JP Morgan upgraded CHK to overweight from underweight.
Looks like there may be some light at the end of the tunnel for this company?
JP Morgan upgraded CHK to overweight from underweight.
Looks like there may be some light at the end of the tunnel for this company?
For many decades the benefits of oil and gas development in the US have been overshadowed by the amount of money companies in the sector have made, the environmental impacts of use or development and occasional accidents and the degree to which imports impact US foreign policy and economic health.
The extent to which the US oil and gas business drives job growth, contributes to local and the national economies and has renewed potential to shift economic and political power back to the US were the focus of the American Petroleum Institute's State of American Energy presentation in Washington, DC today. API has sought ways to boost the reputation of the oil and gas industry in recent years after the industry faced unprecedented opposition to new development both on-and-offshore as new technology allowed access to onshore reserves and offshore development revived.
API quotes some extraordinary figures in its recent report (available here) to illuminate the oil and gas sector's contributions to economic health. It invites readers to imagine American lives without oil and gas, noting they would be "far different, making it exceedingly challenging for families to heat their homes and run their daily lives." What the alternatives might be, or how one might retroactively decarbonize an entire economy, isn't addressed in the report, which quickly turns to the sunny prospect of potential North American energy security replete with spiking job growth and even energy exports.
Some of the more striking statistics cited by API today include:
‚ÄĘ$1.1 Trillion: The total value added by the US oil industry to the national economy
‚ÄĘ$109.5 Billion: The projected amount US households will save between 2009 and 2020 due to lower household natural gas prices
‚ÄĘ$545 Billion: Amount directly provided by the oil and natural gas industry to the US economy in 2011 (according to a PriceWaterhouseCoopers report).
‚ÄĘOne million plus: The number of hydraulic fracturing wells API claims have been drilled without a case of groundwater contamination (API cites its own blog, quoting in turn outgoing EPA chief Lisa Jackson on proven cases of groundwater contamination).
‚ÄĘ9.2 million: The number of US jobs supported by American oil and gas
‚ÄĘ$94,500: The average salary for refinery workers
‚ÄĘ$29 billion: Cash dividends paid to shareholders of oil and natural gas companies
API sponsored an unprecedented advertising campaign around energy issues in the 2012 election cycle, read more about that effort here.
This is a good read about the movement of crude oil and the changes that are occurring
The Seven Gates of Hell for WTI Crude Traders ‚Äď Seaway Phase 2 and the Brent Differential
published by Sandy Fielden on Tue, 01/08/2013 - 18:55
By the end of this week (Friday January 11, 2013) Phase 2 of the Seaway Reversal pipeline project that delivers crude from Cushing to Houston is supposed to have come online - expanding pipeline capacity from 150 Mb/d to 400 Mb/d. Phase 1 of the project was eagerly anticipated by the market but since then (June 2012) the narrowing in price differentials between WTI Cushing and Brent expected by much of the market has not materialized. Today we explain why Seaway Phase 2 is only one factor in today‚Äôs complex US crude market evolution
RBN School of Energy brings the RBN Energy brand of energy market fundamentals to an intensive two-day course of study to be held Feb.12-13, 2013, at the St. Regis in Houston, TX. For more information, see http://www.rbnenergy.com/school-of-energy
The Seaway pipeline runs from Cushing, OK to Freeport, TX (passing through Houston on the way) and originally moved crude from the Gulf Coast up to Cushing. The joint owners of the pipeline, Enbridge and Enterprise reversed the pipeline last June to flow crude from Cushing to Freeport. Phase 1 of the project provided shipping capacity of 150 Mb/d. Phase 2 of the project expands the existing pipeline capacity by adding more pump capacity to increase the volume to 400 Mb/d. Phase 3 of the project is to build a parallel crude oil pipeline alongside the original that will more than double capacity to 850 Mb/d and come online in 2014. RBN Energy Blog contributor Industrial Information Resources explained the project engineering in a post last August (see Seaway Reversal Project).
The ‚ÄúSimple Theory‚ÄĚ of WTI Price Recovery
Market speculation about Seaway Phase 2 centers on whether or not the addition of another 250 Mb/d of crude oil capacity between Cushing and Houston will cause the price of West Texas Intermediate (WTI) crude at Cushing, OK ‚Äď the Midwest domestic market benchmark and the crude delivered against the NYMEX futures contract - to recover lost ground against the Brent ICE futures benchmark. As pretty much everyone involved in crude oil analysis knows by now, WTI has been trading at a discount to Brent over the past two years. That discount has been hovering around the $20/Bbl level for the past six months - even though the two crudes are of similar quality and WTI traded at a slight premium to Brent up until August 2010. It is generally accepted that the large WTI discount to Brent came about because of an oversupply of new crude production from Canada and US domestic shale plays such as the Bakken field in North Dakota into the Midwest market. The new production backed up supplies at the Cushing hub where WTI is traded, causing its price to fall relative to international crudes that are linked to Brent. Since that price dislocation occurred some have assumed that all it would take to end the WTI discount to Brent is for new pipeline infrastructure like Seaway to open up and let the Cushing crude glut flow out of the Midwest -where it is not needed - down to the Gulf Coast where there is plenty of refinery demand. At that point, theoretically WTI prices would resume parity with Brent, the clouds will part and the sun will shine on Oklahoma. For the sake of argument we are going to call that the ‚ÄúSimple Theory‚ÄĚ of WTI price recovery.
