the two projects plans will have close completion timings. SXL in "early (not sure what early means)" 2016 and KMP/MWE JV in "second" quarter 2016
in addition to Seneca 1 and Majorsville 5 already announced for 4th quarter
I recollect mwe also benefits from mariner east by it committed shipper percentage, so both KMP/MWE JV and Mariner east are winners for MWE
Msg 12507 of 12509 at 12/6/2013 10:15:34 AM from oldtimers iv board by
The following message was updated on 12/6/2013 10:16:18 AM.
In response to msg 12506 by tonoos view thread
Re: Ladenburg Thalmann - Analyst Day highlights report
" I missed much of the pres., heard something about a new partner..." - tonoos
It's not another partner.
With Cardinal now underway on the supply chain side, Navidea has decided they may be able to enhance the speed of penetration by contacting the surgical oncologists directly. Cardinal doesn't call on individual surgeons.
So Navidea plans to explore co-promotion opportunities with companies with existing sales teams that already call on surgeons. That way Lymphoseek can get pushed from both the supply side and the end-user side simultaneously.
It's discussed during the presentation around timeframe 28:00 - 31:00...
Nachrichtenquelle: Business Wire (engl.)
| 05.12.2013, 16:15
"...Enterprise Products Partners L.P. (NYSE: EPD) today announced that the process of injecting ethane into the Appalachia-to-Texas Express (“ATEX”) pipeline began in late November and will continue throughout December 2013. Commercial service is expected to begin in January 2014...."
DUG East observation. One thing that analysts and companies agreed on at the at Hart Energy’s 2013 DUG East conference was that the industry has never seen a shale play where so much success has been found so early.
Baker Hughes Rigs count for the November 15 reporting week.
PA Marcellus 55 – up 1
PA Utica 2 – unchanged
Ohio Utica 34 rigs – unchanged
WV Marcellus 32 rigs – up 1
"..Shell information looks promising. Shell Oil Co. is still actively exploring a plan to build a huge natural gas processing plant in western Pennsylvania, and may have selected engineering firms to do feasibility studies...
...But Shell has cautioned that a final decision on whether to build the multibillion dollar plant wouldn't be made for several years. While some recent media reports suggested that the project might be canceled, The Associated Press found that Shell still has scores of people working on the assessment.
Shell has an option to buy the industrial site in Monaca that's now owned by Horsehead Corp. In an early November conference call, Horsehead CEO Jim Hensler said Shell continues to be "extremely active" at the site, with "about 70 people crawling all over" it recently.
Shell spokeswoman Kimberly Wendon told the AP in an email that "our evaluation of the site continues" and that the process "typically takes several years to complete." Wendon added that the company expects a similar time frame in Monaca.
There also are other signs Shell is seriously considering the project.
Gulfport Energy Corp. said in early November that it signed a contract to provide Shell with raw natural gas for the project, if it gets built. And last month Chemical Week, an industry publication, reported that Shell has chosen two multinational engineering firms to do feasibility and pre-project planning. Executive Vice President Graham Van Hoff told the publication that Bechtel Corp. and Linde AG of Germany would do the preliminary work.
Energy experts say it's simply too early to tell whether Shell will or won't build the plant, since the final decision involves worldwide market conditions and competing projects, both within the company and by competitors. Shell CFO Simon Henry suggested in a late October conference that the company will have to choose among several large new investments over the next year or two."
from shale directories facts an rumors
first it depends the propensity of their processing type agreements (fee, pop, keep whole) and secondly is narrowing of ngl (thru ngl price improvement) to oil spread if pop and overall prices if keep whole
Intarz, do not know if it gives answer for sure, but does narrows the field considerably per prior messaging discussion. Here is quote that does not make it for sure ye,t because they have similar situation to overcome in Marcellus even though several producers have committed to them
"A major difference between the projects was that Shell produces and owns all of the natural gas it uses at the Pearl facility, but would have had to buy natural gas from the U.S. grid in order to supply the Gulf Coast project."
Posted on December 5, 2013 at 12:28 pm by Zain Shauk
HOUSTON — Royal Dutch Shell said Thursday it is abandoning plans for a massive gas-to-liquids project envisioned for Louisiana, citing poor economics for the project that was expected to cost more than $20 billion.
The plant would have turned natural gas into diesel, jet fuel and other liquids, but the company determined that it would be too costly.
