Chesapeake Energy Corp (CHK) 2012 Q2 法說會逐字稿

Good day and welcome, everyone, to the Chesapeake Energy 2012 second-quarter earnings results conference call.

Today's conference is being recorded.

At this time I would like to turn the conference over to Jeff Mobley.

Please go ahead, sir.

Good morning and thank you for joining our conference call today.

I would like to introduce the members of the management team that are on the call this morning.

We have Aubrey McClendon, our Chief Executive Officer; Nick Dell'Osso, our Chief Financial Officer; Steve Dixon, our Chief Operating Officer; John Kilgallon and Gary Clark from the Investor Relations team.

And this is Jeff Mobley speaking.

Following the comments of the management team we will take your questions this morning.

As I'm sure you can understand, we are not going to be able to comment on matters that are subject to litigation or other inquiries.

As usual, our call will last one hour and now I will turn the call over to Aubrey.

Good morning and thank you for joining us today.

Despite experiencing the lowest natural gas prices in over 10 years during the 2012 second quarter, we are pleased with the Company's performance during this challenging time for our industry.

For example, our production surged ahead by 25% year over year and 4% sequentially.

However, had it not been for our 330 million per day gas curtailment during the quarter, Chesapeake's production would have actually been up a remarkable 36% year over year.

These production increases are obviously impressive, but they are especially so for a company as large as ours.

Most importantly, our oil production growth has really taken off.

Starting from a base of 26,700 barrels per day in January 2010; in the past 10 quarters we have increased our oil production by 201% to 80,500 barrels per day.

Our natural gas liquids production growth has been very strong too, growing from 10,600 barrels per day in January 2010 to nearly 50,000 barrels per day in the second quarter, an increase of 370%.

Taken together, Chesapeake's total liquids production of 130,200 barrels per day has now risen to 21% of our total production mix and we expect this percentage to continue trending upward to 35% of total production by 2015.

In addition, our second-quarter liquids production was up 65% year over year and 15% sequentially.

Looking across the industry, our year-over-year liquids production growth is the third best in the industry on an absolute basis and on a percentage basis it is the second best.

Chesapeake is now the 11th largest liquids producer in the US, and we hope by 2015 to be knocking on the door of the top-five liquids producers in the US.

You may recall that in 2010 when we had a very modest liquids production of about 30,000 barrels per day we set a goal of reaching an exit rate of 250,000 barrels per day of liquids production in 2015.

In 2011 we accelerated that goal to be an average of 250,000 barrels per day during all of 2015, rather than just an exit rate.

Given that Chesapeake's production already exceeds 50% of our objective, it appears our ambitious target can likely be exceeded if present trends continue.

Turning to gas production, I hope you noticed that we are now projecting a decline in Chesapeake's gas production of approximately 7% in 2013.

This will bring to an end our likely unprecedented public company record of 23 consecutive years of gas production growth, which has taken Chesapeake's gas production from 10 million cubic feet per day in 1993 to more than 300 times that level currently and in the process has helped transform the US gas market.

Moreover, Chesapeake's projected 7% downward trend in gas production for 2013 will likely continue beyond that year until such time as gas prices rise to levels that make returns from drilling in our gas plays competitive with the returns available from drilling in our liquids plays.

In fact, by year-end 2013 we expect Chesapeake's gas production rate to have declined by 430 million cubic feet per day, or 14%, from our peak rate of 3.4 Bcf per day in 2012.

Including the production of our non-operating working interest owners and our royalty owners, the total decline in Chesapeake-operated US gas production is likely to be around 800 million to 900 million cubic feet of gas per day.

Based on the substantial gas drilling rig count decline that last week reached a 12-year low and an embedded high decline rate in the country's existing natural gas production base, we believe it won't be long until the EIA-914 data shows US gas production on a confirmed downward trend.

We believe this trend of declining gas production could continue as long as gas prices do not permit gas producers to earn an attractive return on the investments necessary to finish developing the big new unconventional gas fields that have led to America's greatly increased gas production over the past five years.

In addition, the gas storage overhang is decreasing by an average of 2 to 4 Bcf per day each week.

If this trend continues and we experience a normal winter, the US gas market could reverse its 900 Bcf year-over-year storage surplus established in April 2012 and reach a potential gas storage deficit in April 2013 of up to 900 Bcf.

As a result of this potential storage reversal, rising demand for natural gas across the economy, and likely production declines from many gas producers as they continue shifting their CapEx towards more profitable liquids production, we expect gas markets to look very different during the next few years than they have looked during the past six months.

Chesapeake's management believes that based on the foregoing the US is likely in the very early stages of a multi-year upcycle in gas market fundamentals and clear evidence of this new upcycle is readily apparent.

Gas prices have bounced strongly upward from the $1.84 level set on April 20, which we believe marks the low in the four-year downcycle that started in 2008.

Now I would like to return to Chesapeake's operational performance.

During the first half of 2012 we added proved reserves of 4.2 Tcfe through the drillbit, or the equivalent of about 700 million barrels of oil equivalent, at a very attractive finding and development cost of only $1.14 per Mcfe, or $6.84 per boe.

Using current NYMEX strip pricing these added proved reserves add $10.2 billion of PV-10 value.

So to drive this important point home, I would like to reiterate that in the first half of 2012 we invested $4.7 billion in our drilling programs and from that drilling we created $10.2 billion of future PV-10 proved reserve value.

That means that for every $1 that we invested in drilling in the first half of the year we found $2.17 of PV-10 proved reserve value.

In total, that is a margin between finding costs and PV-10 value of $5.5 billion, or about $7 per share of net asset value creation for our shareholders.

And that is $7 per share of value creation in just the first six months of 2012.

We believe that is an exceptional performance, especially during a six-month period of very low gas prices.

I believe it is this metric above all others that showcases the effectiveness of Chesapeake's drilling machine at converting large blocks of undeveloped leasehold into very large quantities of proved reserves.

We believe Chesapeake's performance can improve even further from this very high level as we progress from operations designed for new asset identification and capture to a more manufacturing-like operations approach designed to maximize efficiency and returns as we shift more fully into harvest mode.

We are now able to increasingly focus on developing just the core of the core areas of our plays, taking advantage of first well infrastructure, benefiting from economies of scale, and development mode drilling efficiencies, and also capitalizing on our substantial investments in human resources, experience, and technology.

In doing so we are now projecting to reduce our capital expenditures from 2012 to 2013 by $6 billion, or about 45%.

