Wednesday, May 21, 2014

Sanchez Acquires Additional Eagle Ford Acreage; $6,000/Acre (De-Risked/Producing); XTO To Acquire 26,000 Additional Acres In The Permian

It seems I've read this before, possibly even posted it earlier. Whatever. Rigzone is reporting:
Royal Dutch Shell plc will sell to Sanchez Energy Corp. its interest in Eagle Ford shale assets as the company refocuses its North American portfolio on acreage where it can reach the scale it needs to successfully execute projects.
Houston-based Sanchez will acquire Shell’s 100 percent working interest in approximately 106,000 net acres in Dimmit, LaSalle, and Webb counties in south Texas, which includes approximately 176 operated producing wells and associated field facilities and infrastructure.
The assets include 60 million barrels of oil equivalent of proved reserves. Net production from this acreage in first quarter 2014 was approximately 24,000 barrels of oil equivalent per day (boepd); around 60 percent of this production was crude and natural gas liquids. The acquisition will boost Sanchez’s position in the Eagle Ford to around 226,000 acres, with up to 3,000 potential drilling locations and average first quarter 2014 pro forma production of about 42,800 boepd, Sanchez said in a May 21 press statement.
The pro forma potential drilling locations of nearly 3,000 wells include 200 identified low-risk and high rate of return drilling locations and up to 800 additional potential locations.
I don't think the Rigzone article mentions the price (I may have missed it) but FuelFix says it was a $639 million deal for 106,000 de-risked/producing acres. BOTPE: $639 million / 106,000 acres = $6,000/acre.  

A bit more about Shell's re-focusing:
Shell has previously divested its acreage position in the Mississippi Lime play in Kansas, its position in Ohio’s Utica shale and part of its acreage in Colorado’s Sandwash Niobrara basins.

Meanwhile, Rigzone is also reporting that in an exchange deal, XOM/XTO will add 26,000 acres to its North American portfolio:
Exxon Mobil Corporation announced Wednesday that it has executed an agreement to add nearly 26,000 acres to its U.S. oil and natural gas portfolio managed by subsidiary XTO Energy Inc., through a non-monetary exchange with LINN Energy, LLC. Virtually all of the acreage is located within the portion of the Midland Basin that is most prospective for horizontal Wolfcamp and Spraberry development. In exchange, LINN Energy will receive a portion of XTO’s interest in the Hugoton gas field in Kansas and Oklahoma.

Canadian Company To Try Nitrogen Flooding In Saskatchewan/Manitoba Bakken/Three Forks Wells

Every now and then a really good article comes across "my desk." Generally I do not know how good an article might be until weeks or months later. But something tells me this might be a very good article to bookmark for future reference.

A reader sent it to me. A huge thank you to the reader.

The article has to do with enhanced oil recovery (EOR) using nitrogen instead of CO2.

One should review primary, secondary, and tertiary oil production at wiki.

I'm getting out of my comfort zone and could be very, very wrong on this, but reading the wiki article as well as Schlumberger definitional resources, and then the new article (linked below), it looks like using nitrogen to help recover oil could fall into either secondary or tertiary production.

Again, outside of my comfort zone, it appears "secondary" production has to do with increasing reservoir pressure whereas "tertiary" production has to with decreasing viscosity. Depending on "how" one used a gas such as CO2 or N2 determines whether it is "secondary" or "tertiary" recovery. EOR is generally "synonymous" with tertiary recovery. (Further confusing matters, there is some suggestion that the operators consider this use of nitrogen to be part of primary production; see below.)

Again, this is all colloquial.

