll hear about it. Companies in every industry make promises they can’t keep and YOU and I have to be educated in knowing whether or not we’re dealing with a reputable party. We also have to protect ourselves best we can. By accepting bank sight drafts, mineral owners have unknowingly allowed the possibility of not being paid.

We’re seeing this issue across the news because of lawsuits brought against Chesapeake in Michigan where the company was leasing through a shell company and many leases were ultimately rejected.

Shell companies and land brokerages will not disappear when it comes to leasing land. Companies simply can’t divulge their ideas to the world before acquiring a material position or benefiting from the idea. We, as mineral owners, have to make sure we’re armed to the best of our ability. There are numerous resources where you can connect with professionals and other landowners to help educate yourself. MineralRightsForum.com is a great place to join or create a local county group and kick off discussion on what is happening in your area. If your situation warrants, an oil & gas attorney is a good backstop.

You can read more on the issues in Michigan at reuters.com

Devon Energy and Sinopec (China) have inked a joint-venture (JV) deal worth $2.2 billion for a 1/3 interest in Devon’s acreage across five new venture plays. Devon is selling an interest in 1.2 million net acres for a little more than $5,000 per acre across several emerging plays:

• Tuscaloosa Marine Shale
• Niobrara Shale
• Mississippian
• Ohio’s Utica Shale
• Michigan’s Utica Shale (Possibly A-1 Carbonate too)

The companies have added 235,000 net acres in the Ohio Utica Shale prior to the announcement of the agreement. The new Utica acreage brings the total acreage covered and price to over 1.4 million acres and $2.5 billion.

Sinopec is acquiring a little over 470,000 net acres across the two plays and will pay $900 million up front and will then carry 80% of development costs until the remaining $1.6 billion balance in spent. Devon and Sinopec expect to reach that amount of spend sometime in 2014.

The JV plans to drilling approximately 125 gross wells in 2012 and future capital allocation between the plays will likely be directed based on exploration results from the coming year.

Chesapeake Energy and Total closed the previously announced Utica Shale joint venture on January 2, 2012. The deal was announced at the beginning of November without disclosing the partner, but Total was likely as the company already partners with Chesapeake in the Barnett Shale.

The Chesapeake – Total Utica Shale joint venture covers acreage in the liquids-rich window of the play. Total paid a combined $2.32 billion to Chesapeake and Enervest for a 25% interest 619,000 acres across Ohio.

CHK will serve as the operator and Total will participate in further acquisitions that cover the JV’s area of mutual interest.

The price to play the shale play game increased at a brisk pace in 2011. Prices in the Eagle Ford Shale and Utica Shale  went to levels not seen before 2011.

Typical Eagle Ford Shale deals were hopping along at a few thousand dollars per acre until Chesapeake and CNOOC reached a JV agreement in the fourth quarter of 2010 that broke the $10,000 per acre mark. That set the stage for 2011 where we would see even bigger transactions - Petrohawk acquired by BHP at a 65% premium to its stock price and both the Marathon-Hilcorp Eagle Ford acreage deal and the Carrizo-Gail deal went for for more than $20,000 per acre.

The Utica Shale was the latest play to emerge in major shale development. We also saw a major deal later in the year when Chesapeake’s 2011 Utica Shale JV in the liquids window of the play brought in $15,000 per acre. That was after the company leased its acreage at a price of $1,400 per acre.

There were other deals in gas plays, but over all it has been quiet as we entered the fourth quarter of 2011. Natural gas prices have dropped to approximately $3 per mmbtu while the oil prices has held relatively strong at $100 per barrel.

2012 isn’t shaping up to be a good year for natural gas prices. The NYMEX 12-month strip for 2012 sits at a measly ~$3.30/mmbtu. That’s not a good sign for natural gas royalty checks in 2012.

The November 2011 issue of Kiplinger Personal Finance contains an article titled “Cash In on the Natural Gas Boom”, in which MineralWeb was interviewed for part of the story.

