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Build A Sick Air Jordan Collection Overnight By Buying All Eleven Collezione Packs by Patrick Johnson 9 Comments
they'll never release em to the public so i dnt care about about em
October 27, 2012 BY John Kim / 6
The duo of Air Jordan IIIs made for Oregon got a ton of blessings from the sneaker community last year, but why not give the Air Jordan IX some love? The two Oregon PEs made for the University of Oregon and neighborhood rival Oregon State were major surprises last year as well, and with the IX being such a trendy hit right now with the Kilroy Pack and Olive/Cool Grey re-issues, it's about time we revisit these rare PEs. Have we ever seen these side-by-side? Check out the gallery below and if you want to throw in some offers for both pairs, check out the listing from chris_pi on eBay.
Filed under: Air Jordans eBay PE
Tags: Air Jordan IX Air Jordan IX 'Oregon State' Air Jordan IX 'Oregon'
they'll never release em to the public so i dnt care about about em
man this whole time i thought that light cream pair was the Tinker colorway , i remember the AJI Alpha's & AJ2010 being in that color called the Tinker's...I'm i wrong???
Not feeling any of these nines to plain but the 3,4,and 5 Oregon ones r must copps for me
im prayin that they come out with an oregon pack in the next 5 yers with either these 9s or the 3s n 4s come on jb
Diggin both over that "Kilroy" set BS..
@dsuaveallday Beat me to it, would rather have these release instead of the persona pack
OHSU's Finest: Ranking the Doernbecher Jordans by Patrick Johnson 53 Comments
27 Air Jordans Take On A "Chicago" Colorway by John Kim 58 Comments
True Blue: A Look Back at Blue Air Jordans by Brendan Dunne 37 Comments


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Greenville, South Carolina
For population 25 years and over in Greenville:
For population 15 years and over in Greenville city:
3,894 residents are foreign born (1.3% Europe, 0.9% Asia).
Median real estate property taxes paid for housing units with mortgages in 2012: $1,369 (0.6%)
Nearest city with pop. 200,000+: Charlotte, NC (91.6 miles , pop. 540,828).
Nearest city with pop. 1,000,000+: Philadelphia, PA (533.8 miles , pop. 1,517,550).
Nearest cities: Judson, SC (1.6 miles ), Dunean, SC (1.6 miles ), City View, SC (1.6 miles ), Parker, SC (1.8 miles ), Glendale, SC (1.8 miles ), Sans Souci, SC (1.9 miles ), Welcome, SC (2.0 miles ), Wade Hampton, SC (2.0 miles ).
Single-family new house construction building permits:
Number of permits per 10,000 residents
Average cost (in $1000s)
Latitude: 34.84 N, Longitude: 82.39 WNickname or alias (official or unofficial): Textile Capital of the World
Daytime population change due to commuting: +60,725 (+102.5%)
Area code: 864
Property values in Greenville, SC
City-data.com crime rate counts serious crimes more heavily. It adjusts for the number of visitors and daily workers commuting into cities.
(click on a table row to update graph)
Crime rate in Greenville detailed stats: murders, rapes, robberies, assaults, burglaries, thefts, arson
Full-time law enforcement employees in 2012, including police officers: 223 (181 officers).
Greenville tourist attractions:
Greenville, South Carolina accommodation, waste management, arts - Economy and Business DataUnemployment in July 2013:
Unemployment by year (%)
Historical population
Historical housing units
Population change in the 1990s: -2,785 (-4.7%).
Work and jobs in Greenville: detailed stats about occupations, industries, unemployment, workers, commute
Average climate in Greenville, South Carolina
Based on data reported by over 4,000 weather stations
Tornado activity:
Greenville-area historical tornado activity is slightly above South Carolina state average. It is 59% greater than the overall U.S. average.
On 5/27/1973, a category F3 (max. wind speeds 158-206 mph) tornado 5.7 miles away from the Greenville city center injured 40 people and caused between $500,000 and $5,000,000 in damages.
On 5/5/1989, a category F4 (max. wind speeds 207-260 mph) tornado 30.5 miles away from the city center killed 2 people and injured 35 people and caused between $500,000 and $5,000,000 in damages.
Earthquake activity:Greenville-area historical earthquake activity is near South Carolina state average. It is 86% smaller than the overall U.S. average.
On 8/2/1974 at 08:52:09, a magnitude 4.9 (4.3 MB, 4.9 LG, Class: Light, Intensity: IV - V) earthquake occurred 67.5 miles away from the city center
On 8/25/2005 at 03:09:42, a magnitude 3.6 (3.6 MW, Depth: 5.0 mi, Class: Light, Intensity: II - III) earthquake occurred 75.4 miles away from Greenville center
On 3/18/2003 at 06:04:24, a magnitude 3.5 (3.5 LG, Depth: 3.1 mi) earthquake occurred 84.9 miles away from the city center
On 12/7/2007 at 11:07:03, a magnitude 3.1 (3.1 LG, Depth: 3.1 mi) earthquake occurred 30.6 miles away from the city center
On 1/3/1992 at 04:21:22, a magnitude 3.2 (3.2 MD, Depth: 3.1 mi) earthquake occurred 62.3 miles away from Greenville center
On 6/16/2006 at 00:57:27, a magnitude 3.1 (3.1 LG, Depth: 2.9 mi) earthquake occurred 66.5 miles away from the city center
Magnitude types: regional Lg-wave magnitude (LG), body-wave magnitude (MB), duration magnitude (MD), moment magnitude (MW)
Natural disasters:The number of natural disasters in Greenville County (5) is smaller than the US average (12).
Major Disasters (Presidential) Declared: 3
Emergencies Declared: 2
Causes of natural disasters: Ice Storms: 2, Drought: 1, Hurricane: 1, Tropical Storm: 1 (Note: Some incidents may be assigned to more than one category).
Birthplace of: Jesse Jackson - Civil rights activist, Kevin Garnett - Basketball forward, Jim DeMint - Politician, Terry Taylor - Professional wrestler, John Michael McConnell - Admiral, Jesse Jackson, Jr. - Congressman, Charles Hard Townes - Physicist, Dorothy Allison - Poet, Mike Hunter (boxer) - Boxer, Michael E. Thornton - Navy Medal of Honor recipient.
Medal of Honor Recipients born in Greenville: Michael Edwin Thornton, Robert Allen Owens, Robert S. Kennemore.
Main business address for: SAFETY COMPONENTS INTERNATIONAL INC (MOTOR VEHICLE PARTS & ACCESSORIES), CONSOLIDATED CAPITAL INSTITUTIONAL PROPERTIES (REAL ESTATE), SCANSOURCE INC (WHOLESALE-COMPUTER & PERIPHERAL EQUIPMENT & SOFTWARE), SPAN AMERICA MEDICAL SYSTEMS INC (ORTHOPEDIC, PROSTHETIC & SURGICAL APPLIANCES & SUPPLIES), GREENVILLE FIRST BANCSHARES INC (NATIONAL COMMERCIAL BANKS), SOUTH FINANCIAL GROUP INC (STATE COMMERCIAL BANKS), DATASTREAM SYSTEMS INC (SERVICES-PREPACKAGED SOFTWARE), JPS INDUSTRIES INC (BROADWOVEN FABRIC MILLS, COTTON) and 7 other public companies.
Hospitals/medical centers in Greenville:
Political contributions by individuals in Greenville, SC
Airports and heliports located in Greenville:
See details about airports and heliports located in Greenville, SC
Amtrak station:GREENVILLE (1120 W. WASHINGTON ST.) . Services: ticket office, fully wheelchair accessible, enclosed waiting area, public restrooms, public payphones, vending machines, free short-term parking, free long-term parking, call for taxi service.
Local government website: www.greatergreenville.com/city_government/index.htm
Colleges/Universities in Greenville:
Other colleges/universities with over 2000 students near Greenville:
Public high schools in Greenville:
Private high schools in Greenville:
Public elementary/middle schools in Greenville:
See full list of schools located in Greenville
Biggest private elementary/middle schools in Greenville:
Library in Greenville:
User submitted facts and corrections:
(lower is better)
Air Quality Index (AQI)
Sulfur Dioxide (SO2) [ppb] level in 2010 was 0.598. This is significantly better than average. There were 26 monitors within city limits.
Ozone [ppb] level in 2010 was 28.6. This is about average. There were 10 monitors within city limits.
Particulate Matter (PM10) [µ/m3] level in 2009 was 16.6. This is significantly better than average. There were 27 monitors within city limits.
Particulate Matter (PM2.5) [µ/m3] level in 2010 was 10.4. This is about average. There were 30 monitors within city limits.
Lead (Pb) [µ/m3] level in 2010 was 0.00025. This is significantly better than average. There were 22 monitors within city limits.
Carbon Monoxide (CO) [ppm] level in 2010 was 0.245. This is better than average. There were 20 monitors within city limits.
Nitrogen Dioxide (NO2) [ppb] level in 2010 was 4.26. This is significantly better than average. There were 33 monitors within city limits.
Drinking water stations with addresses in Greenville and their reported violations in the past:GREENVILLE WATER SYSTEM (Population served: 337701, Surface_water):
Past health violations:
Percentage of residents living in poverty in 2012: 18.6%
(9.1% for White Non-Hispanic residents, 35.4% for Black residents, 20.4% for Hispanic or Latino residents, 12.1% for American Indian residents, 14.7% for Native Hawaiian and other Pacific Islander residents, 7.9% for other race residents, 47.9% for two or more races residents)
Average household size:
Percentage of family households:
Percentage of households with unmarried partners:
Likely homosexual households (counted as self-reported same-sex unmarried-partner households)
Detailed information about poverty and poor residents in Greenville, SC
People in group quarters in Greenville in 2010:
People in group quarters in Greenville in 2000:
Greenville compared to South Carolina state average:
Banks with most branches in Greenville (2011 data):
Fire-safe hotels and motels in Greenville, South Carolina:
Educational Attainment (%) in 2012
School Enrollment by Level of School (%) in 2012
Most commonly used house heating fuel:
Presidential Elections Results
1996 2000 2004 2008 2012
1996 Presidential Elections Results
2000 Presidential Elections Results
2004 Presidential Elections Results
2008 Presidential Elections Results
2012 Presidential Elections Results
Graphs represent county-level data. Detailed 2008 Election Results
Religion statistics for Greenville city (based on Greenville County data)Percentage of population affiliated with a religious congregations: 57.34%
Breakdown of population affiliated with a religious congregations
Tables represent county-level data.