[Confusing matters further, nitrogen apparently can also be used for fracking, or at least has been tried. At the bottom of the blog, I have a "Fracking_Nitrogen" tag, for example.]

junewarren-nickle's energy is reporting:
Tundra Oil and Gas Partnership is seeking regulatory approval for an immiscible nitrogen flood in the Middle Bakken/Three Forks tight oil formations in the Daly Sinclair field of southwest Manitoba.
Based in Winnipeg, Tundra is a privately held light oil producer that operated the drilling of 168 wells in Canada last year -- 163 in Manitoba and five in Saskatchewan.
This isn’t the company’s first foray into gas flooding in a tight oil formation. Since August 2008 Tundra has been operating a miscible gas pilot injecting carbon dioxide in the southeast quarter of section 04-08-28W1 within Sinclair Unit No. 1. Last August this pilot was approved for conversion to a water-alternating-gas project.
Now the company is applying for an immiscible gas injection pilot using nitrogen. (In miscible gas floods, the injected gas forms a single homogeneous phase with the oil. The resulting fluid has lower viscosity, reduced interfacial tension and improved mobility. While immiscible gas doesn’t form a single phase with the oil, it still has the benefit of improved pressure maintenance and sweep efficiency within the reservoir.)
This is a long, long article and many, many data points.

First, of all, this is a Canadian story, with subject wells in Saskatchewan and Manitoba.  I talked about the Bakken in Manitoba in a recent post, but in that post, the Canadian Three Forks was referred to as the Torquay.

Second: in this new article, the difference between using CO2 and N2 is spelled out very nicely. The big difference is that using N2 is much less expensive than using CO2, is readily available, and doesn't get into the issue of global warming/greenhouse emissions.

A third data point has to do with the general recovery rate of crude oil from the Bakken/Three Forks in this area (Saskatchewan/Manitoba):
Total net original oil in place (OOIP) in the proposed project area is estimated at 2.78 million bbls for an average of 174,000 bbls per 40-acre legal subdivision.
According to Tundra’s application, oil production per well in the proposed project area peaked in 2009 at 268 bbls a day. As of last November, average oil production per well had fallen to 9.6 bbls a day. Production is forecast to continue declining at a rate of nearly 29 per cent a year.
By last Nov. 30 cumulative production from the four wells within the proposed Ewart Unit No. 5 project area was 206,500 bbls of oil and 292,800 bbls of water. The recovery factor was 7.4 per cent of the net original oil in place.
Estimated ultimate recovery of primary proved producing oil reserves in the proposed project area is estimated at 256,000 bbls with 49,500 bbls remaining as of last Nov. 30.
Under the current primary production method, ultimate oil recovery of the proposed Ewart Unit No. 5 is forecast to be 9.2 per cent of the original oil in place.
Note the "downspacing": 40 acres. (In one test, they plan to go to 20-acre spacing, also.)

Note the recovery rate:  7.4% of the net original oil in place (OOIP) prior to N2 flooding.

With N2 flooding, they propose a recovery rate of 9.2%.

Note the EUR of these Bakken/Three Forks wells: 256,000 bbls. Compare with EURs of Bakken/Three Forks in North Dakota -- suggested to range between 400,000 and one million bbls.

This is where it gets a little confusing. In bold in the above paragraph, it sounds like they consider N2 flooding part of primary production: "Under the current primary production method, ultimate oil recovery of the proposed Ewart Unit No. 5 is forecast to be 9.2 per cent of the original oil in place."

This seems accurate because almost immediately, the article talks about "secondary" / EOR production:
Tundra estimates ultimate recovery of proved oil reserves in the project area, using a secondary water-alternating-gas EOR scheme, would be 379,000 bbls of oil with 176,000 bbls remaining.
And here, the author writes "secondary" and "EOR."

Be that as it may. It's a long, long article, with many, many data points. As noted at the beginning, this may turn out to be an article we come back to again and again.

Oh, by the way, there is at least instance in which N2 injection was being considered by an operator in the North Dakota Bakken. In the August, 2012, NDIC hearing dockets, case 18402:
  • 18402, Whiting, nitrogen injectivity test in the Sanish, Mountrail
Big disclaimer: I may have misinterpreted the linked article. I don't spend a lot of time sorting all these articles out the first time I go through them. If you are interested in this particular subject, I would ignore what I've written and go directly to the source.

Perhaps the most important takeaway from this article: rate of recovery before additional measures -- about 7%. My hunch is that newer, more aggressive technology in the North Dakota Bakken is resulting in a great percentage recovery. 