The article explores the oil and gas boom in Pennsylvania and how it has changed the lives of many across the state. Lease bonuses have soared from $3 an acre in 2000 to thousands per acre today. Shalionaires are popping up across the state and its time to think about long-term financial planning. Should you buy, sell, or hold mineral rights in PA:

Market timing is as risky with mineral rights as it is with stocks or bonds, says Kenny DuBose, a mineral-rights consultant and CEO of MineralWeb.com.

Natural gas prices have not been on a healthy trend for the industry and mineral owners. While our heating bills are getting cheaper, companies are slowly being forced to move more rigs to oil and liquids targets as natural gas prices fall.

Natural gas prices have fallen from over $13/mmbtu in 2008 to almost $3/mmbtu at the end of December 2011. The low in prices is also coming at a time in the year when prices usually bounce as cold weather rolls into the country. While we’re only a few days into the official winter, some gas utilities and storage facilities are required to begin pulling gas from storage. That means more supply is coming into the market and without an event that triggers higher demand we’re likely in for OVER-supply for the coming year.

The current NYMEX 12-month strip is a puny $3.38/mmbtu. That’s close to a 20% drop from the average over the past 12-month period. In other words, royalty checks on your gas properties will likely be 20% lower than last year.

While our heating bills will benefit in the winter, fewer jobs will be created in the gas side of the business. We strongly believe the oil & gas industry has the potential to help lead this economy out of the lows of the past three years.

To make the largest impact possible, we likely need natural gas prices in the $5/mmbtu range. That is what many operators have pinpointed as a price that allows for further development without simultaneously hurting the economy. It’s also a price that will add to mineral owners pockets at a much faster rate than $3….

You can always estimate your royalty checks with current gas prices at our Natural Gas Royalty Calculator. Remember – the calculation does not account for severance, ad valorem, or income taxes.

Leasing in Athens County, OH, and other areas of the Utica Shale oil play continue to heat up. Land owners are joining together to sign leases in bulk to get favorable terms. Leases are being signed for $2,500 per acre with rumors of $5,000 per acre in the hottest areas.

Some mineral owners are going as far as taking less money to make sure a well is not drilled on the the surface rights they own. At the most recent “leasing party” $2,500 per acre was the going lease bonus offer, but you could guarantee no drilling on your lands for signing up at $1,250 per acre. Typical royalties were 16% in the leases.

Lavelle said his firm is still processing the many leases that have been signed since early October, but estimated Saturday that more than 400 landowning parties are involved, accounting for approximately 30,000 acres in Athens County. Cunningham has indicated it’s shooting for nearly 100,000 acres worth of leases, a little under a third of the county’s land area.

These leases, with the West Virginia-based Cunningham Energy company, represent a potential payout of approximately $75 million to all the property owners involved, Lavelle said. The attorney has organized three lease-signing events in the last two months.

Lavelle noted that while he was organizing to offer county landowners the use of his lease at a price of $50 an acre another set of lawyers was trying to move in on the local oil-and-gas leasing market. Lavelle’s lease calls for a signing payment of $2,500 per acre, plus 16 percent royalties on any oil or gas taken from beneath the property.

Read more at athensnews.com

In arid regions of the U.S. (e.g. Texas in 2011), water is becoming a precious commodity. Many of us have leased our mineral rights and granted oil and gas companies the right to use water from our property.  The problem is many land owners did not stipulate a price.

While this has been commonplace for many years, it is coming to light due to the recent drought conditions in South Texas where water is being produced for use in drilling and hydraulic fracturing. The implied assumption was the mineral owner was granting the use of water to aid in the production of his/her minerals.

The question being raised now is – Does the right to water mean a FREE right? I suspect we’ll see this language challenged in the near future. There are already grumblings of court cases and I suspect this will be an issue that effects more areas than just the Eagle Ford Shale.

One issue is that oil & gas companies pay sophisticated mineral owners for water. When I say sophisticated, I mean the ones that negotiated to be paid and had the language put into their lease. We’re now in a position where the guys that aren’t getting paid aren’t happy about it and will likely challenge the language in their leases.

If water production on your property is important to the value of your property going forward, be sure to negotiate and describe the planned arrangement in any mineral lease you sign. You might not have much bargaining power if you are a small landowner, but those who farm and ranch need to address the issue to prevent future problems.