Unfortunately things are not working out the way the ‚ÄúSimple Theory‚ÄĚ would suggest. In fact looking at the data since the Seaway pipeline opened in June 2012 we can see two distinct periods of activity where prices and inventories basically did the opposite of what the ‚ÄúSimple Theory‚ÄĚ says should have happened. The chart below shows Cushing stocks and the WTI discount to Brent over the past year. The WTI discount to Brent is the blue line on the left axis and the Cushing crude stock position is the red line on the right axis. The first period to look at (green circle) is between June and November 2012 when Cushing crude stocks declined by about 4 MMBbl after Seaway Phase 1 opened. Instead of the WTI discount to Brent narrowing during that period as the ‚ÄúSimple Theory‚ÄĚ expected the discount widened from around $11/Bbl in June to as high as $25/Bbl in November. The second period to look at is between November 2012 and this week (orange circle). During that period Cushing stocks increased by 6 MMBbl to reach another new record level over 49 MMBbl and the WTI discount to Brent fell back from $25/Bbl to $18.25/Bbl. During both these periods the data behaved inversely to the ‚ÄúSimple Theory‚ÄĚ that says lower inventories narrow the WTI discount and higher inventories will increase the WTI discount.
In short the ‚ÄúSimple Theory‚ÄĚ is not sufficient to explain how and when WTI prices will recover against Brent. Instead the US crude oil market is going through a complex transition that involves more variables than just Cushing inventories and WTI/Brent prices. In the rest of this blog we list seven variables (the ‚ÄúGates of Hell‚ÄĚ in our title) and their influence on crude prices. Only by paying attention to these ‚Äúgates‚ÄĚ can we explain what is happening to crude price relationships.
Gate #1 ‚Äď Midwest Refinery Demand
Fluctuating refinery demand in the Midwest currently has more impact on Cushing inventory levels than crude flows from Cushing to Houston on the Seaway pipeline. During our last blog on the WTI discount to Brent (see Place Your Bets on Narrower WTI/Brent Spread) we referred to the 400 Mb/d BP Whiting refinery in Indiana that makes up 11 percent of Midwest refinery crude capacity. A significant expansion project at BP Whiting took 250 Mb/d of refining capacity out of the Midwest market in November 2012 that will not be returning until the middle of 2013. That disruption helps explain the rise in Cushing inventories since November 2012. It could be argued that the Seaway Phase 2 expansion evens out the 250 Mb/d that BP Whiting is no longer consuming. That would mean Seaway 2 has no impact on Cushing stocks before BP Whiting comes back on line in mid 2013. Expect refinery demand fluctuations to continue causing temporary blips in crude pricing.
Gate # 2 ‚Äď The Crude Stockpile at Cushing
Regardless of temporary refinery demand fluctuations in the Midwest the fundamentals suggest that the crude stockpile at Cushing (and oversupply in the Midwest) is going to be addressed by new pipelines ‚Äď probably by the end of 2013 when Seaway Phase 2 and the Keystone XL Gulf Coast Extension project (700 Mb/d by 3Q 2013) will together have added 0.9 MMb/d of new capacity between Cushing and Houston. Reducing the Cushing stockpile will reduce the downward pressure on WTI prices and narrow the discount to Brent but it is not the only factor and may well be overshadowed by other variables.
Gate # 3 ‚Äď New Flows of Crude into Houston from the Permian and Eagle Ford
New crude flows from the Permian will come via the Magellan Longhorn Reversal project that will flow 75 Mb/d in 1Q 2013 and another 150 Mb/d by the end of 2Q 2013 as well as the Sunoco Logistics (Energy Transfer Partners) additions to the West Texas Gulf pipeline that will add another 200 Mb/d of capacity from the Permian to Houston by mid 2013.
New pipelines out of the Eagle Ford basin in South Texas began delivering increasing volumes of crude to Houston refineries (Enterprise 350 Mb/d, Kinder Morgan 300 Mb/d) during the second half of 2012.
Because the majority of Permian crude production has been flowing to Cushing, OK up until now - adding to the supply glut there - the new flows of West Texas crude to Houston will relieve pressure on Cushing. [The new pipelines will also reduce the heavy price discount against WTI that Permian producers have recently had to endure because supplies exceeded takeaway capacity and backed up at Midland, TX (see After The Flood).]
The new flows of crude from the Eagle Ford and the Permian will initially be delivered into the Houston area and will not pass through Cushing on their way to market. The focus of trading and pricing for WTI will therefore likely gravitate away from its traditional hub in Cushing. Watch for a new crude trading market based in Houston.