Food Environment Statistics:
Number of grocery stores: 86
Number of supercenters and club stores: 6
Number of convenience stores (no gas): 23
Number of convenience stores (with gas): 198
Number of full-service restaurants: 383
Adult diabetes rate:
Adult obesity rate:
Low-income preschool obesity rate:
Greenville government finances - Expenditure in 2006 (per resident):
Greenville government finances - Revenue in 2006 (per resident):
Greenville government finances - Debt in 2006 (per resident):
Greenville government finances - Cash and Securities in 2006 (per resident):
7.48% of this county's 2006 resident taxpayers lived in other counties in 2005 ($47,357 average adjusted gross income)
0.09% of residents moved from foreign countries ($490 average AGI)
Top counties from which taxpayers relocated into this county between 2005 and 2006:
5.95% of this county's 2005 resident taxpayers moved to other counties in 2006 ($46,283 average adjusted gross income)
0.07% of residents moved to foreign countries ($617 average AGI)
Top counties to which taxpayers relocated from this county between 2005 and 2006:
Strongest AM radio stations in Greenville:
Strongest FM radio stations in Greenville:
TV broadcast stations around Greenville:
Fatal accident count (per 100,000 population)
See more detailed statistics of Greenville fatal car crashes and road traffic accidents for 1975 - 2011 here
National Bridge Inventory (NBI) Statistics
Number of bridges: 51
Total length: 295 meters (968ft)
Total costs: $4,936,000
Total average daily traffic: 775,529
Total average daily truck traffic: 46,023
New bridges - Historical Statistics
FCC Registered Cell Phone Towers: 1 (See the full list of FCC Registered Cell Phone Towers in Greenville)
FCC Registered Antenna Towers: 754 (See the full list of FCC Registered Antenna Towers)
FCC Registered Commercial Land Mobile Towers: 30 (See the full list of FCC Registered Commercial Land Mobile Towers in Greenville, SC)
FCC Registered Private Land Mobile Towers: 104 (See the full list of FCC Registered Private Land Mobile Towers)
FCC Registered Broadcast Land Mobile Towers: 24 (See the full list of FCC Registered Broadcast Land Mobile Towers)
FCC Registered Microwave Towers: 216 (See the full list of FCC Registered Microwave Towers in this town)
FCC Registered Paging Towers: 27 (See the full list of FCC Registered Paging Towers)
FCC Registered Maritime Coast & Aviation Ground Towers: 18 (See the full list of FCC Registered Maritime Coast & Aviation Ground Towers)
FCC Registered Amateur Radio Licenses: 558 (See the full list of FCC Registered Amateur Radio Licenses in Greenville)
FAA Registered Aircraft Manufacturers and Dealers: 13 (See the full list of FAA Registered Manufacturers and Dealers in Greenville)
FAA Registered Aircraft: 144 (See the full list of FAA Registered Aircraft)
Detailed mortgage data for all 22 tracts in Greenville, SC
Conventional Home Purchase Loans
Conventional Home Purchase Loans - Value
2006 National Fire Incident Reporting System Incidents:
Incident types - Greenville
See full 2006 National Fire Incident Reporting System statistics for Greenville, SC
Greenville on our top lists:
Total of 2072 patent applications in 2008-2014.
Back to Greenville, SC housing info, Greenville County, South Carolina, SC smaller cities, SC small cities, All Cities.

subset: commoncrawl


text:
Dear all, I started to go through the meeting minutes of our group and collected everything i found in a wiki entry [1] as asked in action 207 [2]. These things are a little bit more structured, but from the content point of view only a few things more. There was some discussion in the mailing list, about the test suite (05.11.2009 - 11.11.2009). I will try to summarize the ideas on monday. Best, Florian [1] http://www.w3.org/2008/WebVideo/Annotations/wiki/TestSuite [2] http://www.w3.org/2008/WebVideo/Annotations/track/actions/207 _____________________________ Dipl. Inf. Florian Stegmaier Chair of Distributed Information Systems University of Passau Innstr. 43 94032 Passau Room 248 ITZ Tel.: +49 851 509 3063 Fax: +49 851 509 3062 email@example.com https://www.dimis.fim.uni-passau.de/iris/ http://www.jpsearch.org http://www.mpegqueryformat.org _____________________________Received on Friday, 22 January 2010 12:59:06 GMT
This archive was generated by hypermail 2.2.0+W3C-0.50 : Friday, 22 January 2010 12:59:07 GMT


text:
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Paris, France
67 Avenue Du Maine, 14th arr., 75014 Paris, France – Show map – Subway access
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Citadines Maine Montparnasse Paris's staff speaks: French, Spanish, English
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Internet via modem is available in the hotel rooms and is free of charge.
WiFi is available in public areas and is free of charge.
WiFi is available in the business center and is free of charge.
Private parking is available on site (reservation is needed) and costs EUR 30 per day.
Vending Machine (drinks), Vending Machine (snacks), 24-Hour Front Desk, Baggage Storage, Babysitting/Child Services, Laundry, Dry Cleaning, Ironing Service, Business Center, Fax/Photocopying
Newspapers, Safe, Non-smoking Rooms, Facilities for Disabled Guests, Elevator, Heating, All Spaces Non-Smoking (public and private), Air Conditioning
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Oceania Paris Porte De VersaillesLatest booking: 7 hours ago There is 1 person looking at this aparthotel.
accsess to the transportation
No kitchin at the room. I supposed that this type of apartment hotel had a kitchin.
My wife and I had a room without a kitchenette, but which included breakfast. The room was compact but well designed and comfortable with all the required amenities. Friendly reception staff. The hotel is excellently located for transport: close to the Montparnasse railway station and metro, as well as two other metro stations. We used the Air France bus from the CDG airport, which has its last stop at the Montparnasse railway station which is within easy walking distance (even with luggage) from the hotel. Good value for money.
staff at reception really helpful
Location, helpful staff
Bed was too short
Great location, you can just walk to metro station and Montparnasse train station
The room is a bit too small, yet very comfortable
The kitchen equipment are very clean and sufficient for cooking and eating.
The staff at reception were very friendly and helpful.
It's a wonderful property, the room is very small, but full of utilities.( kitchen, iron).Good to stay for one night specially if you are coming to Paris by train from Montparnasse station, hotel is 100mts away. Also it's a good point to take Air France Bus to CDG or orly. As well good place to come at late hours from Air port by the Air France Bus. The street inside are full of bars, restaurants, convenient shops.
I will not say its bad or I didn't like, just that it's too small. Specially once you open the bed. (It's a sofa cum bed), it's comfortable. But much better, cleaner than other hotels in Montparnasse and also a safe option to stay rather than trying a new property..
The male receptionists were gracious and helpful.
For 133€ a night clean towels should be given more than once a week. 3rd time we have stayed there and last due to poor maintenance, difficult wifi connections, inhospitable, unhelpful female receptionist when we arrived who gave us their tiniest studio apt. #85 with one window, slanted ceiling, teeny kitchenette and mini closet in spite of noticing my husband was6'3", we were booked for 5 nights, had booked and prepaid several months in advance and were repeat 5 night customers 3 years in a row. After my husband said # 85 was unacceptable, we were relluctantly given #75. Last two years the apts. were in good condition. This year definitely no one checking the poorly malfunctioning toilet, barely draining bathroom sink, missing kitchen items available previous visits, inoperative safe, curtains falling apart at top so they made it hard to open and close windows. And when problems were noted, same female receptionist would not even offer us any timely assistance. When toilet wall flushing component was about to fall out of the wall and maybe flood the apt. we were offered use of bathroom on another floor. Then, my husband said give us another room or get that toilet fixed, since 24 hour plumbing services exist! We left for the day and came back to fixed toilet and pleasant male receptionist.
Single foldout beds were uncomfortable and advertised as double
Location was the reason chosen
Did not know it was sofa beds, room small and photos online were very misleading. Room not available after official check in time.
Great location near metro, usual well-equipped Citadines room with strong Wifi signal, very comfortable sofa bed, spotless modern bathroom, fantastic free coffee on demand and great staff.
Hotplate had a mind of its own!
near from metro, bus stop, super market etc....
there is no dish washer in the room.
Loved the staff, the cleanliness and style of the furnishings, the location, the coffee/tea machine in the lobby, the daily newspapers and the bathtub!
Wish the bed was a bit larger for comfort, but room size wouldn't really be able to accommodate that.
The location
The room was small, the bed was a sofa bed, no coffee machine in the room, and all that for $175.00 a night! Outrageously expensive even for Paris! There are a lot of good reasonably priced hotels in Paris - this place is not one of them.
Good bed Clean
Small room, when I expected a more spacious appartment
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text:
Devon Energy Corporation (NYSE:DVN)
Q3 2007 Earnings Call
November 7, 2007 11:00 am ET
Vince White - Vice President, Investor Relations & Communications
J. Larry Nichols - Chairman of the Board, Chief Executive Officer
Stephen J. Hadden - Senior Vice President - Exploration and Production
John Richels - President, Director
Brian Singer - Goldman Sachs
Tom Gardner - Simmons & Company
Gil Yang - Citigroup
Joe Hofer - Wachovia Capital Markets
Mark Gilman - The Benchmark Group
David Heikkinen - Tudor, Pickering & Co.
Welcome to Devon Energy's third quarter earnings conference call. (Operator Instructions) I would like to turn the conference over to Mr. Vince White, Vice President of Communications and Investor Relations. Sir, you may begin.
Vince White
Thank you, Operator and good morning to everyone. Welcome to Devon's third quarter 2007 conference call and webcast. Today's call will follow our standard format; that is, starting with our Chairman and CEO, Larry Nichols, who will provide his perspective on Devon and the quarter; and following Larry, Steve Hadden, our Senior Vice President of Exploration and Production, will cover the operating highlights; and then Devon's, John Richels, will conduct the financial review.