Many of issues of this kind boil down to a common denominator. Land owners have to consider leasing as a business decision and need to evaluate all potential ramifications. Many oil & gas wells produce for decades and some…centuries. You want to have your bases covered before entering an agreement that binds your grandkids grandkids.

Gold prices have remained high long enough that we’re beginning to see an increase in gold mining and prospecting across the U.S. That means gold might be as important in some places as it was in the old gold rush days in California.

At almost $1,800 an ounce, it doesn’t take much to rationalize drilling a few wells and digging a few holes to figure out what lies below the surface. There’s potential for a mine in Alaska that could be the largest new mine in decades and there are multiple smaller efforts getting under way in places like Easton, Michigan.

For the most part, a typical oil & gas lease does not address gold minerals and mining.  If you’ve had gold production on your property at any point in history, it is something you need to consider. You’ll want to address the potential in your mineral or land leases to ensure proper development is possible. Having gold you can’t mine or oil you can’t drill is pretty much the same thing as not having it at all.

Aquila Resources, a Toronto-based company with an office in Michigan, this fall drilled 22 holes east of Thornapple Creek Road in the town of Easton to explore what is known as the Reef Deposit. The company plans to drill another 32 holes this winter and has purchased mineral rights from landowners across 356 acres.

The deposit was explored by a different company, Noranda, in the 1970s and 1980s, which estimated up to 120,000 ounces of gold could lie beneath Marathon County soil. With the price of gold today at about $1,700 per ounce, the deposit could be worth as much as $200 million — and could be more profitable to mine now than in the 1970s.

Read the full story at wausaudailyherald.com

A recent article by the NY Times surveyed several thousand oil and gas leases. The Times hasn’t shied away from making accusations about the industry, but the story’s findings should be considered when leasing your minerals.  While many of the problems mentioned are few and far between, you don’t want to be that one land owner that did have problems.

Here are a few of the findings:

• Fewer than half the leases require companies to compensate landowners for water contamination after drilling begins. And only about half the documents have language that lawyers suggest should be included to require payment for damages to livestock or crops.
• Most leases grant gas companies broad rights to decide where they can cut down trees, store chemicals, build roads and drill. Companies are also permitted to operate generators and spotlights through the night near homes during drilling.
• In the leases, drilling companies rarely describe to landowners the potential environmental and other risks that federal laws require them to disclose in filings to investors.
• Most leases are for three or five years, but at least two-thirds of those reviewed by The Times allow extensions without additional approval from landowners. If landowners have second thoughts about drilling on their land or want to negotiate for more money, they may be out of luck.

You can also read an article done by nytimes.com

Montana mineral buyers might be on the hook for knowing whether or not a mineral owner has the right to sell. Northland Royalty Corp bought minerals from a gentleman in the 1990, but a will surfaced approximately a decade later that changes the understood ownership of the minerals.

Without the Bakken Shale, this might not have ever been an issue, but with oil production rising in the area there is no arguing there might be significant value tied to the minerals.

The lower court determined it was Northland’s liability to know a will might have been prepared. We’ll have to wait and see what the state supreme court determines before knowing how this ends. This is a very interesting string of events that further supports the need for everyone to make sure their estate is order before passing on. Otherwise, your kids or grandkids might be in a court battle 20 years later.

In the District Court’s order in favor of the defendants, the Court stated that, “Northland Royalty Corporation…should have had constructive notice of something amiss…” and “Mr. Keller is a landman and should know that when estates are open or when people die they don’t always die without a Will….” further language in the lower court decision, according to Northland, appeared put a burden on the company to determine the individual’s right to sell to them and they say that is not supported in statute. Northland is asking the state supreme court to reverse the lower court order.

Read more at the examiner.com

Mineral valuations are an animal of their own and have multiple complexities, but minerals also complicate surface valuations.  Many times the issue is related to family inheritance and estate planning. Very seldom are all family members interested in taking over a farm or homestead, which often leads to one or more family members working out a way to purchase the property.  Many of the problems start just like this story:

Our problem is – and I can’t really call it a problem – we hit minerals on our land.  The income from the minerals is more than we ever dreamed of having. We’ve looked into ways of sharing this income with our children and need some ideas as to how to do that.