“Despite the ample supplies of natural gas in the area, the company has taken the decision that GTL is not a viable option for Shell in North America, at this time, due to the likely development cost of such a project, uncertainties on long-term oil and gas prices and differentials, and Shell’s strict capital discipline,” the company said in a statement.
Shell announced the potential site for the project in September, but said it was no sure thing as the company was continuing to evaluate its economics.
“We are making tough choices here, focusing our efforts and capital on the most attractive opportunities in our worldwide portfolio, to add value for shareholders,” Shell CEO Peter Voser said in a statement.
Gulf Coast: Nation’s largest methanol plant planned for Texas
A prior Shell gas-to-liquids project in Qatar, the Pearl GTL project, cost about $19 billion and offered more value than the conceived Louisiana project, according to the company.
A major difference between the projects was that Shell produces and owns all of the natural gas it uses at the Pearl facility, but would have had to buy natural gas from the U.S. grid in order to supply the Gulf Coast project.
Shell’s decision came down to that and other costs, with the projected construction tab expected to be too high, and the margin the company hoped to earn on the natural gas it processed projected to be too low, spokeswoman Kimberly Weldon said.
Shell made its decision to abandon the project despite a $112 million incentive offered to the company by the state of Louisiana.
Wells are probably not that costly so 222 bopd is probably a fair return "The well was drilled to a lateral length of approximately 1,200 feet and was fracture stimulated with nine stages using our “Super Frac” completion design." Next well is 1500 feet
chrx new grass in ROW should make for a quick hunt, just sit in the scrub oak, etc and pick your target. onto sxl. what the statement said to me was what ake pointed out. sxl is in competition with KMP/MWE line and does not quite know for sure where the major inlet(s) will be (sounds like multipleinlets as they used a wide range of shipping distances also)
"...pipeline that will transport natural gas liquids from processing facilities built in the liquid-rich Marcellus and Utica Shale areas in Western Pennsylvania, West Virginia and Eastern Ohio to Sunoco Logistics’ Marcus Hook Industrial Complex on the Delaware River, approximately 300 to 400 miles from the production region..."
ake did you also note on of my other posts on the possibility of the Tuscarawas plant to possibility being tied into KMP Cochin line reversal to ship condensate to Canada
will still be needed in Eastern US and other parts of US for power generation for a least next 20 years-sees article on investorvillage bry message board
In addition to major Dec 8-10 winter storm forecast across much of U.S.--
"There could (keyword is COULD!) be an atmospheric pattern evolving that may be setting up for some severe cold weather and potentially significant winter storms for the latter half of December....This doesn't mean it will 100% verify, but the LRC is one factor I place high confidence in, and the MJO willing to transfer this potential anticyclonic Rossby Wave train into the Gulf of Alaska would mean that the cold wouldn't just be "cold"- it would be potentially brutal. In addition to the LRC seeing cold around the mid-late December timeframe, it also points out the presence of stormy conditions in the Plains, Midwest and Ohio Valley during this timeframe, adding credibility to the MJO Phase 5 and 6 precipitation composite.
In case you didn't get any of that, here's the summary.
-The Madden-Julian Oscillation is predicted to move into favorable phases for pushing a large, repetitive anticyclone east towards the US.
-The weather pattern then favors potentially brutal cold in the nation for the mid-late December period.
-Stormy conditions in the Midwest, Plains, Great Lakes, Ohio Valley, and Northeast are then possible.
The usual long range forecasting caveats apply in this case, including the chance that this may not happen at all. My confidence is decent that this should happen at least to some extent, but there's always something that could go wrong, thus the caveats of long range forecasting...."
full posting on iv mlp and bry boards
Sunoco Logistics announces binding Open Season for its Mariner East 2 project (SXL) 68.65 : Co announced that it will commence a binding Open Season for its Mariner East 2 project. This Open Season is for a pipeline that will transport natural gas liquids from processing facilities built in the liquid-rich Marcellus and Utica Shale areas in Western Pennsylvania, West Virginia and Eastern Ohio to Sunoco Logistics' Marcus Hook Industrial Complex on the Delaware River, approximately 300 to 400 miles from the production region. The Mariner East 2 pipeline is expected to be operational in early 2016.
some repeat of post 6 "...Many oil and gas operators and energy analysts suggest that it is only a matter of time before "the code is cracked" and the Monterey produces at rates comparable to the Bakken and Eagle Ford. Owing to the fundamental geological differences between the Monterey and other tight oil plays, and in light of actual Monterey oil production data, this is likely wishful thinking.