As usual, we will open the call up to questions and we will try to hold the call to about an hour.
A replay of the call will be available later today through a link on our website. That is devonenergy.com. We will also be posting to the website a new issue of Devon Direct. That's our electronic report that includes highlights from the webcast and includes links to supplementary information.
During the call today, we are going to update some of our estimates based on actual results for the first three quarters of the year and our outlook for the balance of the year. In addition to the updates that we'll provide in today's call, we plan to file a Form 8-K later today and that will document all the details of our updated guidance.
Also, please note that the references in today's call to our plans, forecasts, estimates and so on are forward-looking statements as defined by U.S. securities law. There are a number of factors that could cause our actual results to differ from those estimates, so we would encourage you to review the discussion of risk factors that accompany the estimates in the Form 8-K.
One other compliance note; we will make reference today to certain non-GAAP performance measures. When we use these measures, we're required by securities law to provide certain related disclosures. You can see those disclosures. They are available on our website. Again, that's devonenergy.com.
Finally, I want to remind you that our decision to sell our assets in Africa triggered the discontinued operations accounting rules. Under those rules, we exclude oil and gas produced from the assets selected for divestiture from reported production volumes for all periods presented. The related revenues and expenses for the discontinued operations are collapsed into a single line item at the bottom of the statement of operations.
However, in the spirit of full disclosure, you will find an additional table in today's news release that includes a detailed statement of operations and the related production volumes attributable to the properties that we are divesting.
I also want to point out that net earnings from discontinued operations were $91 million in the third quarter. However, that does not mean that the discontinued operations would have contributed the full $91 million of additional earnings if we were not selling them. That's because the accounting rules for discontinues operations require us to stop recording depletion expense on the sale properties once we make the decision to divest them.
Had we not chosen to exit Africa, we would have reported net income associated with the divestiture properties of $66 million, or $25 million less than the $91 million of income from discontinued operations for the quarter.
Accounting for these discontinued operations also complicates the comparability of earnings estimates. Most of the analysts that reported estimates to First Call this quarter excluded the impact of the discontinued operations. The mean estimate of earnings per share from the analysts that excluded it was $1.39 per share. That compares to our non-GAAP earnings from continuing operations of $1.41 per share.
The mean estimate for analysts that included discontinued operations in their estimates was $1.47 a share, and that compares to our non-GAAP diluted earnings of $1.55 per share for the third quarter, including discontinued operations. So in either case, our non-GAAP earnings beat the street expectations.
With those items out of the way, I will turn the call over to Larry Nichols.
J. Larry Nichols
Thanks, Vince. The third quarter was another excellent one for Devon. We made progress both from an operational standpoint, a financial standpoint, and some important strategic actions, of which I'll comment on in a moment.
For the third quarter, oil and gas production exceeded our expectations and our guidance. Our production grew 10% over the third quarter of 2006, which provides us with our sixth consecutive quarter of organic production growth.
We outperformed our third quarter forecast by nearly 2 million equivalent barrels, which allows us to increase our full year production forecast. John Richels will discuss the drivers of this production outperformance and the revised guidance in a little bit.
The financial results for the third quarter were also very positive. Net earnings were $735 million and earnings per share exceeded street expectations, both with and without discontinued operations.
Cash flow before balance sheet changes increased 15% to $1.8 billion, bringing the year-to-date cash flow to $5 billion. We funded total capital expenditures of $1.6 billion and we repurchased 120 million shares of our common stock and ended the quarter with $1.7 billion of cash and short-term investments. We ended the quarter with net debt to adjusted cap at its lowest point in 10 years at 19%.
Following the end of the third quarter, we moved forward with our Africa divestiture program by closing the sale of the Egyptian operations in early October. As of the closing date, the adjusted sales price was $341 million, and we do not expect to pay any income tax on this transaction.
We are finalizing purchase and sales agreement and getting the necessary partner and governmental approvals for the remaining African assets. Although the process has been complicated and time consuming, we are optimistic that we can complete all of these transactions by the end of the first half of 2008.
In today's release, we've provided an update on our previously announced MLP, our master limited partnership. As noticed in the release, we have reconsidered our plans to form a marketing and midstream MLP. This decision reflects our views about the current condition of the public market for yield-driven instruments. The market today is just less receptive than it was when we announced our plans, so we are putting that project on hold.
With Devon's marketing and midstream business generating more than $450 million in operating profits, we believe it is prudent to be very cautious with any decision affecting this important and strategic part of our business. Although we have no firm timeline for revising the project, we will reconsider it in the future should market conditions change.
Before I turn the call over to Stephen Hadden, I want to share with your our perspective on the royalty situation in Alberta. As you probably know, in late October, the Alberta Government announced a change in the royalty regime in that province. With Canada providing a quarter of Devon's current oil and gas production, and with most of that in Alberta, any change in the royalty structure is of course a concern.
The new structure is somewhat complex and we are still evaluating the impact of the changes on our Canadian operations, but it does seem likely that there will be some economic impact.
Devon's capital investments are of course based not just on royalty rates but rather on expected full cycle returns. Those expected returns are impacted by our expectations for production, realized oil and gas prices, capital costs, operating costs, foreign exchange rates, and a host of other things .
On a positive note, last week the Canadian Federal Government announced a budget proposal which, if enacted, would reduce corporate income taxes, which would have a positive impact on our Canadian returns. You can be assured that our future investment allocation decisions will continue to take into account not only the implications of the Alberta Government's decision to change the terms under which we operate, but also all of the return criteria we evaluate.
Fortunately, Devon has a very large and diverse portfolio which will allow us to reallocate capital, both within capital and between -- both within Canada and between Canada and across all of our other operating divisions. We of course will choose those areas which generate the most favorable return.
At this point, I will turn the call over to Stephen Hadden. Stephen.
Stephen J. Hadden
Thanks, Larry and good morning to everyone. Let's start with a look at our 2007 capital spending. During the third quarter, our exploration and development CapEx totaled $1.4 billion, bringing year-to-date E&P capital expenditures to $3.8 billion. As we noted in last quarter's call, we expect full year E&P capital to come in near the top of our forecasted range at about $5.3 billion.
At the end of the third quarter, we had 150 rigs running company wide, with 89 of those rigs drilling Devon operated wells. We drilled 599 wells company-wide during the quarter. Twenty-four were classified as exploratory, of which 92% were successful. The remaining 575 wells were development wells and about 98% of those wells were successful, giving us an overall success rate for the quarter of roughly 98%.
Now let's move to our quarterly operational highlights, beginning with the Barnett Shale field. We reached a significant milestone during the third quarter by drilling our 1,000th Devon operated Barnett Shale well. It was just about five years that Devon pioneered horizontal drilling in the Barnett. Due to the superior economics and reduced surface impact, almost all the wells being drilled in the Barnett today are horizontal.
Horizontal wells make up about one-third of our Barnett producers, but account for about two-thirds of our Barnett production. Our Barnett Shale production averaged a record 856 million cubic feet of gas equivalent per day in the third quarter. This was a 7% gain from the second quarter and up 32% compared with the third quarter of 2006.
In our last call last quarter, we revised our year-end target rate to 875 million cubic feet of gas equivalent per day and we are well on the way to hit that goal. We had also previously announced a longer term net target rate of 1bcf per day by the end of 2009. Given our progress to date and the pace we are on, we now expect to reach the 1 bcf mark per day by early 2009. This is more than twice the forecasted production of our next closest competitor.
This leading position in the play has been well established through our first mover advantage. That advantage has given us unmatched size and scale in the play. Since 2001, with our acquisition of Mitchell, we built a lease position of over 735,000 acres with very favorable lease terms. Devon has an average royalty burden of under 20% on these leases. This compares to a royalty burden on most leases taken in the Barnett over the last several years of 25% or greater.
The economic impact of a lower royalty burden is dramatic. On a typical 2.5 bcf Barnett well drilled for about $3 million in a $6 per mcf realized gas price environment, a well with a 20% royalty burden has about 1.4 times the present value of a well with a 25% royalty burden.
A large portion of our acreage is concentrated in the better areas of the play, such as the core area in Johnson County. Accordingly, we have a superior acreage position and years of additional drilling inventory in the better portions of the play.
Our history of being the first to identify new applications of technology has been well-established since the beginning. Devon was the first to unlock the early potential of the play with light sand fracs and horizontal drilling. While all of the major operators in the play have the same drilling and completion services available to us, the various operators choose to complete wells differently. Various lateral lengths and number of frac stages can impact IPs per well, recoveries per well, and ultimately well economics.
Rather than focus on maximizing per well production or reserves, Devon has chosen to optimize return with our well designs. We now have 3,000 wells in the play and we are drilling at a rate of over 500 wells per year, by far the largest in the play. This scale allows us to establish an in-depth knowledge of the reservoir, as well as very strong, long-term relationships with the leading drilling and pumping service providers in the country, providing reliability, performance, and value.
We have been asked recently if we plan to integrate vertically in the play through the purchase of drilling rigs or completion related assets. It's always been our view that it's best to allow the specialists to do what they do best while our team stayed focused on combining innovation and our deep understanding of the Barnett Shale to deliver the best value growth and return for our shareholders.
These relationships have allowed Devon to hold our well costs flat over the past year, despite the cost escalations experienced by our industry over the same period. We accomplish this while ramping up activity from 385 wells in 2006 to over 500 wells this year, growing our production 32% compared to the third quarter of 2006.
Devon will keep its focus on maintaining the lead position in the play with the best acreage position, the best lease terms, and the most consistent execution, and we'll provide an early achievement of our 1 bcf per day goal.
During the third quarter, we completed a total of 127 Barnett wells, 50 of which were in the core and 77 were outside the core. We remain on pace to drill 500 wells in the Barnett Shale this year and we are running 32 Devon operated rigs, nine in the core area and 23 outside the core.
Our non-core drilling program in Johnson County continues to shine. In the third quarter, we put 39 new wells online in Johnson County at an average rate of 2.5 million cubic feet per day. Four particularly strong wells each had 24 hours sustained initial production rates averaging above 5 million cubic feet per day.
North of Johnson County in Southern Wise County, we brought two exception wells online at 5.4 million and 6 million cubic feet per day, so we continue to see solid results from our non-core horizontal drilling with typical yields between 1.5 and 2.5 bcf per well, with some as high as 8.4 bcf.