This is exactly the point at which estate planning becomes important. There are several ways to pass mineral rights down to heirs without paying a majority to Uncle Sam. Depending on the value, it can be as simple as leaving the minerals to your family in a will or might involve setting up trusts or family limited partnerships that make it easy to pass ownership while you’re still alive.

Secondly, when we originally set up our estate plan, our son was going to have a heck of a time being able to buy out his non-farming siblings. We had set up a plan where he could buy the land at way less than market value.

It’s funny how more money creates more problems, but you’d rather argue over who gets what than who gets the last glass of water…… While minerals are usually split evenly, the surface is not. The one brother who wants to carry on the farming tradition will make a push for the property and previously would have been sold the property at a discounted price. Now, he has more money.  Is it fair that he gets the land at a discounted price?That’s for you and your family to decide, but it is one of the many questions you should think about when doing your estate planning.  Don’t leave anything to debate after your gone. It makes it harder on everyone.

Read the entire article at farmandranchguide.com

Idaho oil and gas drilling rules have been approved. The rules include a comment period before drilling and completions, lined holding pits, no fluid pits in freshwater source areas, and bonds with the state that start at $10,000 plus $1 for every foot. The oil and gas industry and beginning to develop in the state, but development of the West Hamilton  and Willow fields is likely delayed until Bridge Resources re-establishes a management team.

RULES FOR PUBLIC NOTICE, BONDS

The rules set a 15-day public comment period before a permit can be issued for drilling or well treatments — also called mini-fracking, because liquids are pumped down wells under high pressure to increase flows.

Horizontal fracturing — known as fracking — is done in shale deposits and uses higher pressures. Natural gas in Southwest Idaho is not found in shale, and no one is talking about fracking here.

But many of the same fluids are used in well treatments, and the new rules require that pits used to hold the liquids be lined to prevent leakage into groundwater. No pits are allowed in areas set aside to protect drinking water.

The rules also set up requirements for bonds of $10,000 per well, plus an additional dollar for every foot drilled. A company also could opt for a blanket bond, covering up to 30 wells for $150,000. The bonds would cover the state’s cost of closing the well, should the wells be abandoned or the companies go out of business.

Read the entire news article at the idahostatesman.com

Anadarko Petroleum’s initial horizontal results in the Wattenberg Field indicate the company has 500 million to 1.5 billion boe in resource potential. That’s a mid point of 1 billion barrels net to the company. One billion barrels is a big boost to any area and any company.

Wattenberg Niobrara IPs from the first 11 horizontal wells have averaged 600 bopd and 1.5 mmcfd. The best well came online at more than 1,100 bopd and 2.4 mmcfd.  That well will produce more than 600,000 boe over its life. Anadarko also has an economic advantage over its peers. The company inherited land grant acreage from UPR in 2000. That directly affects the average royalty burden, which is less than 8% across the area.

The only problem with the release is it tells us a lot about the Wattenberg field and little about the rest of the Niobrara. The Wattenberg has been heavily developed for decades and we knew recoverable oil numbers would be lucrative. What I”m really interested in is seeing what develops from the company’s additional 900,000 plus acres in other parts of the Denver-Julesburg and Powder River basins.

We’ll hear more from Noble soon, but with results like Anadarko’s, don’t expect development to slow down any time soon.

“Based upon the early results of Anadarko’s program in the Wattenberg field, we are confident the liquids-rich Horizontal Niobrara and Codell opportunity provides a net resource potential of 500 million to 1.5 billion BOE (barrels of oil equivalent); and it’s located right in the heart of one of our existing core areas,” said Anadarko Sr. Vice President, Worldwide Operations, Chuck Meloy.

Anadarko is the largest net producer in the liquids-rich Denver-Julesburg (DJ) Basin at greater than 70,000 BOE per day. The company holds interests in more than 350,000 net acres in the Wattenberg field, and operates more than 5,200 existing wells with an average working interest of approximately 96 percent, and an average net revenue interest of approximately 88 percent.