Clearly, we have listened to investor feedback on this important topic.

We also enjoyed a very successful quarter in advancing our asset sales.

As you know, our planned asset sales for the year are designed to help us afford to increase our liquids production, tighten the focus on our core assets, while also reducing our long-term debt by 25% from year-end 2010.

To achieve this important shift to a closer balance of liquids and natural gas production we have invested billions of dollars over the last few years.

While low gas prices have made this shift to liquids-focused production more difficult to achieve, those falling gas prices also made the shift more urgent.

However, we have now captured what we set out to capture in terms of our resource base.

This will now permit Chesapeake to be in asset harvest mode for a very long time.

As a result, we anticipate much higher returns from our portfolio than you have seen in the past.

With regard to specific asset sale information, during the second quarter we closed on $2.7 billion of asset sales bringing our total for the first half of the year to $4.7 billion.

During the third quarter we anticipate entering into asset sales agreements of approximately $7 billion, which would bring our asset sales to approximately $11.7 billion year-to-date.

We continue to identify additional assets to sell during the fourth quarter that will help meet our updated goal of $13 billion to $14 billion in assets sales for 2012.

In addition, we are planning $4 billion to $5 billion of assets sales in 2013.

So by year-end 2013 I believe we will have completed sufficient asset sales to have met our objectives and to have transformed Chesapeake by shifting our production mix to more profitable liquids, tightening the focus on our areas where we have industry-leading scale and expertise, reducing our debt by 25%, reducing our total CapEx by $6 billion, slashing leasehold spending and at the same time increasing our returns while continuing to generate production growth.

When we have completed our asset sales we anticipate Chesapeake will still retain core positions in 10 plays, which we believe will be 10 of the 15 best plays in the country.

In each of those 10 plays Chesapeake will be either the number one or number two producer.

We are not aware of another company that will be number one or number two in more than three of these 15 best plays.

It has certainly been a long and arduous journey during the past seven years to build and asset base of this uniquely high quality, but it was a very important and worthwhile endeavor to pursue at a pivotal time in the history of our industry.

We have appreciated investors' support and their capital during this time which enabled us to complete this important phase in our company's history and position Chesapeake very favorably for the years ahead.

I would also like to express appreciation to my 13,000 Chesapeake colleagues who have continued to work hard to meet all of the challenges of the past few months.

Their talent and dedication will certainly be critical in helping Chesapeake reach its goals in the years ahead.

Finally, as you know, a lot has changed since our 2012 first-quarter conference call three months ago.

I would like to especially thank our new independent Board Chairman, Mr. Archie Dunham, and our newly reconstituted Board of Directors for jumping right in to get up to speed about our strategy and operations.

Their involvement should enable us to further sharpen our focus on driving higher returns from Chesapeake's assets while maintaining a strong balance sheet.

Without a doubt, these efforts should lead to improved operational and financial performance for years to come.

I will now turn the call over to Nick.

Thanks, Aubrey.

It was a very good quarter operationally and I am particularly pleased to highlight our strong production results.

We produced 3.8 Bcfe per day, an overall sequential increase of 4%, but more importantly we achieved a 15% sequential increase in liquids production.

This quarter we began reporting our oil and NGLs separately now that our NGL production and reserves have increased to a material level.

I would like to highlight the liquids production volumes for the second quarter was about 62% oil and 38% NGLs, and also that our rate of growth in oil production had substantially outpaced our growth in NGL production over the past year.

We are also very pleased with the continued strength in our oil price realizations, which were 96% of NYMEX before the affects of hedging this quarter.

These high realizations are a direct result of the hard work by our subsidiary, Oilfield Trucking Solutions, in the Eagle Ford as well as enhanced pipeline connectivity out of the basin, both of which contribute greatly to robust overall pricing.

Thanks to strong growth in the Eagle Ford 45% of our companywide net oil production during the quarter is now sold at a Louisiana Light Sweet correlated price versus 0% in the year-ago quarter.

Looking ahead to 2013 we are currently forecasting flat year-over-year oil differentials, but we do see potential for these to improve further.

You will see in our results that like many of our peers we reported challenging NGL price realizations.

However, we believe these realizations are bottoming and expect them to improve moderately for a couple of reasons.

First, we currently sell 50% of our NGLs at Conway.

In 2013 we will access Mont Belvieu pricing for a portion of those volumes based on new pipelines and resulting basin compression.

Second, industry-wide rejection of ethane has kicked in, which should begin to ease the ethane oversupply situation and prompt a modest increase in pricing.

Finally, more propane export capacity is being developed along the Gulf Coast and East Coast, which should begin to ease the supply overhang before year-end.

Coupled with the traditional seasonal balance associated with the onset of colder weather, these factors should lead to better propane prices in the fourth quarter.

So we expect one more quarter of very weak NGL realizations and then some relief in the fourth quarter, both of which we have built into our guidance.

As a result of our strong production performance in Q2, we are increasing our production guidance for both 2012 and 2013 by approximately 110 Bcfe and 90 Bcfe in each year, respectively.

After adjusting for the changes in expected production decreases associated with asset sales, which are detailed in our outlook, and adjusting for reduced 2012 curtailments, our organic production guidance has been increased by approximately 75 Bcfe, or 6%, in 2012 and approximately 140 Bcfe, or 10%, in 2013.

On the CapEx front we are increasing our 2012 drilling and completion CapEx guidance by about 6.5% to $8 billion to $8.5 billion.

This is purely related to the high activity levels from year-end 2011 and the first half of 2012 that are still working through the system as we ramp down in most of our plays.

However, as expected, we have seen our month-over-month spending begin to decline in both June and July as our rig count has dropped pretty dramatically, which Steve will detail for you shortly.

On the leasehold side we are increasing our 2012 estimated spend to $2 billion, but lowering our 2013 estimated spend to $400 million.

Given that about $1.3 billion leasehold spend year-to-date, you can see that second half of 2012 spend is considerably less than the first half and the ramp down in activity is complete.

I might also add that approximately 50% of this leasehold spend was wrapping up our Utica leasehold acquisition efforts and the Mid-Continent contributed another 25% of the leasehold spend this year.

Even more importantly, our 2013 drilling and completion CapEx has been reduced by $750 million to a range of $5.75 billion to $6.25 billion, reflecting rig count reductions and efficiency gains from our core of the core strategy.