In addition to expanding the play in new directions, an important part of our activity in the Barnett Shale is in-fill drilling or down-spacing in areas that have already been fully developed on primary spacing. These in-fill wells are usually referred to as 20 acre in-fill wells. However, I'll remind you that with horizontal drilling, one well can replace several 20 acre vertical well locations. Consequently, from a surface development perspective, 20 acre in-fill horizontal wells actually occupies 80 surface acres.
Since we began this horizontal in-fill program, we've completed a total of 139 of these in-fill wells. A total of 127 that have been connected to the producing grid are horizontal with average initial production of 2.2 million cubic feet per day. Economics from the horizontal in-fill wells we've drilled to date are very solid at an average drilling and completion cost of about $2.9 million and approximately 2.1 bcf per well estimated recovery.
In addition, we've been experimenting with further horizontal down-spacing. We have completed a total of 11 operated wells that are spaced to result in two wells per 80 acres, or 40 surface acres per well. Seven of these have been tied into production, with an IP of 2.5 million per day. This down-spacing is one of the ways we expect to convert into crude reserves more of the 13 trillion cubic feet of potential, represented by Devon's 735,000 Barnett acres.
While we are very encouraged by these early results, we'll need to see more production data before developing large areas based on one horizontal well per 40 acres.
It the Woodford Shale in eastern Oklahoma, we currently have five operated rigs drilling in the play. We brought a total of eight new operated wells online during the third quarter with individual well production rates as high as 4 million cubic feet of gas a day. We now operate 46 wells in the Woodford, with gross operated production running about 38 million cubic feet per day.
Our net Woodford Shale production averaged 20 million cubic feet per day in the third quarter, up almost 70% compared with the third quarter of 2006. On average, our Woodford Shale wells are costing between $4.1 million and $4.3 million to drill and complete, and yielding about 2.5 bcf of reserves per well.
Moving to the Rockies and the Washakie Basin in Wyoming, we had five rigs running throughout most of the third quarter. During the quarter, we drilled 16 wells and brought 15 on production. Devon's net production at Washakie averaged about 100 million cubic feet per day in the third quarter.
Shifting to east Texas, we continue with a seven-rig vertical Cotton Valley drilling program in the Carthage area. In the third quarter, we drilled 25 vertical wells and continued an active recompletion program. At the end of the quarter, we were drilling with 66 wells in a 95 well vertical program that's planned for this year. Looking forward, we have a significant drilling inventory with as many as 420 additional vertical locations available, including about 65 20-acre in-fill locations.
We also continue to see good results from our three-rig horizontal drilling program in the Carthage area. We drilled and completed five new Cotton Valley horizontal wells during the third quarter, including the 100% working interest Davis 4H well that averaged 6.6 million cubic feet of gas per day for the first 30 days of production.
Since we first tested the horizontal drilling concept in the Carthage area about one year ago, we've drilled 11 out of 11 successful horizontal wells. These wells cost from $5.5 million to $7 million per well to drill and complete, with estimated ultimate recoveries of 3 to 6.5 bcf per well.
We have as many as 96 additional horizontal locations to drill at Carthage. In total, our net Carthage production average 260 million cubic feet of gas equivalent per day for the third quarter, up 5% from the second quarter average and up 8% from a year ago. With a lot of running room for both the horizontal and vertical well programs, we believe we can continue to grow Carthage production well into the future.
Shifting to the Gulf of Mexico and our deepwater production operations, we established production from the two subsidy wells at Merganser in the third quarter. These gas wells are flowing into the independent hub and are currently producing at a combined rate of more than 68 million cubic feet of gas per day net to Devon's interest. This rate is 36% better than our forecasted rate, so we are obviously very pleased with the early performance of these wells.
In our deepwater [inaudible] and exploration program, we expect to begin drilling on the Sturgess North prospect located in Atwater Valley Block 138 in early 2008. We made an initial discovery at Sturgess in 2003, encountering over 100 feet of net oil pay. Sturgess North is located adjacent to the Sturgess discovery but will test a separate geologic structure. Devon has a 25% working interest in this Chevron operated prospect.
Our lower tertiary exploration program was in full swing during the third quarter. Early drilling on our Chuck prospect located in Walker Ridge 278 has gone slowly as the Ocean Endeavor rig was being debugged by Diamond Offshore. We believe that most of the start-up issues have been resolved and we are currently drilling below 21,000 feet. Chuck is targeting a large sub-salt structure in about 6,500 feet of water and Devon is the operator of Chuck, with a 39.5% working interest.
We expect to begin drilling an exploratory well on the Green Bay prospect around year-end. This lower tertiary exploration prospect is located on Walker Ridge 372 in approximately 6,300 feet of water. The prospect is about 20 miles north of the St. Malo discovery and about 18 miles east of the Chuck prospect. Devon has a 23.4% interest in Green Bay.
We are continuing with appraisal and development activities on the four significant lower tertiary discoveries which we've participated in to date. Last quarter, we began drilling a location on our Keathley Canyon Block 244 in the Kaskida unit. This location, previously known as Cortez Bank, is located about 12 miles west of our 2006 Kaskida discovery. The well was drilling in a side-tracked hole to a proposed depth of 33,000 feet when mechanical issues forced the well to be abandoned before reaching the target objective.
While it is always a disappointment to spend capital on a well that fails to reach its intended objective, this result does not dampen our enthusiasm for the unit. The Kaskida discovery well clearly encountered a very significant oil column and we have a lot of work left to do to fully understand the potential of the unit.
The joint owners are now integrating the results from the two wells, along with seismic data to determine our next location in the unit. Devon has a 20% working interest in the unit, which is operated by BP. The next well operation is expected some time in the first half of 2008.
At Cascade, our lower tertiary development with Petrobras in the Walker Ridge area, we sanctioned development during the third quarter. We have submitted operating and development plans to the MMF and we have awarded the FPSO and shuttle tanker contracts. We now anticipate initial production at Cascade to likely be in the first half of 2010.
Our approach to development at Cascade will allow us to produce the first wells over a sustained period. Reservoir information gathered during that initial period phase will help us determine the optimum number and placement of producing wells and allow optimization of full field facilities for the project. Devon and Petrobras each have 50% working interest at Cascade.
At Jack, also in Walker Ridge deepwater lease area, Devon and our co-owners expect to finish drilling operations on a second delineation well, the Jack Number Three, in the first half of next year. The well will be operated by Devon and drilled with the Ocean Endeavor rig.
Finally, at St. Malo, also in the Walker Ridge deepwater area, we are currently drilling our second delineation well and we hope to have the results in the first quarter of 2008. These additional Jack and St. Malo wells will providing important data that will help the partners determine the optimum development approach to these discoveries.
I will remind you that Devon has a 25% working interest in Jack and a 22.5% working interest in St. Malo.
Moving to Canada, in the Lloydminster oil play in Alberta, we have increased production by over 50% over the past 12 months to 34,600 barrels of oil per day. We continues to have an active five rig program in the third quarter, as we drilled 125 new Lloydminster wells. A second 10,000 barrel a day expansion at our [Manitokin] plant is underway and we expect to complete that work by the end of 2008.
At the Devon operated Jackfish thermal heavy oil project in Eastern Alberta, we began steam injection in the third quarter. We are wrapping up final pre-commissioning activities and expect to see first production from Jackfish around the end of this year. As previously indicated, production will then ramp up toward an expected, sustainable rate of 35,000 barrels per day.
At Jackfish 2, engineering and budgeting work continue and we expect to receive regulatory approval around mid-2008. At that point, we will make a formal decision about the project. This project would add another 35,000 barrels of day of thermal oil.
Moving to the international arena, development drilling at the Devon operated Polvo project on Block BM-C-8 in Brazil continued during the third quarter. We achieved first oil on July 26 and have completed the first three of a total of 10 planned producing wells, which reach a combined growth rate of 9,500 barrels per day. The field's first lifting of 385,000 barrels occurred on October 21st. The fourth well is currently drilling. The additional wells will be drilled and tied in throughout the remainder of this year and into 2008 as we ramp up the field's production.
In Azerbaijan, where Devon had a 5.6% working interest in the ACG oil field, our share of ACG production averaged about 28,000 barrels per day in the third quarter. As expected, there were about 17 days of downtime at ACG in the third quarter to perform facility upgrades to both offshore and onshore infrastructure. Field production has since been brought back online.
In China, we expect to drill our Watermelon prospect located on Block 4205 in the first quarter of 2008. You might remember Block 4205 is adjacent to Block 2926, where Husky and CNOOC announced a multi-pcf gas discovery. However, this well has all the typical risks of an exploration well. Devon operates Block 4205 with 100% working interest.
That concludes my comments on our operational highlights for the quarter. I'll now turn the call over to John to review our financial results. John.
John Richels
Thank you, Steve and good morning, everyone. This morning, I will take you through a brief review of the key drivers of our third quarter financial results and take a look at how they impact our outlook for the remainder of the year. You can find the details of our updated forecast in the form 8-K that we'll be filing today, as Vince mentioned earlier.
As a reminder, we have reclassified the assets, liabilities and results of operations in Africa as discontinued operations for all accounting periods presented. As a result, I'll focus my comments only on our continuing operations, which exclude the results attributable to the divestiture properties.
Let's begin with production. In the third quarter, we produced 56.8 million equivalent barrels, or approximately 618,000 barrels per day. This exceeded our guidance by about 3% or nearly 2 million barrels.
Approximately three-quarters of this outperformance was due to better-than-expected results from several of our core properties in North America and the remainder of the outperformance was attributed essentially to the absence of anticipated downtime for hurricanes in the Gulf of Mexico and the postponement of planned facilities repairs at our offshore [Puguang] project in China. Thankfully, we've had an uneventful hurricane season and the repair work at [Puguang] is now scheduled to begin in the fourth quarter of 2007.
When you compared our third quarter results to the same quarter a year ago, you'll find that company-wide production increased by 10%, or approximately 55,000 barrels per day. This reflects year-over-year growth in our U.S. onshore, Canadian and international segments. Production from the U.S. onshore region grew by nearly 40,000 barrels per day, or 12% when compared to the third quarter of 2006.