RBC Capital Suggests North Dakota Will Hit Million-BOPD Milestone Early Summer

The tea leaves suggest that North Dakota will have passed the million-bopd milestone as of last month (April, 2014). It was noted at this post. We will know in the next Director's Cut. It was with a small chuckle that I read this note from RBC Capital at SeekingAlpha:
  • Oil and gas producers in the Bakken Shale saw a pickup in production in March and should see an even bigger increase as the weather turns warmer, according to a new report from RBC Capital.
  • Bakken development activity rose to 200 well completions in March vs. 70 in February, and well backlog remains high at ~635 wells, RBC says, expecting operators to work through the backlog since North Dakota has experienced a relatively warm spring.
  • "As completion activity catches up in the early summer and drilling activity remains strong, oil production should top 1M bbl/day around mid-year, the report says.
"... according to a new report from RBC Capital." -- It would be nice if the real source of this information would have been cited: the Director's Cut, North Dakota Industrial Commission. 

Summer: June, July, August, I believe. Early summer: June.

For Investors Only -- May 21, 2014; CLR Trades At 52-Week High


Later, 7:42 p.m. central time: this really isn't an update, just a comment. Mineral owners should be happy with oil at $104 today. For investors in the oil and gas industry, and for investors in the stock market in general, $104-oil is not good. I would prefer that oil remain in its historical trading range. It scares me when speculators start driving the price of oil up. Regular readers know my feelings about "speculators."

Original Post

Trading at new 52-week highs: BP, BRK-B, CLR, NFX, TRGP, WMB.

Oil trades up almost 2% -- hits $104.

47% of unemployed have 'completely given up' looking for a job -- The Weekly Standard. The same percent of the population that would never vote for Mitt Romney.

10 million US citizens on disability. New record. First time in history.

CO2 400 parts per million. New record. First time in history.

385 days. Number of days since Phoeniz, AZ, whistleblower in VA scandal was transferred from her place of duty. I guess yesterday, her boss, the commander-in-chief, as he referred to himself several times today, became aware of that.

At least 8. Number of years the president has been working on the VA problem. He said he started working the problem when he was running for the US Senate. 

1. The number of deaths due to a 1967 Oldsmobile being driven off a Chappaquiddick bridge.

0. Number of deaths in US due to CBR trains derailing. 

Disclaimer: this is not an investment site. Do not make any investment decisions based on anything you read here or think you may have read here.

Quite a Day on Wall Street

Oil will close near $104/bbl.

Majors (CVX, COP, XOM): all in the green, though COP barely moved. The other two up about 1.5%.

Service companies (SLB, HAL, BHI): all in the green; about 1%.

ENB, WMB: ENB up about 1%; WMB trading at a new 52-week high.

  • OAS: goes over $50 first time in a long time; up over 5% today.
  • KOG: up 4%.
  • WLL: up 2%
  • CLR: up over 3%; traded at 52-week high.
Other shale:
  • EOG: up 2%
  • SD: up almost 3%
  • CHK: flat (slightly up)
  • HK: flat (slightly up)
  • BRK-B: flat, up sightly
  • UNP: trading near its 52-week high; up 3/4th of a percent

Rawson Oil Field

28424, loc, Whiting, Good Shepherd 41-15H-2H,
28423, loc, Whiting, Good Shepherd 41-15H,
28226, loc, Triangle Petroleum, Paulson 150-101-23-14-4H,
28225, loc, Triangle Petroleum, Paulson 150-101-23-14-3H,
28224, loc, Triangle Petroleum, Paulson 150-101-23-14-2H,
28223, loc, Triangle Petroleum, Paulson 150-101-23-14-1H,
27566, 622, Triangle Petroleum, McCabe 150-101-24-13-4H,
27565, drl, Triangle Petroleum, McCabe 150-101-24-13-3H,