I am very pleased to point out that even with drilling CapEx about $2 billion lower in 2013 than in 2012 we are actually raising our 2013 production guidance by 7% due to strong performance in our liquids plays.

Also, very notable in our 2013 CapEx spending forecasts is the significant decrease from our prior outlook of $1.275 billion as a result of the sale of our midstream business.

Total decrease in 2013 spending relative to our May 1 outlook is over $2.1 billion.

Again, we have been able to increase our production guidance despite the significant CapEx reduction.

Our adjusted EPS for the quarter of $0.06 per share was negatively impacted by approximately $0.06 per share due to the effect of higher DD&A related to price-related revisions primarily from Barnett, Haynesville PUD eliminations.

If gas prices follow the current NYMEX strip, these reserves may be eligible to come back on our books in 2013 subject to our forecasted pace of drilling in those areas.

I would like to point out that we did not have a ceiling test write-down this quarter as we have built a full-cost pool cushion as a result of our low finding costs and profitable asset sales in recent years.

As a full-cost company we are not able to recognize gains on our income statement when we sell E&P assets and are instead required to apply the asset sale proceeds to the decrease of our full-cost pool, resulting in lower DD&A rates over time.

We do expect to have a ceiling test write-down in Q3 as we substitute three more months of low 2012 gas price months to the trailing 12-month SEC calculation.

I would like to note however, that at the 10-year average strip pricing our PV-10 is 5.4 billion higher than under the SEC methodology as shown on page five of our earnings release.

You will also see in our release that we have added significant gas hedges for the second half of 2012 at an average price of $3.03 per Mmbtu.

While we don't view the current natural gas price strip as long-term sustainable, we did see this as an opportunity to take a significant amount of fall shoulder season risk off the table.

We remain quite bullish on gas prices in 2013 and beyond and accordingly have begun to reduce some of our previously written out-year natural gas call positions.

We are making great progress on our asset sales and are looking forward to having more to share with investors in the next month or so.

We will use the proceeds from our Permian and midstream sales to retire the $4 billion term loan we put in place in May and planned to apply the remaining proceeds from these sales and others to any outstanding balances on our $4 billion corporate revolver which was 100% undrawn at June 30.

We also have a very favorable call feature on the $1.3 billion notes we issued in February of this year, which allows us to call the notes at par between November 15 of this year and March 15 of 2013.

Our goal is to exit 2012 with no more than $9.5 billion in long-term debt which implies having nothing drawn under our $4 billion corporate revolving credit facility.

Going into 2013 this revolver liquidity, plus the discretionary liquidity associated with the $1.3 billion of callable notes, would give us $5.3 billion of available liquidity irrespective of the amount of our 2013 asset sales.

To be clear, we intend to complete our 2013 projected asset sales of $4.25 billion to $5 billion and finish 2013 with no incremental net debt.

However, we do not expect to be dependent on the 2013 asset sale program to meet our liquidity needs.

Lastly, before turning the call over to Steve I wanted to point out that a few weeks ago we posted an appendix to our investor presentation that included more detail on our VPPs, midstream commitments, and drilling and compression sale leasebacks.

There has been much written about these items in the past few months and we wanted to make sure the facts were disclosed and available for all to analyze.

Please let us know if you have any questions regarding these new slides.

Steve?

Thanks, Nick.

I am very pleased and impressed with our operational performance and I'm very proud of the efforts and the results that our team at Chesapeake has been able to deliver for our shareholders this year.

As Nick just outlined, our strong liquids production growth during the second quarter has prompted us to raise our forward liquids production guidance outlook for the remainder of 2012 and 2013 to an average of 135,000 barrels per day and 170,000 barrels per day, respectively.

These are increases of 12% and 9%, respectively, and are net of volumes associated with projected asset sales.

I would also like to point out that the majority of this growth will be in our oil production versus our NGL production.

We mentioned in our last quarterly call that in response to low natural gas prices we would reduce drilling in our dry gas plays from 47 rigs at the beginning of 2012 to just 11 rigs by year-end.

We have accomplished this goal and now plan to further reduce this amount to 8 rigs at year-end.

At our high-water mark back in March of 2010 we were drilling with 104 gas rigs.

As you might imagine, this will have profound impact on our gas production.

In 2013 we are now projecting a 7% decline in gas production.

Moving on to cost side of our business, we are beginning to realize significant benefits from lower service costs and rising drilling efficiencies as we optimize our activity levels and move more fully into harvest mode.

Consequently, we plan to drill the same number of net wells with fewer rigs operating and have accordingly reduced our projected year-end 2012 liquids rig count from 115 down to 93.

In the second half of 2012 and in 2013 we plan to spend approximately 85% of our drilling and completion capital in oil and liquids plays.

I would also like to point out that I am especially proud of our operating cost control efforts as we have ramped up our liquids production, but yet we still expect per unit production expenses to remain relatively flat at approximately $1 per Mcfe through 2013.

Moving on to specific plays, I would like to start with the Eagle Ford shale.

Subtracting 28% of our capital in 2012 and 33% in 2013 second-quarter net production from the Eagle Ford was 36,300 boe per day, which is a 58% increase over the first quarter and a 615% year over year.

During the quarter we connected 121 wells or nearly one-third of our 337 total producing wells in the Eagle Ford.

Importantly, at June 30 we had 220 wells at various stages of completion of pipeline connection.

This provides a foundation for strong liquids growth runway into the quarters ahead.

In addition to rapid growth and robust activity levels, the Eagle Ford is particularly exciting as we have experienced higher per well initial production rates, an oilier production mix, and lower well cost.

During the second quarter 31% of the wells we placed on production had peak rates in excess of 1,000 boe per day.

Furthermore, 91% of our wells placed in production had peak rates in excess of 500 barrels per day, and that is up from 81% in the same quarter, one year ago.

Approximately 66% of our Eagle Ford production volumes during the quarter were oil as compared to 57% in the first quarter.

This is an important increase given the much higher margins associated with oil production relative to gas and NGLs.

These metrics help demonstrate that Chesapeake's Eagle Ford acreage is located in the core of the very best oil acreage in the western portion of the play.

With regard to cost control, our completed well costs in the Eagle Ford are tracking 15% lower than a year ago and we expect further reductions in the months ahead.

This will enable us to target year-end exit rate of only 25 rigs, down from 28 currently, and from a peak of 35 rigs three months ago.

Turning to the Anadarko Basin, we have four key plays that provide a very strong base for continued liquids growth production -- the Mississippi Lime, the Granite Wash, the Cleveland, and the Tonkawa.

