赫斯 (HES) 2012 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Hess Corporation's second-quarter earnings conference call. My name is Tawanda and I will be your coordinator for today.

At this time all participants are in listen-only mode. Later we will conduct a question-and-answer session. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the conference over to Mr. Jay Wilson, Vice President of Investor Relations. Please proceed.

Thank you. Good morning, everyone, and thank you for participating in our second-quarter earnings conference call. Our earnings release was issued this morning and appears on our website, www.hess.com. Today's conference call contains projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements.

As usual with me today are John Hess, Chairman of the Board and Chief Executive Officer; Greg Hill, President, Worldwide Exploration and Production; and John Rielly, Senior Vice President and Chief Financial Officer. I will now turn the call over to John Hess.

Thank you, Jay, and welcome to our second-quarter conference call. I will make a few brief comments after which Greg Hill will provide an update on our activities in the Bakken. John Rielly will then review our financial results.

This conference call at midyear is when we discuss our 2012 results and forecast in more detail. Just as important, this quarter also marks the midpoint in a period of important change for Hess. Before getting into the details of the quarter, I would like to reflect on this change for a moment as I think doing so will provide meaningful context to our current and expected future results.

This change essentially began in 2009 and should be largely complete in 2014. In that relatively short span of five years, Hess has all but exited the refining business with the closure of the HOVENSA joint-venture refinery and will have shifted our Exploration and Production growth strategy from one base primarily on high-impact exploration to one combining lower-risk unconventional development opportunities such as the Bakken, along with the exploitation of existing discoveries like North Malay Basin, and more focused and limited exposure to high-impact exploration such as Ghana and Ness Deep in the deepwater Gulf of Mexico.

This shift in Exploration and Production has required a substantial upfront increase in capital spend, largely related to the Bakken. Approximately 35% of this year's capital and exploratory expenditures are devoted to the Bakken compared to 11% in 2009. The majority of our total spend has been funded with cash flow from operations. Any shortfall has been and is expected to be funded mostly, if not entirely, through asset sales as we rebalance our oil and gas reserve and production portfolio in favor of lower risk, geographically more secure and higher return assets.

At current oil prices, the gap between cash flow and capital expenditures should peak this year at about $3 billion, moderate substantially next year, and approach a balance in 2014. Asset sales should be largely completed by year-end 2013. We expect that the reserve and production base established as a consequence of these actions will be lower than the levels likely to be achieved in 2012. However, the profitability of those barrels on a per unit basis should be higher than is currently the case.

With the feedback gained each day through the execution of our strategy, we feel ever more confident that this portfolio reshaping is the right course for our company. Certainly there have been and will continue to be difficult learning experiences along the way, but we are convinced of the strategy, committed to its successful execution, and believe it will lead to improved financial performance.

With that as an introduction, we will now cover the details of the quarter. Net income for the second quarter of 2012 was $549 million. Compared to the year ago quarter, our earnings were positively impacted by higher crude oil sales volumes and improved marketing and refining results, but were negatively impacted by lower realized crude oil selling prices and higher operating costs in Exploration and Production.

Exploration and Production earned $644 million. Crude oil and natural gas production averaged 429,000 barrels of oil equivalent per day, a 15% increase over the year ago quarter. Higher production from the Bakken in North Dakota, the Llano Field in the deepwater Gulf of Mexico and Libya was partially offset by natural field declines in Equatorial Guinea.

In North Dakota, net production from the Bakken averaged 55,000 barrels of oil equivalent per day in the second quarter compared to 25,000 barrels of oil equivalent per day in the year ago quarter, an increase of 120%. For the full year 2012, we now forecast net Bakken production to average between 54,000 and 58,000 barrels of oil equivalent per day.

In April we commenced operation of our crude oil rail loading facility and shipped an average of 29,000 barrels per day during the quarter to higher value markets. At the Llano Field in the deepwater Gulf of Mexico where Hess has a 50% interest, a successful workover was performed on the Llano number 3 well, which had been shut in for mechanical reasons since the first quarter of last year. The well was brought back online in May, and in June net production averaged 13,000 barrels of oil equivalent per day.