27230, drl, Triangle Petroleum, Rowe 150-101-1-12-6H,
27229, drl, Triangle Petroleum, Rowe 150-101-1-12-5H,
26232, 414, Triangle Petroleum, Dwyer 150-101-35-26-4H, t2/14; cum 32K 3/14;
26231, drl, Triangle Petroleum, Dwyer 150-101-35-26-3H, producing,
26230, 348, Triangle Petroleum, Dwyer 150-101-35-26-2H, t2/14; cum 31K 3/14;
25718, 633, Triangle Petroleum, McCabe 150-101-24-13-2H, t11/13; cum 66K 3/14;
25717, 622, Triangle Petroleum, McCabe 150-101-24-13-1H, t11/13; cum 70K 3/14;

24546, 485, Triangle Petroleum, Dwyer 150-101-35-26-1H, t5/13; cum 65K 3/14;
24279, 478, Triangle Petroleum, Triangle 150-101-36-25-5H, t8/13; cum 74K 3/14;
24278, 436, Triangle Petroleum, Triangle 150-101-36-25-6H, t8/13; cum 83K 3/14;
24277, loc, Triangle Petroleum, Triangle 150-101-36-25-7H,
24276, loc, Triangle Petroleum, Triangle 150-101-36-25-8H,
23620, loc, Triangle Petroleum, Rowe 150-101-1-12-4H,
23619, 355, Triangle Petroleum, Rowe 150-101-1-12-3H, t6/13; cum 101K 3/14;
23618, loc, Triangle Petroleum, Rowe 150-101-1-12-2H,
23617, 634, Triangle Petroleum, Rowe 150-101-1-12-1H, t6/13; cum 87K 3/14;
23523, 1,510, Murex Petroleum, Rose Marie 3-10H, t12/12; cum 85K 3/14;
23426, loc, Triangle Petroleum, Sanders 150-101-3-10-1H,
23416, 895, Murex Petroleum, Jade Brenna 2-11H,
23414, PNC, Zenergy, Jacobson Family 26-36H,
22892, 1.552, Oasis Petroleum, Dwyer 27-34H, t9/12; cum 87K 3/14;,

21828, loc, Triangle Petroleum, Gullickson Trust 150-101-36-25-4H,
21827, 1,173, Triangle Petroleum, Gullickson Trust 150-101-36-25-3H,
21826, loc, Triangle Petroleum, Gullickson Trust 150-101-36-25-2H,
21825, 984, Triangle Petroleum, Gullickson Trust 150-101-36-25-1H, t6/12; cum 104K 3/14;
21515, 853, Whiting, Good Shepherd Home 150-101-15B-22-1H, t10/12; cum 76K 3/14;

No permits
Some selected wells permitted prior to 2010
9328, AB/29, Triangle, Berge-FLB 1-24, Rawson, t4/82; cum 212K 9/12; 
8706, Red River/Madison, 153/64; Triangle, Berge C 1, t1981/1990; cum 40K/cum 133K 9/12;
7845, Duperow/Madison, 70/142, Triangle, Nygaard State 1, t7/18/t9/85; cum 37K 134K 3/14;
Original Post

Rawson oil field is a 3-section x 6-section field; a rectangular, 18-section field. It is one of the sweet spots in the Bakken, located in north-central McKenzie County, just west of Watford City and west of some of the sweetest spots int the Bakken. US Highway 85, running east-west through Rawson oil field, cuts the field exactly in half,with 9 sections to the north and 9 sections to the south. The field lies almost exactly midway between Alexander, North Dakota, and Arnegard, North Dakota. Watford City is about 12 miles to the east. On the date of the original post, most permits in Rawson were Triangle Petroleum permits. The largest truck wash facility in the United States is located just to the west of this field.

Random Data Point From EOG's 1Q14 Earnings Conference Call

From EOG's 1Q14 Earnings Conference Call 

In the Eagle Ford:
In modeling production from the Eagle Ford we are on a growth track for the next 10 years; and, I want to repeat: in modeling production from the Eagle Ford, we are on a growth track for the next 10 years before we even begin to see production level out.
So, what about the Bakken? What is EOG's modeling for the Bakken?