At June 30 we had 51 rigs running in these plays and combined second-quarter net production of 88,100 boe per day.

Production mix in these four plays consists of 34% oil, 23% NGLs, and 43% gas.

Looking ahead to 2013, we anticipate these plays will comprise approximately 19% of our total production and that oil will continue to rise as a percentage of the production strength.

As Nick mentioned in his remarks, we are working with others to jointly obtain infrastructure enhancements, such as our NGL production, from these areas will access more favorable Mont Belvieu pricing.

Also in the Anadarko Basin, I would like to highlight our emerging Hogshooter Wash play, which could become a meaningful contributor to our oil volumes over the next few years.

Our Thurman Horn 406H well, which we first announced on June 1, has produced nearly 330,000 boe in its first 60 days on production, almost 80% which is oil.

We are pleased to report this well has already generated over $16 million of gross revenue that paid out in one month.

We believe this has been the best onshore well in America the past two months and may continue to grow, even though its production starts to decline from extraordinary levels in the past few months.

An offset well, the Thurmond Horn 4010H, is now drilling ahead and will provide valuable information from this immediate area and its ultimate recoverability.

Chesapeake holds approximately 30,000 acres prospective in the Hogshooter Wash and has identified 60 potential drilling locations.

11 wells are scheduled to spud in the play before the end of 2012, so stay tuned for more updates.

In addition, we believe the liquids rich Missouri Wash will also emerge as a key play for us out in the Texas Panhandle later this year and in 2013.

In the Powder River Niobrara play we have finally cracked the code with numerous recent wells drilled in our newly identified over-pressured, liquids-rich core area of 100,000 net acres delivering outstanding flow rates of more than 1,500 boe per day.

However, due to limited gas take away infrastructure and processing facilities, production growth on the Powder River Basin has not yet begun in earnest, but we expect to see this area take off in 2013 and beyond as we have identified over 1,000 potential locations in the Niobrara core.

In addition, we believe a significant portion of our overall 350,000 net acres of Powder River leasehold will be prospective for other formations, such as the Teapot, Parkman, Sussex, Shannon, and Frontier formations.

We have eight operated rigs currently running and plan to ramp this up to 11 by year-end.

I might add that CNOOC is paying for 67% of our drilling costs in the Powder River Basin and we project that that will remain through the end of 2014 as we earn our remaining drill-and-carry which was approximately $520 million as of June 30.

I will now turn to the Utica Shale in Ohio where we are the leading leasehold owner, driller, and producer with 12 operated rigs currently working to evaluate our 1 million-plus net acres.

We continue to delineate the wet gas window as well as HBP some acreage in the highly productive dry gas window towards the east.

The Utica oil window is being tested by Chesapeake on both an operated and non-operated basis, as well as by other industry competitors that are beginning to report results.

Well completions are progressing at a quickening pace in the Utica as much-needed midstream infrastructure begins to come into service.

We've recently submitted a number of new wells to the Ohio DNR which will soon be posted on their website.

We remain very pleased with our results to date in the Utica.

To conclude my remarks, I hope our report today makes it abundantly clear that we believe liquids-rich plays are working exceptionally well and we expect drilling and completions costs to come down further while our per well operating costs remain constant.

The Eagle Ford is our most active play, continues to attract the largest amount of our capital, while our bread and butter liquids plays in the Anadarko Basin, the Mississippi Lime, Granite Wash, Cleveland, and Tonkawa continue to contribute to a steady upward trend.

In addition, the Niobrara and the Powder River Basin should become a significant contributor to our liquids growth, and we are looking forward to strong contributions from the Utica in 2013 and beyond.

Of course, we retain exceptional upside, optionality, and leverage to potential 2013 rebound of natural gas prices that Aubrey outlined in his opening remarks.

As Nick detailed in the outset, our corporate production guidance takes into account all production losses from our expected 2012 and 2013 asset sales, and also reflects our substantially lower capital budget for 2013, which is predicated on the reduction in average rig count from 131 down to just 100.

Despite these adjustments, our strong underlying property base and enviable leasehold position still enables us to project positive production growth for 2013.

Operator, we will now take questions.

(Operator Instructions) Brian Singer, Goldman Sachs.

Good morning.

I wanted to see if you could connect a few dots with regards to the production and asset sales guidance that you revised.

It seems like you expect less proceeds from asset sales in aggregate in 2012 to 2013, a greater negative impact on ongoing production resulting from these asset sales but as you highlighted both oil and gas production guidance was taken higher.

In the interest of trying to determine how much of this change in guidance is driven by performance versus restructuring, can you just add a little bit of color on the moving pieces please?

Sure, Brian.

When you talked about less asset sale proceeds, I think what you are really pointing to is that we took the VPP off a while ago.

The increase in production relative to performance and unrelated to asset sales is about 140 Bcfe in 2013.

Does that answer your question?

Yes.

Can you break down whether or not both oil and gas was impacted?

I know you highlighted the Eagle Ford in Steve's comments, but are there major drivers on the oil side versus the gas side?

There are and so it is approximately 50/50 of that would be gas versus liquids.

Then the oil and NGL split would be as related to our base production, so a little better than 60/40 to the oil.

Okay.

Then you highlighted your Eagle Ford backlog; you've got a big backlog in the Marcellus.

What are your expectations for how this backlog will change and what is baked into that guidance for 2013?

Brian, this is Steve.

We are working part of that off and part of that was our overspend on capital.

Running quite a few frac crews in the Eagle Ford to catch that up as well as Marcellus.

Got it.

So do you expect that backlog to be eliminated by the end of next year, is that what is baked in?

A good portion of our Eagle Ford backlog is normal course so we don't expect it to be eliminated and the Marcellus backlog will stay with us for some time as we are doing some appropriate backlog reduction there, but we are not exactly racing.

Thanks.

If I could ask one more, you highlighted in the release the expectation for maybe a greater strategic update with third-quarter results.

Can you just talk to whether you think that will be dramatically different versus this latest change in 2013?

I do not expect it to be dramatically different, no.

Thank you.

David Kistler, Simmons Co.

Good morning.

Just following up on Brian real quick, can you break out just specifically the Eagle Ford VPP and the implications that had on production guidance for 2012 and for 2013?

The VPP in and of itself was projected into our 2012 and 2013 production guidance.

When we pulled it out, we had a reduction or an add-back of about 30 Bcfe in 2012.