Continuing a trend, the leading driver of our U.S. onshore performance was strong production growth from our Barnett Shale assets. We also experienced significant growth in the international sector, almost entirely attributable to increased production from the ACG field in Azerbaijan.
In Canada, total third quarter production increased 2% over the third quarter of 2006. This was achieved in spite of significantly scaling back on our Canadian conventional natural gas program. Growth in Canada was driven principally by drilling on our Lloydminster oil properties.
Looking ahead to the fourth quarter, we expect to grow company-wide production for a seventh consecutive quarter. In total, we anticipate fourth quarter production of approximately 57 million equivalent barrels. Key growth drivers will be our U.S. onshore assets, a full quarter of production from Merganser and Polvo, and an uninterrupted quarter of production in Azerbaijan.
However, this growth will be offset somewhat by the rescheduled downtime for equipment replacement in China, along with anticipated declines from our conventional gas fields in Canada.
Based on strong performance for the first nine months, coupled with a bright fourth quarter outlook, we are now increasing our full year production forecast to 223 million equivalent barrels. This will add another percent or two to the 10% year-over-year growth target we had previously forecast for 2007.
Although we expect to finish 2007 ahead of our previous production forecast, we are not increasing our guidance for 2008 at this time. We typically finalize our capital budget in the fourth quarter and submit it to our board of directors in December for approval. Following board approval, we provide updated production guidance. Until we complete the budgeting process and determine the optimal level for our 2008 capital spending, we'll stick with our previous forecast for 2008 of 240 to 247 million barrels equivalent.
Moving on to price realization, starting with oil, in the third quarter the benchmark WTI oil price rose to an average of $75.21 per barrel. That's a 16% increase from the second quarter of 2007.
In addition to higher benchmark prices, regional differentials remain tight with the results of price realizations in all of our producing regions where we are above the midpoint of our guidance ranges.
Our company wide realized price came in at $67.41 per barrel, or about 90% of WTI. That's a 12% improvement in realized prices over the last quarter.
Although differentials have widened recently for heavy and sour crudes as benchmark prices have increased, we are still comfortable with our full year guidance for oil price differentials. I'll remind you that since none of our oil volumes are hedged, we are benefiting from further increases in oil prices that we are seeing in the fourth quarter.
On the natural gas side, the benchmark Henry Hubb index averaged $6.16 per MCF in the third quarter, some 6% below last year's third quarter. Our company-wide gas price realizations were generally in line with guidance at approximately 86% of Henry Hubb.
Strong price realizations in the Gulf of Mexico and in Canada were mostly offset by continued price weakness within the Rocky Mountain producing area. You're probably aware that the price differentials in the Rockies have widened significantly over the past several months, due primarily to constrained regional export capacity.
The impact on Devon, however, has been limited because the Rockies represent less than 10% of our company wide natural gas production.
Looking ahead to the fourth quarter, we expect natural gas price differentials to be very similar to the third quarter.
Turning now to our marketing and midstream business, once again marketing and midstream operations delivered excellent results. Marketing and midstream operating profit for the third quarter came in at $133 million, $21 million more than in the third quarter of 2006. The increase is due to higher gas processing margin in the 2007 quarter.
Based on the strength of the first three quarters, we're again increasing our 2007 operating profit forecast. We now expect Devon's marketing and midstream full year operating profit to come in between $460 million and $490 million. At the midpoint, this represents an increase of $35 million from the midpoint of our previous guidance range.
Moving to expenses, third quarter lease operating expenses were at the low end of our guidance range, coming in at $457 million, or $8.04 per equivalent barrel. This was essentially flat to our average LOE rate for the first half of the year.
For the quarter, unit LOE costs remain steady or decreased in most of our major operating regions with the exception of Canada. In Canada, LOE remains under pressure from the strength of the Canadian dollar.
In the fourth quarter, we expect a moderate rise in LOE costs due to new development projects ramping up production and also a seasonal increase in operating costs in Canada.
For the full year, we expect lease operating expenses to be near the top of our previous guidance range.
Our reported third quarter DD&A expense for oil and gas properties came in at $12.41 per barrel. This was $0.16 above the high end of the guidance range we provided in our second quarter conference call. The higher-than-anticipated depletion rate is entirely due to low spot gas prices in the Rockies at September 30th. This resulted in a temporary reduction in reserves for the calculation of depletion. We expect this situation to correct itself in the fourth quarter and accordingly, we expect our DD&A rate to return to where it otherwise would have been.
However, due to the higher-than-expected rate in the third quarter we now expect our full year DD&A rate to come in near the top of our previous forecast range.
Moving on to G&A expense, G&A expense for the third quarter was $126 million. This result is a couple of million dollars above the quarterly range implied by our full year forecast, and $13 million higher than last quarter. Higher employee related costs were the primary driver.
Looking ahead, based on our year-to-date results and in anticipation of continued upward pressure on personnel costs, we're now increasing our full year G&A guidance by $30 million to a new range of $490 million to $510 million.
A final expense item I want to touch on is income taxes. After adjusting out the items that are generally excluded from analysts estimates, income tax expense for the third quarter came in at 33% of pretax income. The current tax position is roughly 10% of pretax earnings and the deferred tax piece came in at about 23% of pretax earnings. This brought the adjusted income tax rate for the first nine months of 2007 to 32%, with half current and half deferred. The 32% overall income tax rate, with roughly half deferred, reflects our expectations for the fourth quarter and full year 2007.
In today's 8-K, we are providing updated guidance that reflects the lower percentage of taxes that are classified as current.
After backing out income tax expense, our reported earnings from continued operations for the third quarter totaled $644 million, or $1.43 per diluted share. Earnings from discontinued operations added another $91 million, or $0.20 per diluted share in earnings. In aggregate, after backing out the items that are usually excluded from analyst estimates, our adjusted net earnings for the third quarter were $700 million, or $1.55 per diluted share.
This translates into cash flow before balance sheet changes for the third quarter of $1.8 billion, bringing the total year to $5 billion. We used cash flow to fund third quarter capital expenditures of about $1.6 billion, leaving roughly $200 million of free cash flow for the quarter. We used the majority of this free cash flow to return more than $180 million to shareholders through share repurchases and dividends. We also received $106 million of exchange requests related to our Chevron exchangeable debentures and we chose to retire those obligations with cash rather than to redeem them with the Chevron shares that we hold.
Even with the redemption activity, we concluded the quarter with a healthy cash balance of $1.7 billion and with our net-debt-to-capitalized ratio, or net-debt-to-capitalization ratio under 20%.
Looking forward, we expect cash flow from operations to roughly cover our capital demands. This will leave us with after-tax proceeds from the African divestitures to repay short-term borrowings and to continue to repurchase our stock.
All in all, this was another outstanding quarter for Devon and with that, we'll open the call up for Q&A.
Vince White
Operator, we're ready for the first question.
Question-and-Answer Session
(Operator Instructions) Our first question comes from Brian Singer from Goldman Sachs.
Brian Singer - Goldman Sachs
Thank you. Good morning. A question on Canada; if you look at your overall portfolio beyond Canada, what area do you see that has the greatest combination of opportunity and capacity to take capital, should you further reduce drilling in Canada? Or would you look toward the acquisition market in part?
Stephen J. Hadden
We have a, as you mentioned, a very deep portfolio. Mainly where we would look is in the U.S. onshore business. John mentioned that strong 12% growth that we've seen happening in that aspect of the business. We would probably redeploy it into areas like we have in the Barnett where we are now drilling 500 wells where we initially estimated we would drill 385 at the beginning of this year.
And we have good opportunities in the Carthage area and some of the east Texas areas, so generally, that give us -- those are some examples of the areas that give us some of that swing. The U.S. onshore is a good opportunity for us.
I will mention that within Canada, we have both a very viable thermal oil business but we also have the Lloydminster area and some very good cold flow heavy oil opportunities that I think you heard earlier in our comments that we've been able to grow about 50% year over year.
So within Canada, we can actually -- we have a pretty good portfolio in Canada that allows us to redeploy capital within Canada away from maybe some of the lower returns we may be seeing in the Canadian conventional gas business, and those are very good and solid returns that we get in the Lloyd area.
We can optimize within Canada first and then as we look across our portfolio, we have other areas where we can go to for that near-term growth.
J. Larry Nichols
I might add that within Canada, you need to realize that the royalty rates are different between oil and gas and they are different between different types of gas and different types of oil, and a lot of those are sliding scale type royalties, so it's a fairly complicated situation that can result in that reallocation within Canada.
Brian Singer - Goldman Sachs
Absolutely. Shifting to the Barnett, based on the strong results that we've seen, it would seem like you could reach your 1 bcf a day target a littler earlier than early 2009. Do you feel like you are conservative there? Do you seen any constraints in bringing wells online? Following up on the previous question, what do you think is your capacity to drill in the Barnett in terms of the number of wells per year?
Stephen J. Hadden
You know, Brian, we're very comfortable where we are now. We are at about 32, 33 rigs in the Barnett and that's probably an activity level we would feel good at [inaudible]. At that rate, we drill about 500 wells a year and as we look forward, we're not having -- as a matter of fact, if you looked in the history over this year, our inventory of wells to hook up, for instance, has actually gone down dramatically, [continue] to trend downward. So even at that accelerated rate, because of our very strong midstream presence, the good partnership we have with [CrossTex] and the relationships we have in the field, we've been able to operate at this high level of accelerated activity pretty comfortably.
As we look forward to the bcf a day, we're going to continue to do the right things for value and core [returns] and we're going to want to really take a close look at that as we go in through our budgeting process, which we're in right now. Probably have a little clearer picture of when we get that bcf a day sometime maybe in December or January.
J. Larry Nichols
I might add that the bcf a day is of course not the peak rate that we foresee out there. We are working through on our budget for that process. It was merely the target that we picked which at the time seemed pretty aggressive, but we are clearly way ahead of schedule on meeting that and there is additional growth beyond, after that.
Brian Singer - Goldman Sachs
Thank you.
Our next question comes from Tom Gardner from Simmons & Company.
Tom Gardner - Simmons & Company
Larry, I appreciate your comments concerning the difficulty working your way through the Canadian royalty change.