In Libya, net production averaged 22,000 barrels of oil equivalent per day in the second quarter. In last year's second quarter, the fields were shut in due to civil unrest. Given the political uncertainty in Libya earlier in the year, we chose to exclude Libya from our original 2012 production forecast. However, since production has been restored, we will now include Libya in our revised production financial forecasts.

At the Valhall field in Norway, net production averaged 23,000 barrels of oil equivalent per day in the second quarter. BPV operator has informed us that the field will be shut in for approximately 90 days compared to their original forecast of 30 days, which will result in 2012 net production averaging 15,000 to 20,000 barrels of oil equivalent per day versus our previous expectation of 20,000 to 25,000 barrels of oil equivalent per day.

Major field redevelopment work is now expected to be completed by the end of this year and development drilling will resume in 2013. As a consequence of these factors and the strong overall performance of our portfolio, we now forecast 2012 production for our company to average between 395,000 and 405,000 barrels of oil equivalent per day, which includes the addition of approximately 20,000 barrels of oil equivalent per day from Libya, which was excluded from our previous forecast of between 370,000 and 390,000 barrels of oil equivalent per day.

In June we signed agreements with PETRONAS to develop nine discovered natural gas fields in the North Malay Basin located offshore peninsular Malaysia and adjacent to Hess's interest in the Malaysia/Thailand joint development area. This project is consistent with our strategy to invest in long-life low-risk reserves with attractive financial returns and exploration upside. Hess will have a 50% working interest and become operator of the project.

The project will require a net investment for Hess of approximately $250 million in 2012. First production is forecast to commence in 2013, at a net rate of approximately 40 million cubic feet of natural gas per day, an increase in 2015 to an estimated 125 million cubic feet per day.

With regard to exploration in Ghana, Hess concluded drilling operations on the Hickory North well in June. The well encountered approximately 100 net feet of gas condensate pay. We recently completed drilling our [beach] prospect located five miles north of the Paradise location, and are conducting wireline logging. The Stena DrillMAX drillship will next drill our [Aman] prospect located 20 miles west of Hickory North.

Offshore Brunei, the Jagus East well on block CA1 in which Hess has a 13.5% interest, encountered hydrocarbons. This will along with the previously announced Julong East discovery is being evaluated, and additional exploration and appraisal drilling is planned in 2013.

In the Deepwater Gulf of Mexico on June 12, we spud the Ness Deep well located on Green Canyon 507. This is a Miocene prospect in which Hess has a 50% working interest. BHP holds the remaining 50% and is the operator. The well is anticipated to take approximately 160 days to drill.

Turning to Marketing and Refining reported net income of $8 million for the second quarter of 2012. Refining generated earnings of $8 million versus a loss of $44 million in the year ago quarter, reflecting a positive contribution from our Port Reading facility in the second quarter and the shutdown of the HOVENSA joint-venture refinery earlier this year.

Marketing earnings of $18 million included an $11 million after-tax charge for environmental liabilities compared to $28 million in last year's second quarter. Retail marketing benefited from declining wholesale prices during the second quarter, which resulted in improved fuel margins. Gasoline volumes on a per site basis were down approximately 3%, while total convenience store sales were down nearly 6% versus last year's second quarter, reflecting the continued weak economy.

In energy marketing, natural gas and oil volumes were lower versus last year, while electricity volumes were higher. Capital and exploratory expenditures in the first half of 2012 were $4.1 billion, substantially all of which were related to Exploration and Production. For the full-year 2012, our capital and exploratory expenditures forecast has been increased to $8.5 billion from $6.8 billion. Over half of the increase is due to activities in the Bakken with the balance related to Valhall, Tubular Bells, and our recently announced investment in the North Malay Basin.

Although our 2013 capital and exploratory budget will not be finalized until the end of the year, we plan to make significant reductions below 2012 levels and be more aligned with expected cash flow. As I said previously, we expect that internally generated cash flow and proceeds from asset sales will fund most if not all of our 2012/2013 capital and exploratory expenditures.