Gate # 4 ‚Äď New Flows of Crude into Louisiana From North Dakota and the Eagle Ford
Significant new domestic crude supplies are now reaching refineries in the Louisiana Gulf Coast region. We explained recently how 150 Mb/d of Bakken crude arrives by rail from North Dakota at St. James, LA (see Back to The Delta). There is also a growing coastal trade moving Eagle Ford crude by barge from Corpus Christi, TX to St. James. The newly reversed Shell Houston to Houma (Ho-Ho) pipeline begins delivering up to 300 Mb/d of crude from the Houston area to Louisiana Gulf Coast refineries this month (January 2013). These new supplies of light sweet crude into the Louisiana Gulf Coast market are already backing out sweet crude imports (see Thrown for a LOOP Part 1). The current Gulf Coast benchmark light sweet crude ‚Äď Louisiana Light Sweet (LLS) is priced at a small discount to Brent because it competes with imported crudes that are linked to Brent. Once domestic supplies replace these imports then LLS prices are likely to switch to track domestic crudes linked to WTI rather than Brent.
Gate # 5 ‚Äď Crude Quality
We have previously discussed the fact that the new supplies of domestically produced crude primarily from North Dakota, the Permian Basin and the Eagle Ford are considerably lighter in composition than the crudes that US refiners have been consuming for years (see Turner Mason and the Goblet of Light and Heavy). In addition, new supplies of crude from Western Canada are a blend of very light and very heavy components that again are not typical of existing grades. Refineries on the Gulf Coast that are configured for heavy crudes can only adapt to run these new crudes by reducing their throughput considerably or undergoing expensive alterations.
If there is a flood of light sweet crudes such as Bakken coming to the Gulf Coast from the Midwest via Cushing on the Seaway and Keystone pipelines then there is a very real danger that the supply glut in Cushing will simply be transferred to the Gulf Coast along with the attendant risks of price discounts that have dogged WTI over the past two years. That is because Houston is already receiving light sweet crudes from the Permian, the Eagle Ford and St. James, LA market is being supplied with North Dakota Crude. Once these flows exceed the demand for light sweet crude on the Gulf Coast (currently about 500 Mb/d) then producers will have to discount their light crudes to levels attractive for refineries configured to run heavier crudes.
Gate #6 Does Seaway Ship Light or Heavy Crude?
It follows that an important influence on Variable # 5 will be whether the crudes flowing from Cushing to Houston on Seaway are mostly light sweet crudes such as North Dakota Bakken and WTI or mostly heavier Canadian crudes. Heavy Canadian crudes are more attractive to Gulf Coast refiners because there is greater refining capacity configured to handle them (although some Canadian light/heavy blend crudes are still not ideal for heavy crude refineries). Higher Seaway volumes of heavy Canadian crudes will therefore have less impact on WTI prices than higher volumes of light sweet crude because the latter will increase the risk of the light sweet glut scenario described in Variable # 5
Gate # 7 The Possibility of Crude Exports
Last but not least we should mention the possibility that the US government will allow some volumes of crude oil exports from the Gulf Coast. Currently crude oil cannot be exported without a special License from the Bureau of Commerce (see Fifty Shades Lighter) and these have only been granted for limited exports to Canada. If crude oil exports are allowed at the Gulf Coast then the light sweet crude glut scenario described in Variable # 5 will be avoided. Producers would simply export any light sweet crudes not needed in the Gulf Coast region to international markets. Refiners would continue to import the heavier crudes their refineries are configured to run. The crude export scenario seems politically unlikely but if it does happen it will have a dramatic impact on US crude prices because WTI and LLS will be linked back to international markets and track Brent prices directly.
Our seven ‚ÄúGates of Hell‚ÄĚ indicate just how complex the Gulf Coast crude supply situation is for crude traders and analysts to navigate today. The fate of the WTI discount to Brent is tied to many factors besides the level of crude stocks at Cushing. The WTI relationship with Brent will not resolve itself overnight through one or two new pipelines but rather by a gradual evolution over the next two years. Our belief (as explained in After the Flood - Gulf Coast Light Sweet Crude Pricing Beyond 2013) is that the WTI discount to Brent will decline over the next two years to arrive at a new level close to $10/Bbl. Along the way there will be plenty of hiccups caused by local demand fluctuations, crude quality issues and potentially a new supply surplus on the Gulf Coast. Stay tuned to RBN Energy for continued insight.
^^^ good article. Thanks for posting it.
Updated: Jan 08, 2013 8:31 PM CST
By Jen Kastner NewsWest 9
PERMIAN BASIN- The energy industry's buzz over Cline shale is getting louder. The formation has the potential to make a huge impact on the Permian Basin. It span from Midland to Big Spring and from Lubbock down to Big Lake.
Midland Geologist Gary Dawson has studied the Cline shale for years. "It's kind of the perfect shale. It's got all the ingredients that you need to have," he tells us. Dawson says the shale is jet black and brittle. It creates and retains vast quantities of oil and natural gas.
Cline shale was virtually insignificant until recent developments emerged in horizontal drilling and fracking, allowing for the shale to be tapped.
Midland Energy Industry Expert Morris Burns tells us, "This is a huge shale formation and only in the last 15 to 20 years have we been able to get oil and gas out of it. The Wolfberry shale has increased the permian basin's production by about 25 to 30 percent in the last few years.
The Cline shale has the potential to increase it by another 50 to 60 percent."