J. Larry Nichols
We're having trouble hearing you. Can you speak up?
Tom Gardner - Simmons & Company
Sure, I'm sorry. I believe one of you all's microphones cut out as well, but with regard to Canada and the royalty change there, at Jackfish, any idea of the long-term implications to thermal SAGD development in Canada? What oil price is required now for economic return there for SAGD or thermal?
John Richels
As you know, forecasting the oil price that we need in order to optimize the returns from the thermal heavy oil project is really difficult because there are many variables. It's oil price, natural gas price, since we're burning natural gas to create steam. There's the differential, which is an important aspect of it. The cost of [inaudible] and the transportation costs and they all move in different directions.
So if you tell me what the oil price is and we can factor in some of those other variables, then we can come up with that. But that varies a lot, so that's a tough question to answer.
As far as the royalty effect in Canada, I think there's two things that are important to realize. As Larry pointed out and as Steve did, the royalty effect is variable among different kinds of assets in Canada. When we look at our Jackfish 2 project, our initial view of the legislation or the proposed royalty changes doesn't change the returns on that project materially.
Had the royalty review panel recommendations been enacted, it would have, but the way it has now been proposed, it doesn't change it a lot and frankly, the project remains sensitive to capital cost, foreign exchange rate and all of the other things that it previously did.
The good thing about our Jackfish 2 project is we did some things at Jackfish 1 that will create some benefits for Jackfish 2 if we go ahead with it, most notably the access pipeline. So the costs of that access pipeline was really taken into consideration in Jackfish 1 and Jackfish 2 will benefit from it.
So a preliminary look or a preliminary view of it is that that project still looks pretty good and we are still doing all of our engineering and capital analysis of that project and we'll probably make a decision on that in the middle of next year.
Tom Gardner - Simmons & Company
Just using a normal relationship between oil and gas prices, can you bracket the oil price required for the thermal project?
John Richels
You know, what we've used in the past, Tom, is -- it was interesting. When we approved our Jackfish 1 project, when our board took a look at it, oil was $24.50, the differential was $7.50, gas price was roughly $3, and the return was about the same as it was a year ago when we looked at it again and we are kind of doing a look back into the project halfway through the construction of it, and at that time, oil was $63, the differential was $23, and gas was $7 -- had about the same return.
So the relationship that we think is the most important is the relationship between WTI and the Lloyd heavy with a differential about 30% to 33% of WTI. That's the kind of differential that you need and frankly, we think that given that differentials have historically been in that 30% to 33% range, we think that over the long term, that's where they'll settle because either third party processors and refiners will move into that space, or if they don't, the E&P sector will continue to move into that space to get the differential to that level, at which you can make a real good return on the upgrading side.
Tom Gardner - Simmons & Company
How are the economics then of the thermal different from those who are mining the oil sands in Canada? Would you think that the mining is more cost challenged or less?
John Richels
I'm sorry. I couldn't hear that, Tom.
Tom Gardner - Simmons & Company
I'll speak up. There must be some problems with the line here, but just comparing thermal with mining oil sands in Canada, how would the economics compare between the two?
John Richels
Well, they are very different, obviously because they -- I mean, in the mining projects, they're not burning gas, first of all, and so it's a fairly -- it's a completely different equation. Also, all of those mining projects have an upgrader attached and are producing a quality of oil that trades up with or sometimes above WTI, as you know.
Without getting into all of the details, we would take a lot of time on it, they are just very different types of projects.
Tom Gardner - Simmons & Company
One last question, moving over to the Gulf of Mexico regarding the decision on the MMS royalty case. Did Devon agree to the royalty threshold and do you stand to benefit from the recent federal court decision on royalties?
J. Larry Nichols
The federal recent court decision was at the federal district level. It is not a surprising decision at all because if you read the legislation that Congress enacted that provided some royalty relief for the expensive deepwater, there is -- just a plain reading of it shows that there is no real authority for the MMS to do what they tried to do. Therefore, we were not the least bit surprised that Congress, that the federal court dispatched with that case in a fairly short, summary argument. But that's just a district court. We'll wait and see what happens, whether it's appealed and if so what the appellate court rulings are.
I might go back to one -- the comment on heavy oil. Even within steam-assisted gravity drainage projects, there is a wide variety of costs that those projects can incur. They are not all one-cost structure. What we are happy about in Jack is that -- and why we are proceeding on it, is among heavy oil projects, it is a very high quality, low cost project relative to many others.
Tom Gardner - Simmons & Company
Thanks, guys.
Our next question comes from Gil Yang from Citigroup.
Gil Yang - Citigroup
Good morning. Could you talk, Steve, a little bit about the acceleration in the Barnett? Obviously you said that you are drilling more wells, but is there some -- and obviously you've drilled some good wells as well. So how much would you say the acceleration is due to the increased activity level versus the better performance of the wells?
And then, with respect to the better performance, is it not only IPs but are the decline rates doing anything unusually positive for you? Hello?
Sir, your line is open for your question.
Gil Yang - Citigroup
Can you hear me?
Stephen J. Hadden
Can you hear us, Gil?
Gil Yang - Citigroup
No, I can't hear you -- I can barely hear you. I can hear you a little bit.
Stephen J. Hadden
Can you hear us now?
Gil Yang - Citigroup
A little bit.
Stephen J. Hadden
Back on the question on the Barnett Shale, it's actually both things driving the acceleration of our activity. If you remember, back in about a year, year-and-a-half ago, we were running a lot of seismic, getting some good processing, and really going about better characterizing the non-core area so we could get good, solid repeatable results with our wells.
We've also had some process improvements on the drilling side that allowed us to reduce our drilling days, so we actually get more wells per rig. And we are getting better results. That's partly driven by those factors.
So as we've built up our confidence in really being able to deliver a repeatable and improved results on average, we continue to accelerate the program.
An aspect of the drilling activity that we have is the 20-acre in-fill. Now, those 20-acre in-fill wells, I think we started off at about -- estimating about 1.7 bcf per well. When we initially talked about the 20 acres and we were in the pilot stage, I think you saw now we are about 2.1 bcf per well with the larger program that we are drilling.
Again, those are areas where we can even go back into the core and drill those types of wells. So we are seeing improved performance, part of it is reservoir characterization, part of it is the drilling efficiency that we are gaining, and part of it is the integration of that reservoir characterization with our completions.
So those factors are all driving the ramp-up that we have from about the 385 wells to the 500 well activity level.
Gil Yang - Citigroup
Okay, thanks, that's helpful. Have you seen any change in decline rates?
Stephen J. Hadden
No, not materially. We are still looking at about the same exponents. Of course, we continue to monitor performance and that's how we make our reserve estimates and we are pretty happy and comfortable where we are right now with those decline rates that we have.
Gil Yang - Citigroup
Could I just ask the same question for Merganser? What is the -- those wells are outperforming. Is it just greater permeability? Are the reservoirs larger than you thought? What's going on there?
Stephen J. Hadden
I think, as you probably know, Gil, when we drill these wells, we get a lot of static information. In other words, we can look at core information. We can look at log information and of course, our engineering and geologic teams make estimates of what we think those wells can flow and it's basically on a risk basis. To actually see how the well will perform, some of these larger intervals will perform under dynamic flow. You actually have to flow the wells, so we are simply -- I think we are simply just seeing better performance as it relates to our risk estimate of what the permeability and the contribution of the well would be.
Gil Yang - Citigroup
Do you have any indication yet that the reservoirs, that there's no concern that they are compartmentalized in any fashion?
Stephen J. Hadden
It's still too early to really make any other definitive conclusions on that, since it's still early in the production life. We haven't seen anything negative to date.
Gil Yang - Citigroup
Thank you.
Our next question comes from Ross Payne from Wachovia Capital Markets.
Joe Hofer - Wachovia Capital Markets
Hello? Can you hear me? This is Joe Hofer for Ross Payne. I was just following up on the Barnett Shale, just looking at -- what is the average well life you have there? And as you look to potentially deploy additional cash flow to the area, how would you characterize the cost environment that you are facing in the region?
Stephen J. Hadden
Let me take the first issue first. As we look at the life of these wells, these are wells that they initially come on and have a pretty good decline rate initially. Then they go what we call exponential, so they begin to flatten out in their production profile. Some of these wells, you can estimate them to produce for as long as 40 years, so the well lives are very -- can be very, very long.
If you look in terms of our cost environment, we are actually -- we have actually seen the cost of our wells on a year-over-year basis remain flat. Now that's driven by the drilling efficiencies that we've been able to gain and partly by some of the softening in the acceleration of cost escalations that we had seen starting in about early 2005 and through 2006.
From a cost standpoint, we are very comfortable in the environment that we are in. The average well is going to be around $2.7 million to about $3 million a well, and we are getting about 2.5 bcf on average out of each well.
Joe Hofer - Wachovia Capital Markets
Thank you.
Our next question comes from Mark Gilman from Benchmark.
Mark Gilman - The Benchmark Group
Good morning. Can you hear me? A couple of things, Steve, if you wouldn't mind. First, I think when you were discussing Chuck, you talked about a side track hole having run into mechanical problems. What about the original hole?
Stephen J. Hadden
Actually, Mark, that was on the Cortex Bank well, the well we were drilling in the Kaskida unit.
Mark Gilman - The Benchmark Group
I'm sorry, Steve.
Stephen J. Hadden
We were in the process of side-tracking to gain some more reservoir information. The initial well we drilled to its total depth and we are in the process of looking at that information and working through that information.
The side track that we had was a distance away from the original hole. We were trying to get some more reservoir information but we didn't reach the objective and are disappointed with that, but we are still very excited about the Kaskida unit.
Mark Gilman - The Benchmark Group
Okay, with respect, Steve, to Cascade, do you have any numbers in terms of development cost, reserve numbers, and estimated production?
Stephen J. Hadden
No, I don't think we've put that out yet.
Mark Gilman - The Benchmark Group
Okay, Polvo, it looks as if, just on a pro rata basis, that the performance of the first three wells doesn't necessarily get you to what the plateau estimate was. Is that evaluation premature?