Year to date we have announced asset sales totaling more than $850 million, which includes the sale of our interest in the Schiehallion field in the United Kingdom to Shell for $503 million, as well as the previously announced sale of our interest in the Snohvit Field in Norway and the Bittern Field in the United Kingdom.

Additional asset sales of $1 billion to $2 billion are well underway, and details will be announced as soon as terms are finalized. Further asset sales have been identified and are in the early stages of the divestiture.

I will now turn the call over to Greg Hill.

Thanks, John. I would like to provide a few remarks about the Bakken. We are continuing our transition in the Bakken during 2012, from higher-cost 38 stage hybrid completions and HBP drilling to lower-cost 34 stage sliding sleeve infield drilling. In the first quarter nearly 70% of our wells were hybrid wells with an overall average drill and complete cost of $13.4 million per well. During the second quarter only 40% of our wells were hybrids, with an overall average drill and complete cost of $11.6 million, a reduction of 13%.

Looking forward to the second half, our HBP drilling will be substantially completed by year end, and 100% of our wells will be sliding sleeve wells by the fourth quarter, leading to an estimated drill and complete cost of under $10 million.

Second-quarter production averaged 55,000 barrels of oil equivalent per day, up 30% from the first quarter and 120% from the second quarter of 2011. Our higher second-quarter production reflects working off our completion backlog and the drilling of higher working interest wells. We expect 2012 net production to average between 54,000 and 58,000 barrels of oil equivalent per day, which implies net production will leverage between 60,000 and 68,000 barrels of oil equivalent per day in the second half of 2012.

Our 2012 capital budget for the Bakken has been increased to about $3 billion from $2 billion previously. There are four primary drivers for this increase. The first driver is our decision to drill in higher working interest areas, reflecting an average working interest of approximately 80% versus a budgeted 62%, and to drill additional wells in 2012. While these changes will result in increased capital spending of approximately $500 million, they will also allow us to substantially complete our HBP drilling in 2012 and accelerate production growth that will partially offset the lower than planned production experienced during the first quarter.

The second driver is an overall increase in drilling and completion costs, which are now expected to average approximately $11 million per well in 2012, versus our original budget of approximately $8.5 million. These cost increases are due to the need to use ceramic proppant instead of white sand caused by market shortages earlier in the year, coupled with a slower than anticipated transition to full sliding sleeve. While higher well costs will result in additional capital spending of approximately $300 million, we still expect to generate attractive financial returns.

The third driver is increased infrastructure spend associated with the gas plant and gathering systems due to design changes and higher labor costs, which will increase capital spending by approximately $150 million.

The final driver is higher than budgeted nonoperated drilling spend from additional wells and also higher nonoperated well costs, resulting in additional capital spending of approximately $100 million.

In closing, it is important to note that we are still relatively early in the overall development of the Bakken. We are building a long-term business from a large, high-quality acreage position and competitively advantaged infrastructure. As we move forward, we expect significantly lower capital costs through further well cost reduction, through the completion of the major infrastructure projects including the Tioga Gas Plant in 2013, and through improved capital efficiency as we complete the transition from HBP to pad drilling.

Thank you. I will now turn the call over to John Rielly.

Thank you, Greg. Hello, everyone. In my remarks today I will compare second-quarter 2012 results to the first quarter. The corporation generated consolidated net income of $549 million in the second quarter of 2012, compared with $545 million in the first quarter. Excluding items affecting comparability of earnings between periods, the corporation had earnings of $585 million in the second quarter compared with $509 million in the previous quarter.

Turning to Exploration and Production. Exploration and Production had income of $644 million in the second quarter of 2012, compared with $635 million in the first quarter. In the second quarter of 2012, the corporation and a joint venture partner agreed to exchange interest in properties in the Eagle Ford Shale in the United States and the Paris Basin in France. As a result, the corporation recorded an after-tax charge of $36 million to reduce the carrying value of the exploration properties that are expected to be divested in the exchange.