"Right now, we're just barely tapping the potential of the Cline shale," says Dawson. Experts say this shale will play a key role in America's quest to stray from foreign oil use. "This will help us become energy independent in the next 10 to 15 years," adds Burns.
Note: "oil Shale" and "Shale oil" are NOT the same. Oil Shale are rocks that are better described as wet oil soaked rocks or wet coal. Shale Oil would be better termed "tight oil" as the oil is between rocks and freed from Hydro drilling methods. The 3 states with the Oil Shale the article mentions are Colorado, Wyoming, and Utah. Everything I've read to date, is to get the "oil shale" out you have to mine the rocks much like Coal Mining, then put them through a Heating/Steaming unit which extracts the oil. The cost to do all of that is really high, and not very efficient yet.
An oil boom launched by ‚Äúfracking‚ÄĚ has led energy leaders to take a second look at harnessing the potential of oil shale, a fossil fuel that energy firms largely abandoned the hope of harnessing in the 1980s.
No commercially viable method of producing oil shale exists, but American Petroleum Institute CEO Jack Gerard turned heads earlier this month when he predicted a game-changing technological breakthrough could allow the use of oil shale.
Gerard‚Äôs remarks caught many by surprise as doubts abound on oil shale‚Äôs future.
‚ÄúTo date, what we‚Äôve seen is 100 years of promises and taxpayer funds for projects that have all gone belly up,‚ÄĚ said Ellynne Bannon, a spokeswoman with spending watchdog group Checks and Balances Project.
Environmentalists abhor the prospect of trying to harness oil shale, which would involve extracting oil that is contained in rocks. Extraction methods so far use a considerable amount of fossil fuels and water, which is scarce in the West.
Yet before fracking ‚ÄĒ which injects a high-pressure mixture of water, sand and chemicals into tight rock formations to capture oil hidden under the rocks ‚ÄĒmany had thought accessing the oil and gas buried deep underground was too expensive.
Now ‚ÄĒ largely because of fracking ‚ÄĒ the U.S. is now projected to overtake Saudi Arabia to become the number one oil producer in the world by 2020.
Fracking allowed drillers to tap more natural gas, helping drive U.S. prices from $13.19 per million British thermal units in June 2008 down to $3.14 per million Btu as of Wednesday, according to the U.S. Energy Information Administration. That has industry and lawmakers alike bullish on finding technological breakthroughs to develop other energy sources once thought too expensive to access.
The developments are likely to put further political pressure on President Obama to allow more fossil fuel access, particularly given the slow U.S. economy.
Gerard thinks oil shale could be the next bonanza.
‚ÄúOil shale alone in three western states is three times the proven reserves of what Saudi Arabia holds today. The key to it is to access the ability to develop it, to find the technologies to extract it for domestic consumption and even potential exports going down the road,‚ÄĚ Gerard said.
Tapping oil shale would mean heating rocks under intense pressure to separate the fuel contained within them. Energy firms have had some success in doing this in Estonia, but the practice is heavily subsidized.
A handful of firms are operating in the U.S. on research, development and design leases from the Interior Department. But many others have wound down or ended their U.S. oil shale activities.
The Obama administration‚Äôs approach so far has been to offer funds for research and development of oil shale, but not commercial leases, a policy praised by Bobby McEnaney, a senior lands analyst with the Natural Resources Defense Council.
‚ÄúThere is no sort of known way to get it out of the ground. So I think the administration is approaching this from a cautious perspective,‚ÄĚ McEnaney said.
But Rep. Doug Lamborn (R-Colo.) thinks the administration is going too slowly. He said he is likely to reintroduce legislation in this Congress that would call on the Interior Department to open up more land for oil shale development.
Lanborn‚Äôs PIONEERs Act would have Interior open 2 million acres for commercial oil shale development with a federal royalty rate of 5 percent.
It passed the House with 237 votes, 216 of which were Republicans, in the last Congress but did not receive a vote in the Senate.
Lamborn said the Obama administration has kept too much land off-limits to oil shale development. He said that has deterred investment, making it harder to strike a technological breakthrough.
‚ÄúThere‚Äôs tremendous potential there. It‚Äôs not yet in a commercially viable stage, but it is at least something that should be allowed to move forward in the research and development stage,‚ÄĚ Lamborn said.
Potential can be elusive, said McEnaney, who noted that many energy firms have backed out of oil shale development.
He said Chevron has largely abandoned its research, development and design lease, and noted that Shell is curtailing its activities.
Bannon said many Coloradans are suspicious of oil shale promises after Exxon left overnight in 1982 in what became known as ‚ÄúBlack Sunday.‚ÄĚ The company had entered Colorado hoping to harness oil shale, but failed, and took more than 2,000 jobs when it left.
‚ÄúI think there‚Äôs a lot of people who have lived through the boom and bust, and they‚Äôre naturally skeptical,‚ÄĚ Bannon said.
Still, McEnaney said the domestic energy boom might also have emboldened fossil fuel-friendly lawmakers to trumpet oil shale‚Äôs possibilities.
‚ÄúSo long as you have this what I would call mythical expectation that Colorado would be some Saudi Arabia of oil shale, this probably isn‚Äôt going away,‚ÄĚ McEnaney said.