Again about 50% of that is -- sorry, I misspoke earlier when I gave the number to Brian.

About 50% of that is oil, 25% NGL, and 25% gas of the Eagle Ford.

Of what we are adding back in the 140 Bcfe to 2013 that is performance related that is about 50/50.

Okay, that is helpful.

I appreciate that.

In 2013, the VPP impact was about 35 Bcfe.

Okay.

Great, I appreciate that.

Then are we to come to the assumption, though, that the VPP for the Eagle Ford is completely off the table or is that something that comes back on the table as perhaps crude prices get a little bit better or NGL prices get a little bit better?

Any color on that would be helpful as we think about divestiture plans into 2013.

For now it is off the table.

Okay, appreciate that.

One last one just on the Niobrara - as you guys talk about cracking the code there can you talk a little bit about what you are thinking the initial rates of return on those wells look like, and maybe anything around well costs, well design, etc.?

Yes, Dave, this is Steve.

It is still pretty early there.

I think we have improvements that we want to make on our well costs but we have certainly found a sweet spot with this over pressured, high in liquids basin center that we are really hoping to get some production history and improve on.

Okay.

So to be determined over time is the best way to think of that?

It is still early.

We have got some big improvements to make on the cost side.

We have been still doing a lot of science in defining this sweet spot.

David, I would just say that anytime we are in a liquids play the goal is to have greater than 50% rate of return so if we are, for some reason, not there yet on these production rates, we intend to get our costs to that point.

These are big wells and they come in at 1,000, 1,500 boe per day.

We have got some gas production takeaway issues that are going to take a little bit of time to resolve.

We will probably have some flaring issues associated with that, but we really like where we are.

Of course, we have got CNOOC paying most of the costs there.

So if you take into consideration the carry, our returns from the Niobrara are basically through the stratosphere when you are only paying for a quarter of your costs.

Great.

I appreciate the added color there.

Thanks, guys.

Doug Leggate, Bank of America Merrill Lynch.

Good morning, everybody.

I'm going to try just a few quick ones, if I may.

I don't how much you can share about the asset sales, Aubrey, but obviously you talked about 1.5 million acres in the Permian and you had given a range of values around that.

It looks like you've split that into more than three packages.

Could you give any color as to order of magnitude of what is still left on the table and I guess level of confidence that these are going to get done in the third quarter?

Sure.

Doug, when we started out we offered it in both one entire package but also in the data room there were three packages.

There was the Midland Basin package, which was the smallest, and then there was the New Mexico Delaware basin and the Texas Delaware Basin.

We mentioned we have signed a purchase and sale agreement with EnerVest.

We have mentioned that we have two acceptable bids on the other packages and we are negotiating purchase and sale agreements there.

So we would have loved to have been able to had all three come across the finish line by the end of the quarter but just weren't able to get there.

But as Nick mentioned in his remarks, we expect to get those completed in the next 30 days or so.

Aubrey, you are very clear in the release that you sold the producing assets in the Midland.

Does that mean that there is still a bunch of acreage, undeveloped acreage still on the table?

Yes, sharp eyes there, Doug.

We will have our remaining acreage in the Midland Basin to either develop ourselves or, more likely, to go through another process and look for a home for it.

There are lots of different ideas there; private equity ideas.

There are other producers who were maybe intimidated by the size of the package.

Now when you take the production out of it I think we will get some more kind of growth through the drill bit companies to come back and take a look at the acreage.

So got a lot of options there and this just kind of emerged in the last few weeks that we will go through, frankly, a fourth process to finish up a basinal exit from the Midland side of the Permian.

Okay.

Aubrey, I don't suppose you would care to comment on the $4 billion to $6 billion original range that you gave relative to what you think you are going to realize?

Doug, no, we will continue to just let the process play out and as we have final numbers we will certainly share them with everybody.

Great.

My only other one is really on the activity levels, particularly in the Mississippi Lime.

I guess similar kind of issue on the joint venture there.

Any update you can share there?

But it also looks like you have lowered the rig count from your original plans to 18 versus I think it was 22 originally.

So is it just better well results and, if so, are you prepared to take the type curve up?

And just a general update on the Miss would be appreciated and I will leave it there.

Thanks.

Okay, couple things there.

First of all, we have reduced the rig count in the Mississippi Lime but we have done on all of our plays.

That is just basically the scale down of our enterprise from the start of the year when we were planning to run 200 rigs in 2013 and now we are planning to run 100, so we certainly needed to scale down.

In addition, in the Mississippi Lime we have decided to pursue less just pure HBP drilling and go into some core and some infill drilling there to help our returns, and also to not get too far ahead of our infrastructure.

You can spend a lot of money on infrastructure across a big area there.

With regard to EURs, last time I checked we haven't taken them up, although I noticed in what we call JV 1 area I think we are pushing 600,000 boe on the numbers that I saw.

But I don't think we have taken our pro forma up across the whole area.

Let's see the JV, still continuing our discussions.

There is obviously private equity interest, there is international interest, and we also have been approached for 100% exit from parts of the Mississippi as well.

So we will have lots of options there during the next couple of months as we sort out what we want to do in that area, but we are certainly pleased with our results and obviously watching EURs creep up from other players in the area as well.

Thanks, Aubrey.

Doug, thank you.

David Tameron, Wells Fargo.

Good morning.

Asset sales, let's go back to that.

Two questions - the third quarter, does that include any assumption for Mississippi Lime JV or is that pushed off for the time being?

I don't believe that it's in our third quarter.

That is more of a fourth-quarter expectation.

Okay.

Then if I think about 2013, the numbers you threw out for your asset sale target, what would that be?

Would that be -- obviously Chaparral is still out there, some of the services business, but can you talk about big picture what would be included in that package?

First of all, it is a much smaller number than we have been looking at this year.

So you are right that Chaparral is out there.

We have announced that we intend to sell a non-core asset like that.

We have mentioned that we would like to exit our investment in Fractech or FTS International at some point as well.

And then we have our service company IPO that we have put off to 2013.

Beyond that, I'm not going to say, but we have plenty of other bits and pieces of assets that we have that we will be shaving off to reach the goal of $4 billion to $5 billion in 2013.

I would like to emphasize as Nick mentioned that from a liquidity perspective, we don't have to sell anything next year.

But we certainly want to in order to be able to continue to keep an undrawn revolver and associated with keeping our debt at the $9.5 billion level.

Okay.