In the question and answer period:
Analyst: I liked your comments on your 10 years of growth in the Eagle Ford. Given that you model back, can you about how many years of growth do you see in the Bakken?
Bill Thomas: We have not done that extensive model in the Bakken yet, because we’re really in the initial stages of downspacing, and I want to ask Billy Helms to make some comments on that.
Billy Helms: For our Bakken as we illustrated, we’re still very satisfied, very pleased with our 1,300 foot spacing test. But we realized that our NPV, net present value, was not maximized. So, we’re going to be doing lots of additional testing, we did talk about 700 foot spacing pattern and we’ll be testing some various spacing patterns as we try to define how to maximize net present value. 
This is a similar approach as we've done in most of our shale plays across the company. and until we really find out what that formula looks like, we're really kind of hesitant to state what the upside not be there, but certainly we will provide some more effort on that as we go forward the year, and we're very confident that we're going to have success there.
 I think, if I recall correctly, a reader told me that EOG took lessons learned in the Eagle Ford back to the Bakken, and are already seeing better results with new completion techniques. This short interchange tends to confirm that.

Downspacing: Relationship Effects Of Neighboring Wells

In that same conference call, this exchange:
David Heikkinen - Heikkinen Energy Advisors: On the maximizing NPV, one of the things we've talked a lot about is your IRR doesn't change much, but your EUR may decline per well as NPV goes up. Is that a fair characterization of how your downspacing could actually roll forward?
Bill Thomas: Yes, that's correct. Naturally, as you push wells closer together, you're going to end up having some sharing between wells. That's just inevitable. Our rate of return is still very, very high as you stated, but what we end up doing is adding a lot more recoverable reserves, and there is a lot more net present value to each spacing unit that we drill. So, that's kind of our overall process. And we're still early on in the space, certainly in the Bakken as we try to define that.
I interpret that to mean this: EOG suggests that downspacing (putting wells closer together) in a spacing unit, will increase the amount of oil produced in that spacing unit (and thus increase the net present value to each spacing unit. However, it appears to me he is suggesting that the EUR will decrease in wells that are close together and "sharing."

That's an important interchange, critical to understanding the Bakken. Compare that interchange with what Motley Fool and CLR suggest at this link

The Bakken, May 21, 2014: Only Four (4) New Permits; MRO Reports A Nice Well Thursday; 5 Of 6 Wells Go To DRL Status

Wells coming off the confidential list Thursday:
  • 25671, drl, Statoil, Larsen 3-10 4H, Williston, no production data,
  • 25964, drl, Petro-Hunt, Syverson 156-99-30A-31-2H, East Fork, no production data,
  • 26653, drl, XTO, Jan 14X-34A, Siverston, no production data,
  • 26793, drl, Hess, BB-Belquist-150-95-1110H-7, Blue Buttes, no production data,
  • 26925, 1,687, MRO, Irene Ell 11-1H, Murphy Creek, producing, t3/14; cum 15K 3/14;
  • 27055, drl, Petro-Hunt, Van Hise Trust 153-95-28D-21-1HS, Charlson, no production data,
Active rigs:

Active Rigs188188209178116

Four (4) new permits --
  • Operators: Whiting (2), Oasis, Corinthian Exploration
  • Fields: Rawson (McKenzie), Baker (McKenzie), North Souris (Bottineau)
  • Comments: I believe the two Whiting permits in Rawson oil field might be the first for Whiting in that field; if not the first, rare; the oil field is pretty much owned by Triangle, going to permits back to 2010
Wells coming off the confidential list were posted earlier; see sidebar at the right.

Wal-Mart Continues To Support An Increase In the Minimum Wage

Active rigs:

Active Rigs188188209178116

RBN Energy: Permian Basin pipelines -- part 4.
No fewer than 28 publicly listed companies are currently drilling in the Permian Basin – including industry stalwarts like Occidental Petroleum, ConocoPhillips, Chevron, and Shell as well as independent producers like EOG Resources, Pioneer Natural Resources, Concho Resources and Apache. Overall crude production is over 1.5 MMb/d and headed to 1.7 MMb/d by the end of 2014. Current hot spots include the Wolfcamp horizontal shale play in the Midland Basin – featured in our latest Drill Down Report. Today we look at new gathering systems in the Midland that will transport up to 490 Mb/d of crude to Crane and Colorado City, TX.
The Wall Street Journal