Energy firms are taking a ‚Äúwait and see attitude before spending any big bucks to move the industry forward,‚ÄĚ Glenn Vawter, executive director of the National Oil Shale Association, told The Hill.
Read more: http://thehill.com/blogs/e2-wire/e2-...#ixzz2I3v81N4s
Producing shale oil has been a big game changer but if they can develop a method to economic produce large amounts of US oil shale it would be an even bigger game changer and by several times.
Well, I've heard this saying before, and I think it still applies: Oil Shale is the future fuel...and it ALWAYS WILL BE.
and I agree....it's like a mirage at the moment. But getting "tight oil" was a dream at one point as well
Dormant Mineral Acts.
So I was reading this article on Colorado's Unclaimed Minerals and how those can be handled. The article said that Colorado didn't have an "Dormant Mineral Act". I knew Montana did not, but North Dakota did. In fact I thought MOST states did have some form of the "Dormant Mineral Act"
Well, it turns out, several don't. This article written by a law firm but is NOT DATED...so it could be out of date says: No legislation concerning dormant minerals has been enacted by the legislature in Arizona, Colorado, Idaho, Montana, Nevada, New Mexico, Utah, Texas or Wyoming.
In a very interesting article that is hosted on an OU Law Site from and is from Altson Energy Land Services Presented to the National Association of Division Order Analysts Friday, October 15, 2010 Lists different ways that various states have for reuniting minerals. It mentions North Dakota's laws, as well as Montana's "adverse possession"
Any way....I thought these were a good learning experience for me. Thought it might be of interest for someone else.
^^^^I made a buuuuuuuuuuuunch ofr money in ND in 2007/2008 with the help of the dormant mineral act. Thanks for the info.
It looks like Goldman Sachs may be back to their old tricks of pump and dump‚Ä¶. beware
Today Jeff Currie, Goldman Sachs chief commodity strategist put forth some comments regarding the Oil market. Jeff Currie from Frankfurt said he wouldn‚Äôt be surprised ‚Äúif we woke up in summer and [Brent] oil cost $150 [per barrel]".
We've talked about this before, but here is a new article on the new pipelines coming on-line in the Mid-continent. From Seeking Alpha.
Release The Hounds: Landlocked Oil Starts To Escape To The Gulf Coast
On January 11, Enbridge (ENB) and Enterprise Products Partners (EPD) announced that they had completed the upgrade of their Seaway Pipeline joint venture. The pipeline, which connects the U.S. inland oil hub in Cushing to the Gulf Coast, began shipping crude south from Cushing last May at a rate of 150,000 bpd (barrels per day). Meanwhile, the owners have been working on upgrades to the pumping stations. After being closed for about a week at the beginning of this month, the Seaway pipeline reopened, with its capacity nearly tripled to 400,000 bpd.
The Cushing Oil Glut
This expansion will finally begin to relieve the glut of oil at Cushing, which has depressed WTI prices relative to Brent for more than a year. Moreover, as I have written elsewhere, it is likely to bring Brent prices (which heavily influence oil product prices in the coastal U.S.) below $100 by year-end. The WTI-Brent differential has already begun to close. In December, the WTI spot price was nearly $22 below the Brent spot price, on average. This differential had shrunk to $18.46 by January 15, and the gap for futures this spring is around $16.
It will be very interesting to see how this situation plays out over the next few weeks and months. A recent article published at ValueWalk (and elsewhere) claims, prematurely in my opinion, that the increase in flow rate will not "solve the Cushing oil glut". For the week ending on Jan. 11, Cushing oil inventories increased by 1.8 million barrels to 51.9 million barrels, a new record. This is nearly double the 28.3 million barrels of inventory at Cushing at this time last year. However, the Seaway pipeline was closed entirely for that week. With the line now taking 400,000 bpd (2.8 million barrels per week) out of Cushing, there should be enough capacity to negate the 1.8 million barrel weekly inventory increase and then draw down inventories by 1 million barrels per week. At that rate, Cushing inventories would return to "normal" levels by the middle of 2013.
However, that is not the end of the story. Oil flow rates vary on a weekly basis, and U.S. production has been rising rapidly over the past few years. Bakken oil production may increase by approximately 250,000 bpd over the course of 2013, to 1 million bpd, according to bullish forecasts. (That said, bears believe that production may already be near a peak.) If the expected Bakken production increases occur, they will account for much of the Seaway pipeline's excess capacity.
Additionally, since WTI has been trading at a severe discount to Brent, many Bakken oil producers have been sending crude by rail to the coasts recently. Oneok Partners (OKS) recently canceled the Bakken Crude Express pipeline project, which would have brought 200,000 bpd from the Bakken to Cushing by 2015. I believe that the main reason why the company had trouble securing commitments from producers is that the cost savings of transporting by pipeline rather than rail (likely $8-$12/barrel) is outweighed by the higher prices for oil on the coasts.