First-quarter results included an after-tax gain of $36 million related to the sale of the corporation's interest in the Snohvit Field offshore Norway. Excluding these items, the changes in after-tax components of the results were as follows. Higher sales volumes increased earnings by $161 million. Lower selling prices decreased earnings by $61 million. Lower exploration expense increased earnings by $37 million. Higher operating costs, primarily depreciation, depletion and amortization, decreased income by $61 million. All other items net to an increase in earnings of $5 million for an overall increase in second-quarter adjusted earnings of $81 million.

Our E&P operations were overlifted in the quarter compared with production, resulting in increased after-tax income of approximately $25 million. The E&P effective income tax rate for the second quarter of 2012 was 47%, excluding items affecting comparability of earnings between periods.

In July 2012, the government of the United Kingdom changed the supplementary income tax rate applicable to deductions for dismantlement expenditures from 32% to 20%, with an effective date of March 12, 2012. As a result, we expect to record a one-time charge in the third quarter of 2012 of approximately $100 million to increase the deferred tax liabilities related to asset retirement obligations in the United Kingdom.

For the full year of 2012, we expect our normalized E&P effective tax rate to be in the range of 44% to 48%. This forecast reflects the resumption of operations in Libya.

Full-year 2012 unit costs are now expected to be $39 to $41 per barrel of oil equivalent produced, down from our previous guidance of $40.50 to $42.50 per barrel. E&P cash offering costs are still expected to be in the range of $20 to $21 per barrel, and depreciation, depletion and amortization expenses are now expected to be in the range of $19 to $20 per barrel.

Turning to Marketing and Refining. Marketing and Refining generated income of $8 million in the second quarter of 2012, compared with $11 million in the first quarter. Marketing earnings were $18 million in the second quarter of 2012, compared with $22 million in the first quarter, principally reflecting seasonally lower energy marketing earnings and an after-tax increase in environmental liabilities of $11 million, partially offset by improved retail gasoline margins.

In refining, Port Reading operations generated income of $8 million in the second quarter of 2012, compared with a loss of $6 million in the first quarter, reflecting higher margins. Trading activities generated a loss of $18 million in the second quarter of 2012, compared with a loss of $5 million in the first quarter.

Turning to corporate, net corporate expenses were $39 million in the second quarter of 2012, compared with $38 million in the first quarter. After-tax interest expense was $64 million in the second quarter of 2012, compared with $63 million in the first quarter.

Turning to cash flow, net cash provided by operating activities in the second quarter, including a decrease of $334 million from changes in working capital, was $1.240 billion. Capital expenditures were $1.978 billion. Net borrowings were $803 million. All other items amounted to a decrease in cash of $52 million, resulting in a net increase in cash and cash equivalents in the second quarter of $13 million.

We had $409 million of cash and cash equivalents at June 30, 2012, and $351 million at December 31, 2011. Total debt was $7.845 billion at June 30, 2012, and $6.057 billion at December 31, 2011. The corporation's debt to capitalization ratio at June 30, 2012 was 28.2%, compared with 24.6% at the end of 2011.

As John Hess mentioned, total full-year capital spend is now expected to be approximately $8.5 million. The increase is primarily in four areas. Greg Hill has just explained the increase in Bakken capital spending. The remaining drivers for the increase relate to the recently sanctioned project in the North Malay Basin which added $250 million, cost increases for the Valhall redevelopment project of $200 million, and accelerated spend of $100 million at the Tubular Bells Deepwater development due to the early arrival of the rig.

We plan to fund most if not all of our capital program with cash flow from operations and anticipated proceeds from the asset sales previously mentioned by John Hess. We are currently using our available credit facilities to fund our capital program until the asset sales are completed. At June 30, 2012, we have $2.2 billion of outstanding borrowings under available credit facilities, with additional committed credit capacity of $4.3 billion.

This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.

(Operator Instructions) Robert Kessler, Tudor, Pickering, Holt.

Good morning, gentlemen. John Hess, you referenced you coming moderate -- well, you expected the net-out spend for '13 to moderate substantially next year. I just want to see if you could be a little bit more specific. I know you have to go through budgeting and everything, but just is there a way to give us some sort of range plus or minus $1 billion for 2013?