And then one more question - if I just look at what you did on the hedging side, it looks like you're implying that somewhere in that $3 to $3.25 is where you think gas topped out, at least for the remainder of this year.

Can you talk about is that the right read on what you did based on your hedging?

And if so, can you talk about your projection for the second half of the year, where you think gas will be?

Obviously, we had a nice run from the lows of late April to the above the $3 level, and I think we just wanted to be careful and conservative about our budget in the second half of the year, knowing that even with hot weather we were going to be working off a lot of the storage overhang but there were obviously potential issues in September and October if storage got full.

It looks like we are probably going to avoid the storage box now, so we are not intending to hedge anything at this point for 2013 at today's levels.

We don't think there is any chance that you have a 2013 strip that stays where it is today if you have a complete reversal of the 900 Bcf overhang that you had in April of 2012.

If you get a 900 Bcf storage deficit in April of 2013, clearly you are going to have to have higher prices than $3 in 2013 to incentivize producers to come back.

So for us it has got to be a pretty healthy price to pry our rigs away from our liquids production, our liquids-focused areas.

Steve, remind me, in 2013 how many rigs do we have allocated for dry gas?

It's about eight.

So I think eight rigs out of 100 in 2013 for dry gas.

So this has been a four-year downcycle and a lot of headwinds the last four years, but we think a multi-year upcycle is now underway and frankly, all the die has been cast, the chess pieces on the table have been played and now it is just a matter of physics and time for them to play out.

Then just following up on those comments, do you have any feel for, and I realize it is play specific, but do you have any feel for where gas would have to get back to before you would start to allocate away from liquids back to gas?

No, we are not going to give out those numbers.

It is different from play to play, but I think the industry has said that the number is probably north of $5 before gas plays generate the same kind of returns that you can get from oil at around $90.

The Marcellus maybe a little bit lower than that.

But gas prices have a way to go to catch up to levels that equal the returns we get from our liquids focused plays, and we will just wait for it to play out.

We have an enormous backlog of gas drilling opportunities and we will take advantage of those when the gas market pays us to do so.

All right.

Thanks for the color.

Biju Perincheril, Jefferies.

Couple of questions.

First, in the Utica, in the oil window can you give us some color how many wells you have now completed?

And, Aubrey, in the past you have said Utica is at least as good as the Eagle Ford.

Can you make that statement if you are only looking at the oil window of the two plays?

I don't think I would make that statement comparing the oil plays.

It is just way too early on the Utica side and we have not focused much of our efforts in that area.

Most of our acreages in the wet gas and the dry gas side, so we are basically allowing other companies to work on the oil side.

We have got plenty of acreage over there.

But right now we love what we see on the wet gas side.

Frankly, the dry gas side is as good as the Marcellus, so we are only drilling there where we kind of have to for acreage expiration issues.

So we think when it is all said and done, the wet gas in the Utica and the wet gas in the Eagle Ford are likely to be competitive but I am not willing to compare oil and oil yet because I just don't have enough information out of the Utica.

It goes without saying that we love what we are doing on the oil side in the Eagle Ford.

And the Eagle Ford you mentioned, I think, 15% decline in costs.

Can you say where costs are running currently?

A little over $7 million, right around $7 million per well.

Biju, did you hear that?

Yes.

Yes, that is all I had for now.

Thanks.

Charles Meade, Johnson Rice.

Morning, gentlemen.

A couple of questions - if I could go back to that divestiture question for 3Q, you guys put in your headline for that section of the press release a target of $7 billion.

Am I right in that the two biggest pieces of that are, number one, the midstream, the remaining $2 billion midstream sale to GIP and then the Permian sale?

I guess the question really is, is there another big piece that is going to add up to about $7 million?

Just to clarify, Charles, the $2 billion sale to GIP that actually occurred in the second quarter so it is done.

What is projected in the third quarter is the remaining part of our midstream business which is housed in an entity called CMD; that is our 100% owned midstream.

What got sold in the second quarter was CHKM now renamed ACMP, Access.

So those are the two headline events in the third quarter and, of course, we will have some miscellaneous assets to sell off.

Okay, great.

Going back to the Utica, could you tell us what the lateral lengths were for those 28 wells highlighted in your focus area?

I don't know if we have it exactly, but we can go ahead and tell him what on average we do there.

A little over 5,000.

Got it.

And TBD, I know it goes down as you descend into that gas window, but in general what is the TBD range for the wet gas down to the --?

6,500 to 7,000.

One of the attractive parts of that, of course, is we are now seeing wells get down to TD in 15 to 18 days, something like that.

So all the way drill the horizontal out.

So as we really move into manufacturing mode there one of the advantages that the Utica will have over the Eagle Ford and some other plays will be that it is shallower and will be cheaper.

You knew exactly what I was trying to get to.

Are you prepared or do you have anything you would share for what you think a development mode well cost is there?

I bet Steve can make that estimate.

Yes, I think we can get down to about 6.

Got it, got it.

Then one other question for you, Aubrey, is there anything that you can share about what the focus of some of the new Board members has been or what areas their attention has been drawn to or what questions that are top of mind for them?

Sure.

We have only had one meeting to date.

We just finished it last week, so we decided to have a mid-cycle meeting to get everybody acquainted with each other.

They are looking at the things that you would expect them to look at, the big topics for us, which are asset sales and CapEx and efficiency of our operations.

So that is where the needle gets moved and that is obviously where their level of interest is.

Great.

Thank you very much, guys.

Neal Dingmann, SunTrust.

Just a quick follow-up, Aubrey, just on the Utica, maybe for you or Steve.

Just wondering on those wells now are you still I guess in that wet window that you are drilling in letting most of those wells still rest after you complete those or what are you doing on that front?

Yes, sir, we are.

Most of these all that come on have been waiting on the pipeline really for the most part, but, yes, have been having some settle time.

So is that kind of going on a go-forward basis, Steve, you will continue to do that?

Even if you have the takeaway you will continue to do that to a degree?

Yes, Neal, I mean it ranges from dry towards liquids.

Again, the heavier oil and liquids we think more benefit from it, so it will be a variable.

Got it, got it.

Then just one in the Marcellus, you mentioned about the gas rigs you are going to let go.

I think in the press release, though, you talked about in the Marcellus having at least still six rigs going for dry gas the remainder of 2012.

So will you let some of those go after 2012?

Is that what that is implying or what will you do in that dry gas Marcellus window?

Yes, we think we can get down to four rigs there and hold our key acreage.