As the WTI price approaches the Brent price, more producers will opt to send oil by pipeline to Cushing, necessitating additional takeaway capacity. This need will be met in late 2013 and 2014 with the opening of TransCanada's (TRP) Keystone Gulf Coast Project (700,000 bpd) and the "twinning" of the Seaway line (450,000 bpd). TransCanada's Keystone project is primarily being built to serve Canadian oil production; after all, it is part of the larger transborder Keystone XL project. However, Enterprise and Enbridge are only going ahead with the "twinning" of the Seaway line because of strong demand from oil producers. Oil producers clearly believe that rapid production growth will continue for at least the next year or two.
Production increases, primarily in the Bakken area, will clearly account for much of the recent increase in capacity on the Seaway pipeline. However, the additional 250,000 bpd should be sufficient to halt the buildup of crude inventories at Cushing, which is significant in and of itself. As a result, I expect the WTI-Brent spot price spread to narrow to around $15 for the spring and summer. The opening of the Keystone Gulf project (expected later this year) should create some breathing room, causing the WTI-Brent spread to close to approximately the cost of shipping: $5-$10. This does not mean the ultimate end of shipping constraints. If and when the Keystone XL pipeline opens, the addition of large quantities of Canadian oil flowing to Cushing could reopen the spread. However, this is unlikely to occur until 2015 or later.
I continue to see opportunity in logistics companies like Enterprise, Enbridge, and TransCanada, as well as Sunoco Logistics Partners (SXL). These companies will all benefit from the reshaping of the U.S. oil transport infrastructure over the next several years. Another way to play this opportunity is to buy oil producers heavily invested in the Bakken region, such as Continental Resources (CLR). As infrastructure continues to catch up to growing Bakken production, these producers will receive better prices (closer to Brent), which could significantly improve margins.
Not a shocker...and I expect the approval to be fairly quickly with just the right amount of posturing by the administration to appease their environmental wing. Construction and right of way for most of this has been going on after it was put on hold last year.
Nebraska Gov. Dave Heineman notified President Obama on Tuesday that he has approved the controversial Keystone XL Pipeline to traverse his state, a crucial step toward reviving the project one year after it was delayed by the Obama administration.
The governor wrote in a letter to Obama and Secretary of State Hillary Clinton that he's approved a revised route for the Canada-to-Texas pipeline, which his office said would avoid the environmentally sensitive Sandhills region, but will cut through the High Plains Aquifer.
The move puts the onus back on the Obama administration ‚ÄĒ the project must be approved by the State Department to move forward ‚ÄĒ to decide the fate of the 1,700-mile pipeline that has pitted GOP lawmakers against environmentalists.
Heineman says the Nebraska segment of the project would result in a $418 million positive impact on the state's economy.
Very good report for CLR
OKLAHOMA CITY, Jan. 23, 2013 /PRNewswire/ -- Continental Resources, Inc. (CLR) increased its year-end 2012 proved reserves to 785 MMBoe (million barrels of oil equivalent), a year-over-year gain of 54 percent. With the 2012 increase, Continental has grown proved reserves at a compound annual growth rate of 45 percent since year-end 2009.
Continental's 2012 proved reserves had a net present value discounted at 10 percent (PV-10) of $13.3 billion, a 45 percent increase over the PV-10 of $9.2 billion for proved reserves at year-end 2011.
Proved reserves growth in 2012 primarily reflected strong production growth in the Bakken play of North Dakota and Montana, which Continental believes is the nation's premier oil play. Continental is the largest producer and leaseholder in the Bakken, with approximately 1.1 million net acres. The Company has also accelerated production growth in its South Central Oklahoma Oil Province (SCOOP), an oil- and liquids-rich play in Oklahoma.
Thirty-nine percent of Continental's total 2012 proved reserves, or 309.0 MMBoe, were proved developed producing (PDP), compared with 40 percent of year-end 2011 proved reserves.
Crude oil reserves represented 72 percent of 2012 total proved reserves, a significant increase over year-end 2011, when crude oil accounted for 64 percent of the Company's 508 MMBoe in proved reserves. The higher percentage of crude oil proved reserves in 2012 was accomplished despite two crude-oil concentrated divestitures.
Continental currently operates 85 percent of its total proved reserves, compared with 86 percent at year-end 2011.
"We continue to increase our concentration in high-value, high-growth, crude oil assets, especially in the Bakken," said Harold Hamm, Chairman and Chief Executive Officer. "We are growing the value of our Bakken assets through strategic acquisitions, exploration, and the expanded use of pad drilling, which should improve efficiencies and translate into even better rates of return."
Through acquisitions and leasing, Continental increased its Bakken leasehold by 24 percent in the past year, from 915,863 net acres at year-end 2011 to 1,139,799 net acres at year-end 2012.
The Company is also leveraging the increased demand for high-quality Bakken crude oil at U.S. refineries. "We have more than adequate pipe and rail capacity out of the basin at this time, so we can move our production to the most advantageous markets," Mr. Hamm said. "Realizing the Bakken's full potential is essential to our five-year plan to triple production and proved reserves by year-end 2017, while increasing operating margins."
Strong Production Growth
Continental's 2012 production totaled 35.7 MMBoe, a 58 percent increase over production of 22.6 MMBoe for 2011, in line with the Company's production growth guidance for 2012.