No, I can't for the very reasons that you said. But I will say and repeat that we plan to make significant reductions below 2012 levels for our capital and exploratory spend in 2013. We are going to have flexibility in the Bakken for the reasons Greg said, going from HBP to pad drilling, also the change in completion. Also a lot of the infrastructure investment will be behind us. Also some of the assets that we are selling like Schiehallion will also allow us to get rid of some capital expenditures that we previously had been obligated to spend money on.

There are other such things that we are considering selling now. And as the specifics of those asset sales are done, we will be able to give more granularity if you will to the projection for next year. But with the significant reductions below 2012 levels and also the cash flow that we expect to get from our production operations, we will be much more aligned with expected cash flow going into 2013, and then pretty much in balance in 2014.

So those are the conceptual points. I can't be more specific at this time, which I am sure you understand.

I understand. When you think about balance for 2014, though, what oil price do you assume?

We test down to $80 Brent, but you could assume something in the $90 to $100 Brent range as you think about it conceptually.

And then conceptually, do you think your capital program will be more flexible and variable going forward? Now that you complete the drilling to hold the acreage in the Bakken, will you dial it up or back down?

Yes, we will have more flexibility. I think that is a fair statement. Also, you have to remember we are going to have a number of fields that we are investing in now like Tubular Bells and North Malay Basin, and also the continued investment in the Bakken that should generate more production in 2014. So we will have more cash flow in 2014 from projects that we are spending money on right now.

Understood. Thank you very much.

Doug Leggate, Bank of America Merrill Lynch.

Thank you. Good morning, everybody. Can I start off with asset sales, please? I just want to be clear on your prepared remarks. Did you say an additional $1 billion to $2 billion?

Yes, an additional $1 billion to $2 billion are well underway and the details from those activities will be announced as soon as the terms are finalized. But I also said that above and beyond that further asset sales have been identified and are in the early stages of divestiture.

Okay. You made a comment that this would impact production. We could all take a stab at, I guess, the Eagle Ford restructuring. And you have previously said small working interests, so I guess that might put Azerbaijan in the block.

But these are fairly small in terms of production impact so can you help us with the order of magnitude as to what production is associated with these asset sales?

It's fair enough there, Doug. Again, I can't because these things are underway. Some may succeed, some may not happen, but we have a number underway. So again the specifics of that I only could do once the sales details are finalized.

But I think the real import take away there is that while the reserve and production base that we have right now will likely be lower than the levels that we have now in 2012, the profitability of those barrels on a per unit basis should be higher as is currently the case. So the important thing is we are going to be shedding assets are either smaller interest, that have capital investments associated with them, that may be not as attractive to us, maybe they are in mature areas as well, and we are going to be reinvesting those proceeds and assets that offer lower risk, higher returns, and more sustainable growth.

So we are confident that these reshaping moves will improve our financial performance and really create long-term value for our shareholders.

Before I leave the asset sales, John, just to be clear, you are expecting all of this to be received in the door by the end of this year or is (multiple speakers)?

No, we may announce all it by the end of the year if we are fortunate enough, but more likely than not some of the proceeds in terms of receiving the cash may end up coming in in 2013. That is why I said that the asset sales should be largely completed by year-end 2013.

Got it. Thank you. If I could take a second one on the Bakken, maybe to John. Actually, Greg, sorry.

As regards your Bakken production, Greg, the 55,000 in the second quarter suggests that June or at least the exit rate must have been a fairly punchy number. Can you give us some idea as to how -- where production stands right now and maybe talk a little bit about what the impact will be of moving to a whole sliding sleeve in terms of completion stages? And maybe talk a little bit about how the well results have been coming in of late, because they still look pretty good to us.

Thanks, Doug. Kind of current rates in the Bakken are just shy of 60,000 right now as we speak. You mentioned that we are very pleased with the wells. Of the 165 30-plus stage wells that we have drilled the average IPs are 900 barrels a day and we are particularly pleased when you look at the NDIC data that Hess has drilled seven of the top 25 wells in the play in the first four months of 2012.

We are in transition to the sliding sleeves, and as I said in my opening remarks, really by the fourth quarter we will be in 100% sliding sleeve mode in the Bakken. So obviously that offers significant advantages in terms of timing as well as a reduction in completion costs.