“Outside the Wattenberg field, we’re also exploring additional liquids-rich horizontal opportunities where we hold another 550,000 net acres in the greater DJ Basin and 360,000 net acres in the Powder River Basin. Each area is prospective for the Horizontal Niobrara, as well as other horizons that we will evaluate over time.”

Read the entire news release at anadarko.com

Preliminary results from a University of Texas study on hydrualic fracturing indicates the process does not contaminate drinking water. It does increase the chances for surface contamination, but they were not able to directly tie the process to drinking water contamination.

Prior reports, investigations and data gathered throughout the country on claims that the process often called fracking contaminated groundwater so far don’t make the direct link, said Chip Groat, a UT geologist who’s leading the study.

Rather, it appears that shale drilling results in more problems on the surface than drilling that doesn’t involve fracking, including spills of drilling and fracking fluids, leaks from wastewater pits and other rule violations, said Groat, who’s to unveil unveiling the preliminary results of the study in today Fort Worth.

The study also found regular reports of problems with surface casing — the steel pipe installed at the top of a well to keep the flow of hydrocarbons isolated from aquifers — and with cement jobs that hold the casing in place, Groat said.

Read the full news article at mysanantonio.com 

Chesapeake Energy announced its long awaited Utica Shale joint venture (JV) Nov. 3. We’ll have to wait a little longer to find out who the partner is. We simply know it is an international company. Exxon already has a position in the play and would be a likely candidate, but they don’t have a history of participating in this type of deal. It is likely someone else.

Chesapeake is selling a 25% interest in 650,000 net acres in wet gas window for $2.14 billion or $15,000 per acre. Enervest operates approximately 80,000 of the 650,000 acres and will receive $300 million in the deal. Approximately $640 million will be paid to Chesapeake upfront and the remaining balance will be paid in the form of a cost carry that can stretch through 2014.

It will be interesting to see what happens in the dry gas areas and the oily areas. CHK has an approximate 800,000 additional acres prospective for oil and dry gas. This might be an indirect signal that wet gas formations have the most favorable production characteristics in shale.

The company also has plans to raise $1.25 billion through selling perpetual preferred shares to accelerate drilling in the play. As part of the financial transaction, the company has committed to drilling 50 wells per year or 250 wells total through 2016. With plans to ramp up to 40 rigs, I don’t think there will be any problems hitting those numbers.

Chesapeake will serve as the operator of the JV and will conduct all leasing, drilling, completion, operations and marketing activities for the project. The LOI provides that the JV partner will have the option to acquire a 25% share of all additional acreage acquired by Chesapeake in the JV AMI and the option to participate with Chesapeake for a 25% interest in midstream infrastructure related to production generated from the assets. The LOI provides for the execution of definitive transaction documents and closing by mid-December 2011.

Read the full press release at chk.com

Frack water recycling is gaining popularity as the volume of water used rises across popular shale plays. In a year of record drought in Texas, you can bet water concerns will become a larger issue if rain doesn’t come. It’s perception if nothing else. Millions of gallons are used in oil & gas completions and recycling increases the useful life of the water. It also saves the industry from the need for disposal wells.

When a Barnett Shale gas well is fractured, 2 million to 3 million gallons of water, along with a large volume of sand and a lesser quantity of chemicals, are pumped down a wellbore under high pressure to create fractures in rock, through which gas can flow into the wellbore.

On a typical Barnett Shale gas well, roughly 10 to 20 percent of the water used in fracking might come back up the well as “flowback water” that can be recycled.

The Rover “is a system you can basically drive from well pad to well pad,” said Luke Thomas, vice president of business development for Fountain Quail, a subsidiary of Aqua-Pure Ventures, based in Calgary, Alberta.

In a statement, Aqua-Pure Chairman Richard Magnus said, “We believe this technology, which enables producers to recycle water on demand near the wellhead, will quickly become a widely accepted practice in our industry.”

Read the full news release at star-telegram.com

Mineral rights disputes get more serious when a boom hits. No one cares too much about what they own below the surface until it has value. Eagle Ford Shale sized value. That’s when the lawyers come out. In places like Texas, an operator might be working with landowners and mineral owners who have severed rights dating back 100 years. Over a period of 100 years, there is a lot of opportunity for misunderstood or bad transactions. In the case laid out below, it seems as if the landowners will triumph, but if the bank can prove its ownership you can bet they’ll be happy to have royalties in Karnes County.