Estimated fourth quarter 2012 production was 9.8 MMBoe, or 106,831 Boe per day, a 42 percent increase over fourth quarter production for 2011. The Company deferred some fourth quarter well completions to stay within its capital expenditure budget for 2012. Fourth quarter 2012 was the 19th consecutive quarter in which Continental has increased production compared with the immediately previous quarter.
Based on continued production growth, as well as an acquisition and a divestiture announced December 20, 2012, Continental's current production is approximately 116,000 Boepd.
Increased Proved Reserves
Continental's 2012 proved reserves in the Bakken totaled 564 MMBoe, almost double proved reserves in the play at year-end 2011. The Company's Bakken proved reserves had a PV-10 of $9.9 billion at year-end 2012.
Other significant components of year-end 2012 proved reserves included the SCOOP play in Oklahoma, with proved reserves of 63 MMBoe (PV-10 of $955 million) and the Red River Units, where proved reserves increased in the past year to 78 MMBoe (PV-10 of $2.0 billion).
Exploration and development activity was the primary driver in the Company's 2012 proved reserves growth, adding 234 MMBoe of proved reserves in the year, of which 27 percent were PDP and the remainder PUDs (proved undeveloped reserves). In total, a reconciliation of 2012 proved reserves included:
Last edited by OrangeBlossom; April 11th, 2013 at 09:14 AM.
I'm pretty excited about SCOOP. Looking forward to more well results there.....
I've started on-line stalking of CLR's Corp Commission activity. It may be getting time to bust into some forced poolings and get a position. All you need is cash. Cash is all you need.......
CLR down another buck plus this morning. The market can be such a hazy mystery.....
I heard about this yesterday. It might have something to do with the CLR drop
Enterprise Products Partners LP (EPD) told shippers today that capacity was limited on its expanded Seaway Pipeline, widening the spread between domestic benchmark West Texas Intermediate crude and Brent.
The WTI-Brent differential widened by $1.83 a barrel to $17.57 based on today‚Äôs settlements. Enterprise said the limited capacity was due to ‚Äúunforeseen constraints in outbound takeaway‚ÄĚ at the Jones Creek terminal.
‚ÄúNow the question is how long it‚Äôs going to take before the takeaway capacity gets cleared up,‚ÄĚ said Stephen Schork, the president of Schork Group Inc. in Villanova, Pennsylvania, by phone.
The spread, which reached $26 in intraday trading Nov. 15, narrowed to less than $16 last week.
The 30-inch (76-centimeter) line, which runs from Cushing, Oklahoma, to Freeport, Texas, reopened on Jan. 11 with capacity expanded to 400,000 barrels a day. On Jan. 16, the flow had increased to 301,000 barrels a day, according to Hillary Stevenson, a Louisville, Kentucky-based data integrity analyst for Genscape Inc., which monitors pumping stations.
Inventories at Cushing, the delivery point for futures traded on the New York Mercantile Exchange, reached a record 51.9 million barrels on Jan. 11, according to the Energy Information Administration, the statistical arm of the Energy Department. Stockpiles there were expected to fall with the opening of Seaway.
‚ÄúWhat you‚Äôre seeing now is, here we go again, the template is set for the glut up in Cushing to blow out again,‚ÄĚ Schork said.
^^^ yeah, that probably is in play here.
What incentivizes a company to invest in transmission over storage?
At the end of the day the incentive is always profit‚Ä¶..
Most significant sized NG transmission companies have storage.
NG storage gives the transmission company the ability to reliably meet high demand periods.
With enough storage hedging and selling on the spot market at premium prices could be options.
But new cheap storage options near high demand areas are often very hard to come by.
My only criticism of being profit driven is the potential future losses of all of the stuff we vent off. Do you think this has more to do with keeping prices up for overall company stability or just a lack of foresight when planning a well?
I found this pretty interesting. I'm not on this end of the business, but have to explain it everyday.
Many producers are not in the transmission business and don‚Äôt have the capitol necessary to build billion dollar pipeline projects and since crude oil is more profitable it has the priority for capital expenditures.
With the current glut of cheap natural gas on the market it‚Äôs probably not the best use of capital resources to quickly bring large amounts of still very cheap NG to market. Again crude is more profitable.
In the Bakken it was sometime before the majors with the deep pocket realized its natural gas potential. They are slowly bringing more NG on line in the Bakken.
I like the idea of more GTL. I have heard somebody is building small scale skid mounted GTL units that can be installed on a well pad. In Alaska they inject NG back into the formation to stimulate crude production.
Again, thanks for your insight. I know my posts can come across as contentious, but they are primarily aimed at rousing discussion so that I (and hopefully others) can learn more.
With the family of my better half being heavily involved in the ROW business, I am always appreciative of insight into other parts of the sector.
Yeah, nobody is out in the field any more, but there are some stories about Lamesa Tx circa late eighties that make me glad everyone is now on the administrative side of it.
I worked on a pipeline ROW in, of all places, Georgia and South Carolina. This was in 1999 when oil & gas was really dead. I ran into some real doozies.
Not too thrilled to read Kodiak on this list.....but I think costs are going to continue to drop for Bakken operations and thus earnings SHOULD improve this year........guess I need to keep a closer eye on that.