Stephen J. Hadden
We think it's premature to draw that conclusion. On the first initial wells, we are drilling in the [macha a] carbonites and those carbonites can be a little bit tricky over time and you can have some variability.
We are still very early in the drilling program. We have seven more wells to drill and we are still sticking by about that 50,000 barrels a day. If that changes once we get a few more wells under our belt, we'll let people know.
Mark Gilman - The Benchmark Group
Okay, and finally with respect to Carthage, if I recall correctly, last conference call you were talking about actually pulling back a little bit in terms of the drilling program, as you better assessed horizontal performance. Now you are moving the rig count back up to 13. What's really changed?
Stephen J. Hadden
Mark, actually in east Texas, the area where we were having problems was looking at the Groesbeck area and we were having some mechanical problems in getting into the full extent of the horizontal section and making sure that we had the completions going off and getting the number of stages of fracs that we wanted to have in the horizontal sections.
We've had a very good effort with a team of people working on that. We actually have had some pretty good results. We brought one well on in the Groesbeck area, came on about 17 million cubic feet a day in the [Nantsugill] Field. So you can probably see us begin to ramp that back up as we move into 2008.
On Carthage, that's been working very well. We have not had any of the mechanical problems and we are continuing to run three horizontal rig lines as we continue to move forward with that horizontal program.
Mark Gilman - The Benchmark Group
Okay, Steve, thanks a lot.
Vince White
Operator, we'll take one more question and then terminate the call.
Thank you. Our last question comes from David Heikkinen from Tudor, Pickering.
David Heikkinen - Tudor, Pickering & Co.
Just a follow-up; volume lifted at Polvo in October?
Stephen J. Hadden
The number was 385,000 barrels.
David Heikkinen - Tudor, Pickering & Co.
And then a schedule for liftings from here forward?
Stephen J. Hadden
Right now, we have another scheduled in December.
David Heikkinen - Tudor, Pickering & Co.
Okay, and then just a reminder on the production sharing contract at ACG, volumes versus oil price and how that works, looking forward at today's oil prices?
Stephen J. Hadden
It's a pretty complex PSC but the bottom line is as the oil prices get higher, we are going to have less cost oil coming to the contractor, and as we reach different payout tranches, as we reach different return tranches, we could have a -- we will have a drop in our nets, so it's affected by oil price both on the net that we take and the cost oil that we recover as prices go higher.
Vince White
If I remember correctly, this is just kind of a broad brush recap, we'll go through two tranche reductions in the next nine months or so that will reduce our net take to about half of the current level, and then we really expect flat production for a long time thereafter.
David Heikkinen - Tudor, Pickering & Co.
That's perfect, Vince. Thank you.
Vince White
Okay, just a quick recap of the quarter; it was an excellent quarter again. Operationally we delivered growth from our core development projects, we continue to see very promising results from our long-term exploration program. Our organic production growth of 10% over last year's third quarter positions us to raise our 2007 production forecast, which of course will in turn lead to higher growth over 2007 over 2006. All of this leads to increases in revenues and earnings and cash flow. Divestiture program moving forward, and we expect to be positioned to fully fund our capital needs, repay debt, and repurchase stock in the year ahead.
In summary, we are very happy with our continued high level performance and think we are very well-positioned for the future. Thanks and we'll talk to you again in February. Take care.
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text:
i laughed so hard at dumbledora
Posted on Sep 3, 2014
Keep in mind: There are only 364 days until the next Halloween! Here are some...794K views buzzfeed.com
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Ancient Aliens guy did it for me.
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Captain Canada gave me a good chuckle.
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text:
Posts Tagged 'UFC on Fox Ratings'
May 6th, 2012 at 8:50 am
TV Ratings Saturday: '48 Hours Mystery' Knocks Out 'UFC on FOX' on Slow Cinco de Mayo
FOX won the night in adults 18-49 with its broadcast of a UFC fight, while CBS was number one in total[Read-More]
April 30th, 2012 at 2:19 pm
Randy Couture & Brian Stann Join UFC on FOX Prefight Coverage Saturday May 5
Once again, UFC ON FOX invades primetime with a two-hour quadruple-header this Saturday, May 5 (8:00-10:00 PM ET) live from Izod Center[Read-More]
January 31st, 2012 at 1:15 pm
UFC On FOX Dominates Primetime Ratings In Key Demos
Saturday night's UFC on FOX event from the United Center in Chicago posted a 2.6/5 national rating/share[Read-More]
January 29th, 2012 at 8:40 am
TV Ratings Saturday: UFC on FOX Paces Easy Win
UFC on FOX 2 cruised to an easy win with adults 18-49.[Read-More]
November 17th, 2011 at 9:01 am
UFC On FOX Debut Delivers On Multiple FOX Sports Media Group Platforms
FUEL TV & FOX Deportes Set Records; FOXSports.com Logs Over 1 Million Streams[Read-More]
November 13th, 2011 at 1:47 pm
UFC on FOX Debut Scores Big - Most-Watched UFC Event Ever
Most Watched Pro Fight Since 2003[Read-More]
November 13th, 2011 at 8:35 am
TV Ratings: Oregon-Stanford, UFC on FOX Top Saturday
ABC looks to win the night with adults 18-49 and total viewers.[Read-More]
November 3rd, 2011 at 12:56 pm
Bell Sounds for UFC on FOX - Velasquez vs. Dos Santos TV Schedule
FOX Sports Broadcasts Heavyweight Championship: Velasquez vs. Dos Santos Live in Primetime on Nov. 12[Read-More]


text:
The controversial proposed supportive housing facility
for Alaska Avenue in Avondale was the main subject of a heated session
of City Council's Budget and Finance Committee today, which resulted in the committee's decision to put the project on hold for two weeks. The committee also announced its intent to allocate $5,000 for an independent mediator, which the city administration will be responsible for finding.
A slew of Avondale community members spoke out in opposition of
the project, while representatives from National Church Residences (NCR), Josh Spring of the Greater Cincinnati Homeless Coalition and Kevin Finn of Strategies to End Homelessness were some of those who publicly expressed support for the project. Many in opposition articulated concern that predominantly poor black neighborhoods such as Avondale are "targeted" for low-income housing projects like these, while supporters insist a spread of misinformation is largely responsible for the tension and that the complex is a necessary step in moving forward with the city's 2008 Homeless to Homes Plan, which explicitly cited NCR as the well-regarded nonprofit developer and manager of supportive housing facilities commissioned to bring a permanent supportive housing facility to the city.
The proposed project, coined Commons at Alaska, would be a 99-unit facility providing residency and supportive services to the area homeless population, particularly those with with severe mental health issues, physical disabilities and histories of alcohol and substance abuse. The project, which gained City Council's official support in February, has recently come under scrutiny from community group Avondale 29, Alaska Avenue residents and other community stakeholders who are fervently expressing public distaste for the facility, which they worry will threaten the safety and revitalization efforts in the neighborhood. CityBeat covered the controversy here.
Councilman Smitherman, who originally voted against Council's support for the project in February, vocally expressed his opposition, and later, Councilman Winburn rescinded his support for the project.
"It appears that maximum citizen participation did not happen... you are having hundreds of people who are not ready yet for this project. So something went wrong somewhere," he said.
Winburn was also the one to announce the motion that asked council to suspend the project for two weeks.
Both sides are expected to once again go in front of the Budget & Finance Committee on a Sept. 30 meeting.
Cincinnati City Council on Friday approved a budget that relies on parking privatization as a means to plug a $34 million budget deficit while also raising property taxes in 2014.
Mayor Mark Mallory opened up the council meeting with a moment of silent prayer for the 27 students and adults killed at an elementary school in Connecticut.
"I want us all to take a moment and put into perspective what we're doing today," he said.
Council voted to increase the property tax by about 24 percent, from 4.6 mills (a mill is equal to one-tenth of a cent) to 5.71 mills. That means Cincinnatians would pay an additional $34 for every $100,000 of their home's value.
The vote reverses a move made last year by conservatives on council, who reduced property taxes.
Council also passed a budget that relies on $21 million from a proposed lease of the city's parking facilities — a deal that is expected to be voted on in March. Of the proposals submitted to the city so far, Cincinnati stands to gain $100 million to $150 million in an upfront payment and a share of the profits over the 30-year lease.
"My concern about balancing this budget with a onetime revenue source by selling our parking system seems to be ill advised," said Independent Councilman Chris Smitherman. "We don't know how council will vote in March … but we have tied not only the budget to this one time revenue source, but we have also tied reciprocity."
Council nixed a plan to eliminate tax reciprocity for people who lived in Cincinnati but worked elsewhere and paid income tax in both cities.
Though the budget doesn't mention parking privatization, council hasn't mentioned other options to close the budget deficit.
If opponents of parking privatization want to keep facilities under city control, they would have to come up with $21 million in revenue elsewhere or make $21 million in cuts.
Councilman P.G. Sittenfeld suggested using casino revenue, cutting travel expenses, downsizing the ratio of managers to workers, sharing services with nearby jurisdictions and downsizing the city's fleet as ways to cut down the budget.
Councilwoman Laure Quinlivan, long an advocate of downsizing the police and fire departments, voted against the property tax increase in protest of what she said was bloated spending on departments that were outpacing population growth.
The budget also requires Cincinnati to accept police and fire recruit classes in 2014, regardless of whether the city gets a federal grant to fund the classes.
The budget also restores the Cincinnati Police Department's mounted patrol, which patrols downtown on horseback. The city will use $105,000 from off-duty detail fees from businesses that hire off-duty officers. Council also voted to start charging those businesses an extra $1.64 on top of the off-duty pay.
Council also voted to shift $50,000 for repairs and upgrades to the Contemporary Arts Center to pay for maintenance and beautification at Washington Park, which is operated by 3CDC.
A group of Northside residents is working to raise $45,000 needed to open the neighborhood's swimming pool this summer, after the facility became the victim of the city's budget cuts.
The Working Families Movement of Northside held a rally March 24 to kickoff its fundraising effort. The group wants the pool at the city-owned McKie Recreation Center on Chase Avenue to open this summer, so neighborhood children — many of whom are low income — can use it during the warm weather months.
After years of dithering and months of debate, Cincinnati City Council narrowly approved a plan Wednesday to make changes to the cash-strapped pension plan for municipal workers. But a local GOP leader is confused about who voted for what.