Okay.

Then just lastly, you just had a small increase I noticed on the acquisition of unproved properties.

Just wondering is that just bolt-ons or what was just the small add in guidance on that part?

Yes, it is basically just accounting for the fact that we had to clean up a number of transactions in the Utica.

I think Nick may have mentioned that about half of our leasehold spend for the 2012 is targeted for the Utica.

I think another 25% for the Anadarko Basin, including the Mississippi Lime, and 25% spread everywhere else.

So it is dropping very dramatically.

In fact, I think our first-quarter leasehold spend was about $955 million and dropped to $375 million or so in the second quarter and will continue to drop off quite remarkably, dramatically rather, which I guess will be remarkable.

But we are targeting for 2013, $100 million a quarter and we think that maintenance mode will be even lower than that.

I would love to say we could get to a lower number than that in 2013.

We will certainly try to, but there are still a lot of little holes out there, particularly in the Utica and often in the Marcellus as well.

It jeopardizes a much bigger investment when you fail to go out and complete your unit.

But in the Eagle Ford and most of our other plays, really down to almost zero in terms of additional leasehold buys.

Okay.

Thanks, guys.

Solid quarter and great progress.

Bob Morris, Citi.

Good morning.

Steve, a question on the rigs.

You are going to drop down to 100 rigs at year-end and that is what you plan to hold at for next year.

As I recall, 100 rigs is what Chesapeake owns outright or under a sale leaseback so at that point do you expect to just be running your own rigs and to drop all third-party leased rigs then by year-end?

We will still have some third-party rigs so we will have to stack some of our older mechanical rigs.

Has Nomac tried to lease some of your rigs to third parties at this point or do you think you might be able to do that in the future?

Yes, sir, we have I think 10 or 12 leased to others right now.

All right, thank you.

Jason Gilbert, Goldman Sachs.

Morning, guys.

Most of mine have been asked already.

I think you had mentioned in the past your desire to do a couple of more JVs in the Utica.

I just wanted to hear what your latest thinking was there.

Certainly, Jason.

We will do at least one in the dry gas part of the play and we will wait till 2013, though, to do that when we have got better gas prices.

So that is certainly one of the asset sales that we have in mind for 2013.

On the oil side, it just remains to be seen if the results allow us to do that and we also have a couple of other JV ideas out there.

We think the JV market is still strong.

It has been supplemented by the interest of private equity players during the past year, so that has probably been the biggest change in the market out there in the past year, which is the arrival of, frankly, several tens of billions of dollars of assets that private equity players have brought to the table.

Thanks.

My second one was on the spending guidance increase you mentioned in the comments that it was just spillover from late 2011 or late 2012.

It just sounds like inertia really.

But if I remember correctly you had reiterated the old guidance as recently as July in the investor presentation, which maybe suggests to me that you don't always have a lot of visibility with this.

And I was just wondering if you could say with confidence that these spillover costs are now behind you and we are over the hump on the CapEx increases.

We really think they are in terms of affirmation in July.

I don't remember that so much other than we only change our guidance once a quarter so in July it would have been what we put out in April, and so we kind of just live with it until we have end of the quarter earnings release like we have now.

This is obviously something that we scrub very hard.

We are not happy about the increase and really determined that with our new numbers that they are numbers that we can not only meet but live within.

Great, thanks.

I will turn it back.

Scott Hanold, RBC Capital Markets.

So on the 100 rigs you are going to be running in 2013, how many of those do you think are going to be HBP versus drilling for economics?

First of all, I would say that even if it is drilling to HBP acreage it will be an economic activity, but I think I understand your question.

Certainly a well that is a second or third well in a unit is likely to be better than the first well.

So, Steve, do you have an estimate of that or not?

It is a fairly small percentage.

We are focusing in the core.

Like you said, HBPing within the core but not necessarily multiple wells within a unit.

So if you look at your leasehold, how much do you think with the reduced rig count, is I guess the term would be at-risk for expiration?

Or is some of the stuff that could expire is that stuff that could be potentially up for an asset sale and/or you may not want it anyway?

I think that is really the right way to think about it, Scott.

One of the things we are doing is not only selling assets that are not core but also looking at our 10 core areas and determining what we just don't have the capital to get to and what we don't have the time to get to.

So I think you will see us sell some of our leasehold in plays that are absolutely core to us over the next six months or so as we recognize that we have acreage that may fit other companies better or we have acreage that would expire unless we went and drilled it.

So as we pull in our horns and focus and concentrate our drilling in areas that are going to generate the highest returns, it is a very different strategy than what we have used for the last few years which is to lock down this asset base that we have taken from being in a temporary asset base subject to expiration to a permanent asset base.

And so, for example, nobody today thinks a whole lot about value from the Haynesville, but we have something like 7,000 wells to drill in the Haynesville that are HBPed or that are future drilling opportunities on acreage that has been HBPed.

So I don't think it is fully baked in our forecast going forward, the increases in efficiency that are going to be generated, and certainly the increases in returns on investment as we continually move towards a program of drilling wells that will be on acreage that is already HBPed rather on acreage that is just sitting out there to be drilled at some point.

So stay tuned for other parts of our core areas that we might be willing to let the rest of the industry take a whack at rather than spend our own capital chasing those opportunities to HBP further acreage.

Okay, appreciate that.

One follow-up too - just so I understand this right, so when you look at your drilling CapEx in 2013 being down $750 million, when I look at that, how much is related to just better drilling efficiency versus a planned further reduction to rig count versus changes in planned asset sales or divestitures?

There is certainly some associated with efficiency and hopefully some cost savings as well as obviously the price of fracks have come down in other parts of the drilling and completion operation.

But mostly it is just the drop of rigs as we move down to 100 rigs for 2013.

So it is most of the stuff you could directly control in theory?

Right.

We are not saying that we are going to assume there is a 15% efficiency factor and that allows us to drop our CapEx by 15% or something like that.

It is really related to rigs and if we are able to drive efficiencies higher where we're able to drive costs lower then that, hopefully, will be icing on the cake for us.

Thanks, guys.

Scott, one other thing I might mention, as you lower your cycle times you can drill more wells with a lower number of rigs.

So, for example, in the Eagle Ford as we drop, I think, Steve, we are scheduled for 25 in 2013, is that right?

No, we are 22, but we are already seeing lots of wells in the mid-teens and so I am hoping that can go down even more.

But 22 is spud to spud.

I was talking about number of rigs rather than days.