Got it, thanks. If I can just squeeze one more in and then I will leave it there. You mentioned that you are going to be logging beach. I am guessing you don't log dry holes, Greg, so can you give us some idea as to what they plan going forward could be for Ghana? And I will leave it at that, thank you.

Doug, I have got to be very careful here because obviously we can't outrun the government, so anything we really announce about Ghana has to be approved by the government. So suffice to say, you are right, we wouldn't be logging something if it was a dry hole so that is about all I can say.

All right. I will leave it there. Thank you.

Evan Calio, Morgan Stanley.

Morning, everybody. John, a broader CapEx question. I know the market has been very focused on CapEx increases and I think your stock is pricing real value destruction. I just -- maybe on a higher level question; you mentioned improved returns, but can you quantify your expected returns for these capital projects?

Meaning when Hess vets global opportunities or spending decisions, could you just describe your process and your hurdle rates and how you stress maybe downside returns? I know you mentioned your implied Brent outlook.

We look for cost of capital, meaning 10%, testing it down to $70 and $80 Brent. Number one, our hurdle rate is 15%. Obviously when you talk about a hurdle rate you got to take risk into account as well; so for certain projects we are higher than 15%, for lower risk, long life returns it will be a little bit lower than that. But generally it is 15% hurdle rate.

Then maybe somewhat related, I mean just talking on a price-to-reserve basis, other Hess trading significantly below implied F&D in your CapEx number. I know that is not perfect analysis yet it is clearly historically wide. I mean how do you think about weighing buybacks given the paper value versus investment decisions in this calculus?

Right now what we are focused on is making the investment to reposition the portfolio for lower risk, more profitable growth, led by the Bakken, but by the other parts of our strategy that I talked about. It is a more balanced, lower risk approach to profitable growth.

Obviously, because we are in the investment mode now due predominantly to the Bakken, we are going to use predominantly, if not all, asset sales to make up the funding gap and get more balanced. After we get more balanced then how we use our cash going forward will be a decision that we make where we can find the best way to invest our money for our shareholders.

Great, and maybe just one last if I could. I mean it is clearly topical across the sector. It seems like everything imaginable is ending up in an MLP.

You have some more conventional midstream assets, you spent a lot on infrastructure in the Bakken with potential organic growth behind it which is reasonably tax advantaged. Any thoughts, how do you think about that vehicle as a potential sourcing of funds?

It is certainly an idea that we weigh against continuing to invest in infrastructure. The Bakken infrastructure we have is really advantaged because of the upstream, higher revenues that we get. Because we have significant size and scale in the Bakken, it gives us a competitive position, so that doesn't necessarily mean that MLP would be the most advantageous in the long run to do.

So the point is it is something that we look at, but at the end of the day I think you have to look at it play by play as opposed to just saying do an MLP for all your midstream assets.

Appreciate it. Thanks, guys.

Faisel Khan, Citigroup.

Thanks, good morning. On the increase in capital spending in the Bakken from what you initially guided in January versus where you are now, how do you guys get comfortable that this is the last increase we are going to see this year and as you go to the end of the year you are not going to see any further increases?

Well, I think if you look at the trends, I mean clearly our costs are coming down as I said on our well costs in particular. Obviously the first quarter well costs were high driven a lot by the plug-and-perf wells. Then in the second quarter we dropped our well costs by 13% and we expect that trend to continue as we go through the year. Obviously, as we continue to complete infrastructure that helps as well.

The final thing is by year-end we will be out of HBP mode and largely in infill drilling mode as we move into 2013, so there is some obvious advantages there.

And then as you guys look at your overall capital expenditure budget, what level of capital do you guys think you need to spend in order to keep production flat?

We are not really giving that guidance right now and let me tell you why. Now that we are nearing the end to HBP mode what we are doing is we are doing a comprehensive development strategy for the Bakken, so this is a long-term development strategy with the goal of maximizing profitability and capital efficiency. And so the results of that study will be used to optimize the drilling program in 2013 and beyond.