If for no other reason than to save your heirs the trouble, make sure you get proper legal advice in all land transactions.

“My great-grandmother did not sign her name,” Frank Moravits said. “Somebody from McMullen signed her name to the paperwork.”

In 1943, a judge declared the signatures invalid and returned the mineral rights to Mary and her family.

Her descendants gave the rights little thought until the recent boom in the Eagle Ford shale, which became one of the hottest drilling prospects in the nation, with leases in some areas soaring to as much as $10,000 an acre.

Frank Moravits leased the mineral rights to a group of investors who entered into a drilling deal with Houston-based Petrohawk Energy. Before Petrohawk could begin drilling, though, another company showed up, also claiming to hold the mineral rights.

Read the entire news release at mysanantonio.com

Drilling is expanding in urban areas like Denver, Dallas-Fort Worth, and Pittsburgh. Don’t expect that to change any time soon. The industry will go where it can make a margin. The side effect is the industry is much more visible to the average citizen. Oil & gas producers will be educating people about the industry for years to come.

A half-hour north of downtown Denver, Weld County stretches toward Wyoming with more active oil and gas wells — 17,388 as of this month according to state figures — than almost any other county in the United States

An hour south, the state’s second-largest city, Colorado Springs, is scrambling to write its first drilling regulations, with the prospect of wells within city limits as early as next year. An 18,000-acre former ranch — zoned for housing that mostly never materialized — was bought this month on the city’s east side for $20 million by a Canadian company, Ultra Petroleum, which has also bought more than 100,000 acres of mineral rights farther east in El Paso County in recent months. The county, officials say, has never had a producing oil or gas well in historical memory.

To the west, in the high-country playlands of the Rocky Mountains, the story is the same: drilling, and tensions over drilling, in places where that generally has not happened before. In Routt County, west of Rocky Mountain National Park, energy companies are exploring extensions of the Niobrara. In affluent Aspen, county commissioners have passed regulations, now being fought by the industry, that would all but halt exploration.

Read the full news release at nytimes.com

The Weld County, Colorado, oil & gas industry supports 70% of educational expenses across the state. That’s an impressive number. Weld County has zero debt and the lowest tax rates of any county in the state. Just more support that oil & gas jobs are created and the economy performs well when drilling and production are supported.

Weld County Commissioner Sean Conway, for instance, touts the benefits the oil and gas industry has brought to Weld County.

“The governor has said that 70 percent of all revenue generated for K-12 education across the state is generated in Weld County by the oil and gas industry,” he said. “That’s a huge impact.”

And the benefits are passed along to Weld County taxpayers. ”The mill levy in the county is set just a little over 16 mills, which is considerably lower than the level allowed by the Taxpayers Bill of Rights (TABOR),” Conway said. “We have the 12th best job performance out of all the counties in the United States.”

The boom has also kept Weld County debt free, the only county in Colorado to be so.

“It allows us to have a real competitive business environment, and our residents sure appreciate the extras,” he said.

Read the entire article at coloradoan.com

Pennsylvania prisons and educational facilities may be granted the right to lease their minerals. Currently, only the conservation commission and the game commission benefit from mineral rights that sit atop the Marcellus Shale. The bill will broaden authority for oil & gas leasing on commonwealth lands.

If a separate bill passes, the facilities will get to keep 60% of the royalty revenue generated from the properties.

Land surrounding Pennsylvania’s state prisons and the State System of Higher Education colleges are among the commonwealth-owned property that should be considered for gas drilling, according to a report issued this morning.

Issued by a joint legislative committee, the report concludes that agencies beyond the Department of Conservation and Natural Resources, Game Commission and Fish and Boat Commission should be allowed to enter into lease agreements for gas drilling. Those agencies also should be allowed to retain a portion of any drilling-related revenues, according to the report.

It also noted that 16 state prisons sit on top of the Marcellus Shale formation, mostly in the western portion of the state.