So the point is that as our efficiencies get higher we can reduce the number of rigs.

Our CapEx may not go down but your return on that investment will go up as you get more wells drilled at the same number of inputs.

Got it.

Thanks, guys.

Matt Portillo, Tudor Pickering Holt.

Good morning, guys.

Just a couple of quick questions for me - a quick follow-up on the Eagle Ford question.

Could you give us an idea; I think in the second quarter you guys drilled around 121 wells in the Eagle Ford versus the first quarter of 62.

What is the expected run rate over the next few quarters in terms of completions in the Eagle Ford?

And then once you get down to 22 rigs in 2013 what would be a normalized quarterly well count for you there?

Matt, this is Steve.

Should be similar to this 30, low 30s per month turn in line phase.

The way I like to think about it, Matt, during the last quarter we completed an Eagle Ford well every 18 hours and going forward think we can probably even do better than that.

Perfect.

Then just in terms of the wells you put in the release, obviously a lot of detail on kind of the larger category of wells here with I think peak IPs of around 500 barrels a day equivalent.

Could you give us an idea of roughly what the 30-day rates look like there and maybe just your new expectations around what the EUR would be?

I think Steve can help you with both of those.

I am looking.

Matt, while he is looking do you have anything else?

Yes, sure, just two final questions for me.

On the CapEx side, just curious on 2013 if you had a high enough gas price desire to flatline your gas production next year, what sort of capital increase would we need to see on your development budget to get to that level of flat production?

That is a good question, Matt.

I don't have that right now, but we can certainly dial it up for you.

Again, it would take quite a bit stronger price than what is in the forward curve right now for us to be interested in doing that, but clearly we have the assets to do it and have the capability to do it.

Remember, this is an issue where I think a lot of investors and analysts perhaps think about it in the abstract or in a vacuum, which is what is a gas price that gives you a reasonable rate of return on a well in the Marcellus or Haynesville or Barnett?

That is only part of the equation.

The other part of the equation is capital is finite obviously.

So you have to not only generate an attractive return, but you have to generate a return that is competitive with your other returns.

So it is not do we make money at $4 gas or $5 gas, it is do we make as much money drilling a gas well at that price compared to what we make drilling an oil well at $90 a barrel.

And so that is, I think, a part of the equation that is missing from most people's analysis of the gas market going forward.

Steve, do you have anything to follow up with?

We actually break the Eagle Ford into multiple pro formas because we are wet gas and shale oil but the blend is about 9,000 barrels for the first month.

Anything on NGLs or gas?

We don't produce a whole lot of gas out there.

I will let him continue to look; we can come back.

And given that we are kind of over our hour, I don't know how many folks are left to answer questions, but we are going to, as a courtesy to everybody, we are going to take two more questions.

Then if for some reason you didn't get a question asked and answered, please dial it in to Jeff, John or Gary and they will get back to you.

Operator, we will take two more please.

Bob Brackett, Bernstein Research.

I had a question on the Utica, a two part.

One is it looks like you had a well producing in the Tuscarawas County, which is pretty oily.

Any color on that would be appreciated.

Also, ignoring land retention, where would you put that last rig, in the Mississippi Lime or in the Utica?

Bob, that is tough, man.

First of all, good morning to you.

Let's see, I would say right now Carroll and Columbiana counties are tough to beat on the Utica, and Alfalfa and Woods are tough to beat in the Mississippi Lime.

So I'm not going to declare a winner between those two.

But I would say that each of them has a little bit of HBP work to be done in those counties, probably more to be done in Carroll and Columbiana than in Alfalfa and Woods.

But we will go back and play with that a little bit.

But both of those are very, very attractive areas and, hopefully, they would end up being very competitive with any incremental capital.

And that Tuscarawas County well?

I am not -- do you have a name for us?

Yes, I've got that.

That came on about 227 barrels of oil a day and 1.3 million.

And what is the name of the well?

Gribi

Oh, the Gribi, yes.

Okay.

Are you guys looking at any new plays or is that pretty much done?

We are pretty much done.

We have an acreage position in an area that we have not talked about publicly that I mentioned a little bit about a year ago.

We still will continue to poke around there.

It is a pretty cheap area there and we will get some wells drilled or tested in the next three to six months and see if it is something worthwhile or not.

But we haven't spent much money there to date.

If it becomes a core area for as great, if not we will be happy with the 10 that we have.

Thank you.

Joe Magner, Macquarie Capital.

Good morning.

Thanks for taking my question.

Just any update on the divestiture efforts for the DJ and Utica properties that were announced over the last couple months?

I don't think so but DJ would be modest I think given our lack of success in that area and the industry hasn't done well outside of Wattenberg.

So we will get what we can there and move on.

The Utica fringe process is underway.

We will have something to say there in the next couple of months as we definitely will have successful leasehold sales in that area.

The Utica is clearly an area of intense interest for the industry.

Given our first mover status there, a lot of people that want to establish positions come to see us, so we look forward to sharing some good news there later.

Okay.

And along the lines of the Utica can you update us just on takeaway capacity and when we might expect to see some of those wells turn to sales and production starts to ramp up there?

It is mostly a 2013 but Nick, if you want to address that or, Steve, you want to address it, we have got big programs there underway and kind of lost track with all the different entities involved.

But you want to try and sort that out?

Well, I don't have any real specific dates other than there is a lot of big infrastructure projects underway and we have it all mapped out and looking forward to bringing on more wells.

We have been trying to focus our drilling as close to existing pipelines as we can, so we are doing our best to minimize it in the meantime but there is a lot of infrastructure headed to the Utica.

Processing; there is going to be NGL takeaway adds.

There are projects that want to go to Philadelphia, projects that want to go to Belvieu, so we are going to be a foundational shipper likely in any project that originates from the Utica.

So there is going to be plenty of liquids there and we think plenty of opportunities to get either Belvieu pricing or Belvieu equivalent pricing over time.

Okay.

Just one last one - Nick, any anticipated amount for the ceiling test write-down in the third quarter and could you provide us with where the cushion sits?

No anticipated amount.

There are just too many ins and outs between now and then to give a number, even within a range, so I would like to hold off on doing that right now.

The cushion is pretty significant in my view, but I don't think we are prepared to disclose what that is today.

All right, that is all I have.

Thanks.

Joe, thanks for your questions and thanks to everybody else.

Again if you have additional questions send them in to IR team and they will get back with you shortly.

Thanks again.