Okay, fair enough. Then in the Bakken I think you gave us some data points in terms of the drilling times for your wells. Can you give us some trend data on those wells today, where you were versus last quarter?

That has pretty much stayed the same so there haven't been major improvements in drilling time Q1 to Q2. Obviously, as we move, again, out of HBP mode and more into pad drilling you can expect some reductions there, because the numbers we quote are spud to spud, so that includes all the movement of the rigs that occurs between locations.

Okay, understood. Then on your sort of prepared remarks and how you expect to spend less CapEx next year, does any of that reduction in capital spending affect your long-term kind of production growth guidance?

Again, specifically the Bakken, again I think, just say again, we are in the process of completing this comprehensive long-term development strategy for the Bakken. Again, our goal there is maximizing profitability and capital efficiency and the output of that model will really dictate what those future curves look like.

Okay. Then last question for me. Do you guys plan to hold an analyst meeting to discuss all these changes and the details, and kind of how you guys are spending capital over the next few years?

We obviously have an active investor relations program; we will continue to. Certainly at the right time we will consider hosting our own company investor meeting. We are happy to do that.

But at the same time we are going to do everything we can with Jay, Greg, myself, John Rielly, to get out and see investors one on one as much as possible so they really can get their questions answered and better understand our strategy and our commitment to it. The whole focus will be getting our capital expenditures under control. We have a plan for that and then it is up to us to execute it.

Okay. Thank you for the time.

Paul Sankey, Deutsche Bank.

Good morning, everyone. If I could just triangulate some of the things you have been saying, John, I think basically the long-term outcome from all these moving parts that were just referenced is that you will be cash flow, you said I think basically breakeven in 2014. And if I kind of triangulate that against another statement was you would be cash flow breakeven in 2014 on an assumption of a $90 to $100 Brent.

Let's just assume $100 Brent there.

Okay. So basically that is where we will end up once this whole process has kind of worked its way through. And that would be a 15% return?

I said our projects, Paul, when we invest money our hurdle rate is 15%.

Yes, I understand, okay. If we could just come back to the guidance for 2012 now on volumes, could you just run through the moving parts again? Because I guess at the simplest level you are at a much higher current level of production than what you have said you will achieve for the full year.

Sure, Paul. In the third quarter we are going to be impacted by the normal North Sea facilities maintenance, that happens every third quarter. But in addition to that we have a shutdown of the Llano Field for 45 days due to maintenance at the auger platform. And as well, as John Hess mentioned in his remarks, we now have a three-month shut in of the Valhall Field, so that is approximately 25,000 barrels a day that will be impacting us.

In addition, Conger is going to be down for maintenance as well at Enchilada in the third quarter. So what you are seeing from that guidance is an impact in the third quarter and then the fourth quarter production should be back where we are seeing it right now.

Okay. Then that hopefully can get me down to the, I guess it is the 405,000 upper end of the range guidance that you have got for the full year.

We are not guiding within the range, but it is 395,000 to 405,000. Again, you know we are coming into hurricane season and things like that, so from a guidance standpoint we feel comfortable now narrowing the range to 395,000 to 405,000 for the full year.

Great, thanks. I guess with the level of disposals that you are talking about it is going to be hard for you to talk about an outlook for volume growth. I wondered if you could -- and if you can talk about it that would be great, but I assume that it is going to be very tough with all the moving parts.

It does seem that you have stated quite clearly that you are very committed to the Bakken. Could you talk more about the volume outlook there for the longer term again for us? I am thinking back to my 2014 type balance cash flow. I just wonder what sort of volumes you're looking for now from the Bakken over the longer term. Thanks.

Again, Paul, while our 2013 budget, and that includes production, won't be finalized until later this year and I want to say again we are in the process of completing this comprehensive long-term development strategy now that we are nearing HBP for the Bakken. There is a lot of things to consider -- infill wells, the learning that we have gotten from all the areas that we have drilled in.

Again, the focus of that study is going to be to maximize profitability and improve capital efficiencies, so when the results of that study are done we are obviously going to use that to optimize the drilling program in 2013 and beyond. So not comfortable giving any kind of capital or volume estimates until we are really done with that study. We are at a point now in the Bakken where we have learned a lot and now it is time to look forward and say how do we really want to develop this asset.