For all of these reasons, this analysis suggests that California should consider its economic and energy future in the absence of an oil production boom from the Monterey shale."
article and web references were posted by coolreit on investorvillage bry board
Why These Findings are Important
The March 2013 study from the University of Southern California suggested that the development of the Monterey shale could—by 2020—increase California’s Gross Domestic Product (GDP) by 14 percent, provide an additional 2.8 million jobs (a 10% increase), and provide $24.6 billion per year in additional tax revenue (also a 10% increase). This study was based on estimates that development of the Monterey shale could increase total California oil production as much as seven-fold. Given the unrealistic nature of the original EIA/INTEK Monterey shale estimates, such production growth estimates are unfounded. Moreover, an examination of USC’s oil production estimates reveals that they include unrealistic assumptions about the total production growth possible from the Monterey and the number of wells that would be required to increase production to the levels forecast. Hence the economic projections of the USC study must be viewed as extremely suspect.
Environmental concerns with development of the Monterey shale are centered around hydraulic fracturing (fracking), the main completion technique used in other tight oil plays. Acidization completions, using hydrofluoric and hydrochloric acid, are also of concern. It is certain that hydraulic fracturing and acidization completions have already been used on the Monterey shale, yet an analysis of production data reveals little discernible effect of these techniques in terms of increased well productivity. Many oil and gas operators and energy analysts suggest that it is only a matter of time before "the code is cracked" and the Monterey produces at rates comparable to the Bakken and Eagle Ford. Owing to the fundamental geological differences between the Monterey and other tight oil plays, and in light of actual Monterey oil production data, this is likely wishful thinking...
"...The EIA/INTEK report assumed that 28,032 tight oil wells could be drilled over 1,752 square miles (16 wells per square mile) and that each well would recover 550,000 barrels of oil. The data suggest, however, that these assumptions are extremely optimistic for the following reasons:
Initial productivity per well from existing Monterey wells is on average only a half to a quarter of the assumptions in the EIA/INTEK report. Cumulative recovery of oil per well from existing Monterey wells is likely to average a third or less of that assumed by the EIA/INTEK report.
Existing Monterey shale fields are restricted to relatively small geographic areas. The widespread regions of mature Monterey shale source rock amenable to high tight oil production from dense drilling assumed by the EIA/INTEK report (16 wells per square mile) likely do not exist.
Thus the EIA/INTEK estimate of 15.4 billion barrels of recoverable oil from the Monterey shale is likely to be highly overstated. Certainly some additional oil will be recovered from the Monterey shale, but this is likely to be only modest incremental production—even using modern production techniques such as high volume hydraulic fracturing and acidization. This may help to temporarily offset California’s long-standing oil production decline, but it is not likely to create a statewide economic boom..."
The target strata in the Bakken and the Eagle Ford plays are less than a few hundred feet in thickness and are flat-lying to gently dipping. The shale deposits of the Monterey are much thicker and much more complex, with target strata up to 2,000 or more feet in thickness, and at depths that can range from surface outcrops to more than 18,000 feet within a span of forty miles or less.
The Bakken play is spread over a potentially productive area of as much as 20,000 square miles, and the Eagle Ford play covers roughly 8,000 square miles. The Monterey tight oil play encompasses less than 2,000 square miles.
The Bakken and Eagle Ford shales are approximately 360 and 90 million years old, respectively, and were deposited on a relatively stable platform; as a result they are thin and widespread, and hence are relatively predictable. The Monterey is 6-16 million years old and was deposited rapidly in an active tectonic regime; as a result it is thick, of limited areal extent, and structurally complex, and hence is much less predictable.
An analysis of oil production data from the Monterey Formation reveals the following:
While tight oil plays generally produce directly from widely dispersed source rocks or immediately adjacent reservoirs—as is the case in the Bakken and the Eagle Ford—this is not the case in the Monterey Formation, where most production has come from localized conventional reservoirs filled with oil that has migrated from source rock.
1,363 wells have been drilled in shale reservoirs of the Monterey Formation. Oil production from these wells peaked in 2002, and as of February 2013 only 557 wells were still in production. Most of these wells appear to be recovering migrated oil, not "tight oil" from or near source rock as is the case in the Bakken and Eagle Ford plays.