The recommendations in the report echo an interest from lawmakers in tweaking the existing law to broaden authority for leasing to gas drillers

A Senate measure to allow such mineral-rights leases awaits a final vote. Another measure in the House of Representatives would allow the State System colleges to keep 60 percent of any royalties payments for drilling on a college’s property, with the remaining 40 percent to be divided among system schools that are unable to host a Marcellus well.

Read the full news release at post-gazette.com

Ohio’s dormant mineral act passed in 1989 might open the door for some land owners who recently found their minerals were reserved years ago. There is potential for reclaiming the oil & gas minerals if they have gone undeveloped for many years. This is important for everyone in the midst of the Utica Shale boom in Ohio.

Proper legal counsel will be needed in a circumstance such as this one, but don’t count yourself out until you’ve done the research. Find a local Ohio lawyer with experience in Oil & Gas.

There is a way for some property owners to regain their mineral rights, using the state’s Ohio Dormant Minerals Act if the minerals haven’t been used for 20 years.

“They need to go to an experienced attorney,” Hillyer said of people considering this measure.

The law, passed in 1989, outlines several steps property owners must take. First, they must serve a notice of intent to have the minerals declared abandoned. They then must filed an affidavit of abandonment with the county recorder where the land is located. The holder of the mineral rights must take action to preserve those rights. If the holder fails to do so, the law considers the mineral interest abandoned

There are several exceptions to the law. This procedure does not apply to coal resources or minerals held by the federal or state government or any political subdivision.

Read the entire news release at timesreporter.com

Statoil is acquiring Austin based Brigham Exploration in an all cash transaction worth $4.4 billion. The deal builds on Statoil’s current positions in the Marcellus and Eagle Ford shales, as well as giving the company its first operated position in the onshore U.S.

The company paid a 36% premium to BEXP’s previous 30 day average trading price. Statoil gains >20,000 barrels of oil equivalent per day of production in the Bakken and more than 375,000 acres across the Wiliston Basin.

This deal is the latest in a string of mergers and acquisitions in 2011 that have involved many international companies from around the globe investing in U.S. shale deposits.

The total equity value is approximately USD 4.4 billion, reflecting an enterprise value of approximately USD 4.7 billion, based on June 30, 2011 net debt.

The transaction will provide Statoil with more than 375,000 net acres in the Williston Basin, which holds potential for oil production from the Bakken and Three Forks formations. Brigham also holds interests in 40,000 net acres in other areas. At this early stage of development the risked resource base is estimated at 300-500 million barrels of oil equivalent (boe), equity. Current equity production is approximately 21,000 boe per day, and the acreage has potential to ramp up to 60,000-100,000 boe per day equity production over a five year period.

The Bakken and Three Forks formations are among the largest oil accumulations in the United States. Various sources have estimated the technically recoverable reserves to be in the range of 5 – 24 billion boe, over a 38,000 square kilometers area. The attractiveness of the Bakken and Three Forks plays has resulted in Statoil offering a 36% premium over the average trading price of Brigham stock for the last 30 days.

Read the full press release at statoil.com

Joining together with other landowners can increase your bargaining power as well as make paying an attorney an economically feasible option. Farmers in Ohio are joining forces to help negotiate leases that do more than simply lease their minerals. Lease bonuses have soared in recent weeks to as much as $5,000 per acre is hot areas of Ohio.

Years ago, Bob Rea of Leetonia in Columbiana County was approached about leasing the mineral rights to the 40-acre farm, passed down from his great-grandfather.

He studied the contract the leasing agent gave him and said he realized it was written to benefit of the oil companies. So, Rea along a group of landowners started the Associated Landowners of the Ohio Valley, or ALOV, a non-profit organization. They have represented landowners from 11 counties around Columbiana County and completed leases on 100,000 acres with 100,000 acres still pending.

“Too many farmers were signing for the bonus money, giving the drillers all the rights and little oversight by the owner,” said Rea. “Twenty-five years ago, signing bonuses for a lease were $2 to $5 per acre, now it’s nearing $5,000 an acre.”

Working with a legal firm drafting lease language, Rea said the ALOV is “farmers helping farmers.”

“We want to be very specific, we think that’s the first step in understanding mineral ownership,” he said.