The 3 Stooges of the Oil and Gas Industry
Very often they will have an article one day pumping up a stock in a major way and then the next day in another article they say to dump the same stock and talk nothing but gloom and doom.
So anyone here an AAPL member with a CPL or an RPL? I want to apply for my RL, and I have to have one sponser. However, everyone I've worked with doesn't have an RPL. (I've also got a few "why join them? they suck. It's a waste of money") I've had a few RL's which is how I got in the AAPL in the first place.
Yeah I'm desperate, if I'm posting it on a message board.
One thing to watch will be the continued adoption of NG-fired power plants. As more and more of these come online (especially along the Eastern seaboard), demand for NG storage should be driven down somewhat.
I would advise joining however. The $100.00 annual membership fee is worth it just for the landman's directory. And there are a lot of good continuing ed courses that can be real helpful to the less experienced landman.
I have work around some that dated back to the late 1920‚Äôs and is still used.
I look for more LNG storage to be installed near high usage areas.
The western slope has been pretty quiet with the slow down in gas prices and gas exploration along with that. This is interesting, but I think it's actually old news. This is of a well drilled in 2011, and just now putting out the results.
While the oil-rich Niobrara shale in eastern Colorado has grabbed headlines, WPX Energy says it has been exploring the formation in the western part of the state and found new shale gas reserves.
After drilling two horizontal wells in the San Juan Basin in 2010 and finding an estimated 1.3 trillion cubic feet of proved, probable and possible reserves, WPX headed north the Piceance Basin.
‚ÄúWe had the right equipment, the right location so we moved to the Piceance,‚ÄĚ said company spokeswoman Susan Alvillar.
WPX drilled a well to 10,300 feet, with a 4,600-foot horizontal bore through the shale in Garfield County and hit a potentially natural gas reserve.
The well produced 12 million cubic feet of gas per day for the first 30 days and more than doubled the WXP‚Äôs 18 trillion cubic feet equivalent reserves estimate, the company said.
The Niobrara formation is deep ‚Äď 10,000 to 13,000 feet ‚Äď compared with the traditional drilling into the Piceance‚Äôs Williams Fork formation which is 6,000 to 9,000 below the surface.
The shale formations also require drilling long, horizontal wells to through the shale to gather the more diffuse resource. The depth and technique puts the cost of each of these wells in the range of $3 million to $5 million ‚Äď more than triple the cost of a standard well.
In the eastern Colorado, centered on Weld County, the Niobrara has yielded oil and as a result a lot of activity and big investments.
Andadarko Petroleum Corp. based in The Woodlands, Texas, estimates that it has found a 1.5 billion barrel oil equivalent reserve and is projecting a $1 billion a year investment over the next few years.
Houston-based Noble Energy said it has found a 2.1 billion barrel oil equivalent reserve and plans to spend $8 billion in the fields over the next by 2017.
Meanwhile back in the gas-rich Piceance things have been quieter. The price of natural gas has not been above $4 a million British Thermal Units since September 2011. The low prices ‚Äď the 10-year average has been $5.89 a million BTUs ‚Äď are depressing drilling activity in the region.
Still, Tulsa-based WPX, which was spun-off by Williams Companies Inc. as an independent oil and gas exploration company, is pushing on with its Niobrara wells.
‚ÄúWe are an exploration company and we are committed to the Piceance,‚ÄĚ said Alvillar. ‚ÄúWe have the infrastructure to get the gas and be the low cost producer.‚ÄĚ
WPX said it hopes to drill at least two more horizontal Niobrara wells in the Piceance this year.
‚ÄúWe want to be in a position to produce when the time comes,‚ÄĚ Alvillar said.
^^^^ good info.
I just found this on Seeking Alpha (this is the type info I like from them...). And holy moly, that sounds like a hell of well........full article linked below.
How Big Is The Eaglebine Oil Play?
January 25, 2013
Perhaps not as big as the Eagle Ford or Bakken. And certainly less tested with horizontal drilling than many other established shales. But even at its current early stage of evaluation, this new "hot" horizontal oil play already is real enough and has the promise of becoming impactful enough to warrant a closer look by investors.
The following is an excerpt from the October 31, 2012 press release by Crimson Exploration (CXPO), a small E&P independent involved in the play:
In Grimes County, TX, the Covington-Upchurch #1H well (67.8% WI), targeting the Woodbine formation, has been drilled to a total measured depth of 15,228 feet, including a 5,190 foot lateral. In preparation for completion operations, Crimson perforated only the toe stage of the lateral section which, during a 24-hr period, produced naturally (i.e. without fracture stimulation) at a rate of approximately 6.9 MMcfe/d, or 179 barrels of condensate, 205 barrels of natural gas liquids and 4.6 MMcf of natural gas. The well has yet to be fracture stimulated and the above rate represents production from only one of the fifteen (14 + toe) planned perforation stages. The production rate for the well is anticipated to improve upon conducting fracture stimulation operations along the entire lateral; however, it is not possible to estimate at this time what total production rate will be achieved from the full lateral section.
Not that this makes any real difference but several weeks ago I was checking out Crimson Exploration.
I discovered that its CEO was an Alabama graduate.
I never really thought that an Alabama graduate would own an exploration company.