In hopes of quashing rumors, City Council on Wednesday passed a resolution promising not to use Metro bus money on the streetcar.
The Southwest Ohio Regional Transit authority had voted Tuesday on an agreement with the city that contained a provision saying money from the $42 million transit fund that pays for bus operation can't be used on the streetcar.
The agreement needs to be signed by the city as well in order to release millions of dollars in federal grants to help fund the streetcar. The city has pledged to match those grants with local funds. SORTA wants to make sure the transit fund isn't used for that purpose, but the city wants to have the freedom to use that money on any transportation project.
At least one council member questioned the necessity of passing the resolution.
Chris Seelbach said that nobody on council or in the city administration had proposed or would propose using transit money on the streetcar.
"I don't understand why we would need a provision in any contract that would make us not be able to, when nobody's proposing that we do it," he said.
The resolution has no legal standing preventing council from later coming back and using transit funds for the streetcar, but Qualls said she hoped it put citizens' minds at rest regarding their intentions.
Mayor Mark Mallory on Monday published an editorial in The Enquirer promising that the transit money wouldn't be used for the streetcar.
He went further on Wednesday and said during council's meeting that he as mayor would never approve the use of transit money for the operation of the streetcar.
Council also passed a one-month budget for SORTA, requiring that they come back next month to pass another one.
Councilman Chris Smitherman accused Mallory of trying to flex political muscle in the budget to strong-arm SORTA into taking out the provision disallowing the use of transit funds for the streetcar. He questioned the timing of passing a SORTA budget the day after the transit authority voted to prevent transit funds being used for the streetcar.
Councilman Charlie Winburn — council's sole Republican — walked out of a Budget Committee meeting in advance of the vote.
However Councilwoman Yvette Simpson said it made sense to pass the one-month budget because it forbid SORTA from using taxpayer money to sue the city.
City Solicitor John Curp said it was SORTA's position in the lawsuit that it should be the one deciding how transit funds are used, not the city.
A tri-partisan mix of Cincinnati City Council members are once again reaching across party lines to hold a joint fundraiser — and bragging quite a bit while doing it.
Democrat Jeff Berding, Republican Leslie Ghiz and Charterite Chris Bortz are holding a campaign fundraiser together on Oct. 7. The trio also held a joint fundraiser in 2007 and often receives campaigning advice from Jeff Cramerding, executive director of the Charter Committee, Cincinnati's de facto third political party.
Facing a $33 million deficit for next year, Cincinnati officials are facing some tough choices — including the city manager's recommendation to layoff 44 police officers. Now the public may chime in and offer suggestions.
City Council's Budget and Finance Committee has scheduled four public hearings this month at different locations throughout Cincinnati, with the first set for this week.
The White House announced today that Councilman Chris Seelbach has won the Harvey Milk Champion of Change award, which recognizes 10 community leaders around the nation each year for a commitment to equality and public service.
Seelbach, Cincinnati's first openly gay council member, won the award after he was nominated by the the Gay, Lesbian and Straight Education Network (GLSEN). He will officially receive the award at a ceremony at the White House on Wednesday.
"I am humbled and proud to be recognized by the White House for my efforts on City Council and extremely grateful to the people of Cincinnati for giving me the opportunity to effect positive change in our community. In order to create a city where more people want to live, work and raise a family, we must continue fighting to make sure all people feel welcomed, valued and respected," Seelbach said in a statement.
The award recognizes Seelbach's accomplishments, but it also shows Cincinnati's progress in the past few years.
Seelbach led efforts to extend health benefits to all city employees, including gay couples, and require anyone accepting city funds or subsidies to agree to Cincinnati's non-discrimination policies.
During Seelbach's time in office, the city's police and fire departments created a LGBT liaison.
Most recently, Seelbach co-sponsored a motion that will help avert police and fire layoffs in the fiscal year 2014 budget plan. He also spearheaded "responsible bidder" changes that require bidders on most Metropolitan Sewer District projects to offer apprenticeship programs.
The Harvey Milk Champion of Change award is named after Harvey Milk, who became California's first openly gay elected official when he was elected to the San Francisco Board of Supervisors in 1977. He was assassinated on Nov. 10, 1978 — only 10 months after he was sworn into office.


text: Alfalfa has the highest yield potential of the perennial forage crops grown in Pennsylvania. Yields in excess of 8 tons of dry matter and 4 tons of total digestible nutrients per acre have been obtained regularly. No other perennial crop is equal to alfalfa as feed for livestock, as a cash crop, and as an energy-efficient crop on soils where alfalfa is adapted.


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text:
> Does anyone know of any assistive technologies that directly support Ruby > annotations in XHTML? I'm not sure that even any mainstream browsers support it properly, at least in the full form that allows overlapping phrases in the different texts. IE 5.5 certainly doesn't; I had to resort to tables.Received on Friday, 27 September 2002 02:52:28 GMT
This archive was generated by hypermail 2.2.0+W3C-0.50 : Tuesday, 19 July 2011 18:14:06 GMT


text:
-Re: Insight on why distcp becomes slower when adding nodemanager
Not sure.
Lots of things can effect your throughput.
Networking is my first guess. Which is why I asked about the number of times you've run the same test to see if there is a wide variation in timings.
On Oct 31, 2012, at 7:37 AM, Alexandre Fouche <[EMAIL PROTECTED]> wrote:
> These instances have no swap. I tried 5 or 6 times in a row, and modified the yarn.nodemanager.resource.memory-mb but it did not help. Later on, i'll replace the openjdk with the Oracle java SE 1.6.31 to see if it improves overall performance.
> Now i am running everything on medium instances for prototyping, and while this is better, i still find it abusively slow. Maybe bad hadoop performance on less than xlarge memory instances is to be expected on EC2 ?
> --
> Alexandre Fouche
> Lead operations engineer, cloud architect
> http://www.cleverscale.com | @cleverscale
> Sent with Sparrow
> On Monday 29 October 2012 at 20:04, Michael Segel wrote:
>> how many times did you test it?
>> need to rule out aberrations.
>> On Oct 29, 2012, at 11:30 AM, Harsh J <[EMAIL PROTECTED]> wrote:
>>> On your second low-memory NM instance, did you ensure to lower the
>>> yarn.nodemanager.resource.memory-mb property specifically to avoid
>>> swapping due to excessive resource grants? The default offered is 8 GB
>>> (>> 1.7 GB you have).
>>> On Mon, Oct 29, 2012 at 8:42 PM, Alexandre Fouche
>>> <[EMAIL PROTECTED]> wrote:
>>>> Hi,
>>>> Can someone give some insight on why a "distcp" of 600 files of a few
>>>> hundred bytes from s3n:// to local hdfs is taking 46s when using a
>>>> yarn-nodemanager EC2 instance with 16GB memory (which by the way i think is
>>>> jokingly long), and taking 3mn30s when adding a second yarn-nodemanager (a
>>>> small instance with 1.7GB memory) ?
>>>> I would have expected it to be a bit faster, not 5xlonger !
>>>> I have the same issue when i stop the small instance nodemanager and restart
>>>> it to join the processing after the big nodemanager instance was already
>>>> submitted the job.
>>>> I am using Cloudera latest Yarn+HDFS on Amazon (rebranded Centos 6)
>>>> #Staging 14:58:04 root@datanode2:hadoop-yarn: rpm -qa |grep hadoop
>>>> hadoop-hdfs-datanode-2.0.0+545-1.cdh4.1.1.p0.5.el6.x86_64
>>>> hadoop-mapreduce-2.0.0+545-1.cdh4.1.1.p0.5.el6.x86_64
>>>> hadoop-0.20-mapreduce-0.20.2+1261-1.cdh4.1.1.p0.4.el6.x86_64
>>>> hadoop-yarn-nodemanager-2.0.0+545-1.cdh4.1.1.p0.5.el6.x86_64
>>>> hadoop-mapreduce-historyserver-2.0.0+545-1.cdh4.1.1.p0.5.el6.x86_64
>>>> hadoop-hdfs-2.0.0+545-1.cdh4.1.1.p0.5.el6.x86_64
>>>> hadoop-client-2.0.0+545-1.cdh4.1.1.p0.5.el6.x86_64
>>>> hadoop-2.0.0+545-1.cdh4.1.1.p0.5.el6.x86_64
>>>> hadoop-yarn-2.0.0+545-1.cdh4.1.1.p0.5.el6.x86_64
>>>> #Staging 14:39:51 root@resourcemanager:hadoop-yarn:
>>>> HADOOP_MAPRED_HOME=/usr/lib/hadoop-mapreduce time hadoop distcp -overwrite
>>>> s3n://xxx:[EMAIL PROTECTED]ev/* hdfs:///tmp/something/a
>>>> 12/10/29 14:40:12 INFO tools.DistCp: Input Options:
>>>> DistCpOptions{atomicCommit=false, syncFolder=false, deleteMissing=false,
>>>> ignoreFailures=false, maxMaps=20, sslConfigurationFile='null',
>>>> copyStrategy='uniformsize', sourceFileListing=null,
>>>> sourcePaths=[s3n://xxx:[EMAIL PROTECTED]ev/*],
>>>> targetPath=hdfs:/tmp/something/a}
>>>> 12/10/29 14:40:18 WARN conf.Configuration: io.sort.mb is deprecated.
>>>> Instead, use mapreduce.task.io.sort.mb
>>>> 12/10/29 14:40:18 WARN conf.Configuration: io.sort.factor is deprecated.
>>>> Instead, use mapreduce.task.io.sort.factor
>>>> 12/10/29 14:40:19 INFO mapreduce.JobSubmitter: number of splits:15
>>>> 12/10/29 14:40:19 WARN conf.Configuration: mapred.jar is deprecated.
>>>> Instead, use mapreduce.job.jar
>>>> 12/10/29 14:40:19 WARN conf.Configuration:
>>>> mapred.map.tasks.speculative.execution is deprecated. Instead, use
>>>> mapreduce.map.speculative
>>>> 12/10/29 14:40:19 WARN conf.Configuration: mapred.reduce.tasks is
>>>> deprecated. Instead, use mapreduce.job.reduces