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Nexen, Inc (NXY)
Q3 2010 Earnings Call
October 28, 2010 9:00 a.m. ET
Kevin Reinhart - EVP & CFO
Marvin Romanow - President & CEO
Andrew Potter - CIBC World Markets
Greg Pardy – RBC Capital Markets
Bob Morris - Citigroup/Smith Barney
Mark Polak - Scotia Capital
Arjun Murti – Goldman Sachs
George Tunula – UBS
Brian Dutton– Credit Suisse
Brandon Biago – Treaty Oak
Menno Hulshof – TD Securities
Chip Rewey – CRM
Good morning, ladies and gentlemen. Welcome to the Nexen Third Quarter 2010 Conference Call.
Previous Statements by NXY
» Nexen Inc. Q2 2010 Earnings Conference Call
» Nexen Inc. Q1 2010 Earnings Conference Call Transcript
» Nexen Inc. Q2 2008 Earnings Call Transcript
Good morning and thanks for joining us today. With me today is Marvin Romanow, President and CEO, and Gary Nieuwenburg, Executive Vice President of Canadian Operations.
Before I get started, just to caution that certain statements that I make this morning are forward-looking statements. I refer you to our press release of today for more information regarding those statements. And also refer you to our 10-K and 10-Q for a description of the risk factors.
Following my comments this morning, there will be some time for questions.
We continue to make significant progress across all of our areas in our
portfolio. My plan this morning is to go over the highlights of this progress, and then I'll touch on our production volumes and the significant production adds we have coming over the next 24 months.
Let me start with Long Lake. The bitumen production volumes continued to rise following the turnaround that we undertook last fall. We're pleased with how quickly we got back on the ramp-up curve once we completed the changes to the water softening system last year.
Following the steady ramp up that we've had throughout this year, our pace temporarily slowed during August and September as we took down some of our best-producing wells for ESP upsizes, and to complete asset jobs on other ones. In addition, the steam generation was temporarily interrupted by upgrader shutdowns and power outages.
Now that these are behind us, we're producing record levels of steam and in response,
bitumen production is over 31,500 barrels per day; and that's gross. This is double the levels of the start of the year.
In addition, the number of wells producing at average design rates has increased from ten at the beginning of the year to 24 today. In light of the lost time from the recent disruptions, our ramp-up progress has been delayed by a few months.
As we've described before, we continue to pursue inexpensive ways to add bitumen. These initiatives include bringing on the remaining 13 wells to SAGD production, optimizing all producing wells, developing two additional well pads, and adding two more once-through steam generators that can use the available water treating capacity that we have there.
These actions require little incremental capital and the economics are quite compelling.
Operating costs here continue to trend as we expect, and we're on track to be in the $25- to-$30 range per barrel once we are at full capacity.
As production volumes grow and yields improve we are approaching cash flow break even and we expect Long Lake to generate positive cash flow here shortly.
Oil sands is a key part of our future and we are moving forward to capture the value of the billions of barrels of bitumen resource that we own.
Earlier this year we described our plans to sequence the development of Phase 2 differently than Phase 1.
We'll start with smaller SAGD stages of about 40,000 barrels per day each. And then we'll follow with upgrading at some time after we get those SAGD projects ramped up.
This approach has many benefits; it simplifies the SAGD ramp-up process, there's less stress on material, equipment and labor markets during the construction, it improves our capital efficiency since 2/3s of the capital is in the upgrader. And it provides flexibility on when to move to upgrading based on the economic conditions.
The front-end engineering work is advancing on Phase 2 as we speak.
Turning to shale gas, we're making great progress on our Horn River acreage. We're executing very well, and costs continue to drop.
This past winter, we successfully drilled an eight-well pad. Compared to our previous program, these wells were drilled in 35% fewer days and they were almost twice as long.
We recently completed fracing these wells, and we did this at an industry-leading pace of 3 1/2 fracs per day with 100% frac success rate.
We're currently production testing these wells and expect to reach peak rates of 50 million cubic feet a day this winter. We plan to follow up this successful progress with a nine-well pad that would start drilling this winter. The wells would be fraced and completed next summer with
first production in the fourth quarter of 2011.
This program allows us to advance our Horn River play while we progress our plans for an 18-well pad to be drilled next winter with first production to follow in late 2012.
Compared to other North American shale gas plays, Horn River is top quartile. It has a long land-tenure system with no need to drill and produce to hold the land. It has low royalties and excellent resource density and fracability. So we expect to be able to earn a 10% rate of return with gas prices at above $4 per MCF.
Given the success we've been having in this area, we more than doubled our acreage position in North East British Columbia earlier in the summer, and we are now one of the top acreage holders in the area.
We estimate that the 90,000 acres we have in the Horn River Basin contain three to six TCF of recoverable contingent resource.
With a total acreage position, that is now more than three times that size, the resource potential of our shale gas lands is even more significant now.
Given the progress that we're making here, and the additional land we have acquired at Cordova and Liard, we are in the process of updating our total resource estimates and expect to disclose them in the next month or so.