Russia, China fail to sign natural gas deal. [Update: China and Russian sign the landmark, $400-billion-natural-gas-pipeline deal - 9:00 a.m. EDT, May 21, 2014]
Even if Russian and Chinese officials agree on a price to secure future gas supplies, the fortunes of Gazprom are likely to remain deeply interwoven in the European market.
Gazprom provides 30% of Europe's gas, around half of which flows through Ukraine. Gazprom needs the higher price it receives for exports to Europe to compensate for the much cheaper price it charges in its domestic market, where gas is subsidized.
Last year Gazprom made 2.1 billion rubles ($60 million) from the 174 billion cubic meters it sold to Europe, a far higher profit margin than for domestic sales. It made just 794 million rubles from domestic sales of 243 billion cubic meters of gas. Any deal with China, on the other hand, would take years to become reality. Russia Energy Minister Alexander Novak said in March that Gazprom could start to supply China in 2019 or 2020. The initial volume of gas exported, around 38 billion cubic meters a year, would be small compared to the amount currently exported to Europe.
Even if capacity were increased to over 60 billion cubic meters later, as the Russians hope, the volume of gas will still only be around a third of what is currently exported to Europe. Gazprom's sales to Europe rose by 15% last year to 174.3 billion cubic meters—the highest since 2008.
Workers' new tactic in minimum-wage fight.
Stymied in Washington on their minimum-wage push, low-wage workers are now pressing for U.S. companies to raise wages voluntarily.
Fast-food workers have held rallies asking for hourly pay starting at $15. President Barack Obama is publicly praising companies—from retailer Gap Inc. to Punch Neapolitan Pizza, a tiny Minnesota pizza joint—that committed to paying workers more than the federal minimum wage of $7.25 an hour.
The activism comes after efforts to increase the federal floor to $10.10 an hour fizzled in Congress in recent weeks. Some major corporations have responded by being more open about pay practices, noting that few of their workers receive the minimum wage. Wal-Mart Stores Inc. last week said it doesn't oppose an increase to the federal pay floor. Bill Simon, Wal-Mart's U.S. president, said the retailer is "not a minimum wage payer," noting that only about 5,000 of the company's 1.3 million U.S. workers currently make the minimum wage in their states.
Staples profit drops sharply - a 43% drop in profits.

With Target, it helps to aim low. Target's perverse advantage going into its earnings report is that investors don't expect much.

Two Lead Stories In LA Times Today: Both Predicted! Two-Thirds Of Nation's Shale Oil Reserves Taken Off The Table

I first read the stories a couple of hours ago, lying in bed, reading them on the iPad. It was all I could do to keep from jumping out of bed and starting to blog.

I'll just do the headlines now and come back to the stories later, linking them to the appropriate spots in the blog, etc. but for now, here's the important stuff. Again, the lead stories in The Los Angeles Times today.

First, the headline story, front page: billions pledged for possible ObamaCare losses by health insurers; federal funds earmarked to offset Affordable Care Act insurer losses.
The Obama administration has quietly adjusted key provisions of its signature healthcare law to potentially make billions of additional taxpayer dollars available to the insurance industry if companies providing coverage through the Affordable Care Act lose money.
The move was buried in hundreds of pages of new regulations issued late last week. It comes as part of an intensive administration effort to hold down premium increases for next year, a top priority for the White House as the rates will be announced ahead of this fall's congressional elections.
Administration officials for months have denied charges by opponents that they plan a "bailout" for insurance companies providing coverage under the healthcare law.
They continue to argue that most insurers shouldn't need to substantially increase premiums because safeguards in the healthcare law will protect them over the next several years.  [most .... shouldn't .... need ....  substantially ... increase: parsing that sentence will provide fodder for pundits for months]
But the change in regulations essentially provides insurers with another backup: If they keep rate increases modest over the next couple of years but lose money, the administration will tap federal funds as needed to cover shortfalls.
Although little noticed so far, the plan was already beginning to fuel a new round of attacks Tuesday from the healthcare law's critics.
"If conservatives want to stop the illegal Obamacare insurance bailout before it starts they must start planning now," wrote Conn Carroll, an editor of the right-leaning news site
On Capitol Hill, Republicans on the Senate Budget Committee began circulating a memo on the issue and urging colleagues to fight what they are calling "another end-run around Congress."
Obama administration officials said the new regulations would not put taxpayers at risk.
"We are confident this three-year program will not create a shortfall," Health and Human Services spokeswoman Erin Shields Britt said in a statement. "However, we want to be clear that in the highly unlikely event of a shortfall, HHS will use appropriations as available to fill it."
What this means: in the competitive world of health care insurance, insurers will low-ball premiums to attract customers knowing that the government is now liable for losses. And the losses are open-ended. Blank check. Even some of the 47% who would never vote for Romney can figure this out.