“This natural gas boom has the opportunity to bring jobs back to this area like we have not seen the steel industry,” said Jill Mcnicol.

Read the entire news article at nbc4.com

Forbes conducted a great interview with Chesapeake’s Aubrey McClendon last week. A few notable quotes below:

In reference to the recession in 2008 and losing a chunk of his fortune

I (McClendon) believed in our country and its leadership, and never in my wildest dreams did I think that CHK’s stock price could go from $70 to $16 in 100 days.

In regards to his compensation

You may recall that the $75 million award was not in the form of cash and it had a 100% clawback embedded in it. All in all, I think the award was effective in achieving its goals. I also don’t think it’s well known that at that time I agreed to have my cash compensation held flat for five years. Keep in mind that approximately 85% of my direct compensation for the last two years has been in the form of restricted stock. In fact, in 2010 the number of shares that I received went down by about 15% compared to 2009, and yet the value of my overall compensation went up because the stock price went up by more than 15%.

How he views leasing land”

Take the Eagle Ford shale for example.  Under each acre of land we have acquired there, we believe there is roughly 5,000 barrels of recoverable oil equivalent.  When we put our land position together in that play, we spent roughly $1.2 billion to buy about 600,000 acres of land, giving us an average cost basis of about $2,000 per acre, or roughly $0.40 per barrel of oil equivalent. I ask you, could you go to Wall Street and buy an option to develop 3 billion barrels of oil equivalent at a cost of $10-$15 per barrel for a call option cost of only $0.40 a barrel?  Of course not, there’s no way you could do that in the financial markets.  But yet, we do it in the reality of the oil and gas world all the time.  Too many analysts and investors fail to appreciate that leasehold is simply a very cheap call option on the right to develop resources in some of the best plays the world has to offer.

In addition, please remember that we just sold in a very low gas price environment, our interest in the Fayetteville Shale for an approximate $3.5 billion profit.  I think that is a testament to our land acquisition skills, as well as our resource development skills, and obviously a very strong comment about our ability to create billions of dollars in shareholder value every year in addition to the everyday job of drilling wells.

In addition, you may be familiar with our 25/25 Plan where we told our investors in January 2011 that by the end of 2012 our debt would be 25% less than it was at year-end 2010, or basically at $10 billion in total.  We will certainly achieve that goal, and I also believe that by year-end 2015 our debt levels will remain below $10 billion and the value of our company should be north of $75 billion and people will have stopped long ago about asking about our balance sheet – it will be rock solid.

In response to a comment that he’ll always lease and acquire land:

I see nothing wrong with acquiring acreage in a new play and then selling off say 25% to 33% in that play to another company and thereby reducing our shareholders’ exposure in that play to perhaps a net zero investment and we have the remaining 67-75% for free – how can you go wrong doing that?

McClendon’s view of gas supply

You can’t ask people to use more of your product unless you can prove to them that you can produce more of the product at the same price every day. I think we have successfully done that and have kicked off the beginning of a demand revolution in the US, which will result in an industrial rejuvenation, a cleaner environment by burning less coal, and in an economic revival in the US when we finally figure out that we can’t afford to export $5 trillion of national wealth every 10 years for the importation of foreign oil.

His view of the Fracking debate:

Against that track record of over 1.2 million frac jobs performed by the industry, our critics can only find one or two instances of alleged groundwater pollution, and having examined those few instances ourselves, we don’t agree that that fracking had anything to do with the alleged groundwater contamination.

So, the key thing here is to keep in mind that the chemicals that we use in our frack fluids are highly diluted and that, unlike the ones that you come across everyday in your normal home and work environments, we inject our chemicals 5,000-10,000 feet below the ground.

The benefits of using in house oilfield services:

Our job, on the other hand, is to create value for CHK’s shareholders and to do that at the highest level, we have felt over the past 10 years that it is important to vertically integrate our business to deliver products and services to our wells at a cheaper cost than we could have them delivered by a third party. This gives us not only lower finding costs than we would otherwise have, but also creates a great inflation hedge.  We intend to roll all these entities up into our newly formed service company holding company, Chesapeake Oilfield Services, and our hope is to take the business public at some point in 2012.

Read the entire interview at forbes.com