By the way, there is a front-section story in The Wall Street Journal which reports unintended consequence but predicted in this blog: emergency room visits rise despite ObamaCare. Health act isn't cutting emergency volume so far; government says it's too early to draw conclusions.
Early evidence suggests that emergency rooms have become busier since the Affordable Care Act expanded insurance coverage this year, despite the law's goal of reducing unnecessary care in ERs.
Almost half of ER doctors say they are seeing more patients since key provisions of the health law took effect January 1, 2014, while more than a quarter say their patient volume has remained the same, according to a survey to be released Wednesday by the American College of Emergency Physicians.
Eighty-six percent of emergency doctors expect visits to rise over the next three years, though the email survey didn't ask the doctors why. Democrats who designed the 2010 health law hoped it would do the opposite. They wanted to give the uninsured better access to primary-care doctors who could treat routine ailments and prevent chronic disease, with the intent of keeping patients out of the ER and lowering the cost of care.
The median ER charge was more than $1,200 for the most frequent outpatient diagnoses in a study of over 8,000 ER visits in 2006-08, said a 2013 report funded in part by the National Institutes of Health.
Two-Thirds Of American Shale Oil Reserves Taken Off The Table By The Federal Governent

Okay, now the second story which is even better. I predicted the ObamaCare bailout story above and posted it often on the blog, but I also said the same thing about this second story regarding the Monterey Shale. We're never gonna see it. Right below the ObamaCare story in The Los Angeles Times story was this: Feds deal blow to nation's oil future with California oil estimate. US officials cut estimates of recoverable Monterey Shale oil by 96%.
Federal energy authorities have slashed by 96% the estimated amount of recoverable oil buried in California's vast Monterey Shale deposits, deflating its potential as a national "black gold mine" of petroleum.
Just 600 million barrels of oil can be extracted with existing technology, far below the 13.7 billion barrels once thought recoverable from the jumbled layers of subterranean rock spread across much of Central California, the U.S. Energy Information Administration said.
The new estimate, expected to be released publicly next month, is a blow to the nation's oil future and to projections that an oil boom would bring as many as 2.8 million new jobs to California and boost tax revenue by $24.6 billion annually.
The Monterey Shale formation contains about two-thirds of the nation's shale oil reserves. It had been seen as an enormous bonanza, reducing the nation's need for foreign oil imports through the use of the latest in extraction techniques, including acid treatments, horizontal drilling and fracking.
The energy agency said the earlier estimate of recoverable oil, issued in 2011 by an independent firm under contract with the government, broadly assumed that deposits in the Monterey Shale formation were as easily recoverable as those found in shale formations elsewhere.
If 96% is taken off the table, it's hard worth going after the other 4%. The headline should have been: California takes full loss on Monterey Shale. This has huge implications for the Bakken, the Eagle Ford, and the Permian.

But this was absolutely predictable: the geology alone was going to prevent horizontal drilling success. That was proved by lessons learned in the Bakken laboratory. But even if engineers could have finessed the geology, they never would have finessed the anti-fracking activists. The third strike -- the drought in California; everlasting water battles -- and "they're out" -- the companies who thought they were going to drill the Monterey.