All focused on capital efficiency and focusing on returns.

Okay. So we should think about the -- really as you stated, the primary balance here will be that you will be cash flow balanced in 2014, with the volume that results from that will be an outcome.

Yes, and the volume also that results from that will be a function of which assets we end up selling. I think that the important thing there is we deliver growth. Sometimes people say shrink to grow, that is not our case. I think that is more the case with the major oil companies that maybe have a little more challenge in their growth profile.

We can grow from our current base, but we got to spend a lot more money. By reducing our portfolio to the more profitable assets we still deliver pretty respectable growth; the exact number of that we can't give you until we get the asset sales behind us. But the key to that will be we will be able to live within our means and it deliver, I think, very attractive financial returns on a going forward basis as I said.

While the base of reserves and production going forward will be less subsequent to the asset sales, obviously, than they are now the profitability on our per-unit basis, the cash margin on our per-unit basis will be higher as we go forward. And I think that focus on profitability is the key take away here.

Okay, thank you very much.

Arjun Murti, Goldman Sachs.

Thanks. John, you mentioned the repositioning of Hess and the asset sales you are pursuing in your commitment to the basic strategy. Curious if you still want to be as globally diversified as you are right now, or could some of the asset sales you are considering, and it sounds like it could be more than the $1 billion to $2 billion that have already been outlined, could that exit you out of an area?

Do you want to be onshore US, deep Gulf, North Sea, Russia, Southeast Asia, West Africa, maybe in Australian? Do all those areas really make sense for Hess at its current size and growth and profitability aspirations?

Arjun, as opposed to look at it just purely geographically, I would look at it by asset and what the profitability and investment required for that profitability is by that asset. Sometimes it is a country, sometimes it is an asset within the country.

Obviously, we have a comprehensive program here and a number of the areas you mentioned are going to be considered within that bring more focus to our portfolio, to be more profitable so that then we can invest in the growth projects that deliver the best returns.

Understood. You mentioned the potential for CapEx to come down in 2013 and I think yourself and your colleagues gave some detail. But Utica Shale, if you have success that sounds like it could be additive; Knotty Head presumably will be sanctioned at some point in time; Australia LNG is a potential project. It feels like there could be additions as well, or perhaps some of us might be in the divestiture category.

Yes, Arjun, again, we would like to have a high-class problem that -- or opportunity I should say -- that some of the ones you mentioned would be sanctioned for development and investment because that would mean it has good returns. Having said that a number of the things we are selling will be getting rid of capital obligations in the future. So all of that is modeled into the guidance conceptually that we are giving you.

Got it. Makes sense. And just lastly, can you talk about hedging strategies going forward? You had some hedges; they rolled off; you added some this year. Will that be part of your ongoing program going forward?

As a general concept, we want to keep a strong balance sheet, live within our means, and be able to give our shareholders the benefit of oil prices. Obviously sometimes they go down, so you have to have a strong enough balance sheet and also live within your means to be able to absorb the ups and downs.

Having said that, as we looked at the funding gap that we had this year and the investment program we had this year we thought it very prudent to take the risk out of some of our revenues and cash flows to be sure that we can fund through the cycle. So hedging as a concept will always be an option for us. We only did it for this year.

We don't know where oil prices are going to be next year. We are not sure exactly where the asset sales are going to be, what our CapEx is going to be, even though it is going to be less of a funding gap next year. So it is an option that will always be on the table so we will consider it year by year.

Having said that, as we get our balance sheet in order, as we live within our means, we are going to be more able to absorb the ups and downs of oil prices.

Got it. Thank you so much.

Ed Westlake, Credit Suisse.

Great and congrats on the Bakken production trajectory and the overall volumes in the quarter. Just a quick follow-on from Arjun. Do you think you can get the CapEx with the sales in Bakken becoming more efficient below the $6.8 billion that you were originally going for this year?

I don't want to go there simply because they are moving pieces in the asset sales that we have, but by definition where we are right now is the peak of our CapEx and we are going to make significant reductions for next year. And when we are in a position to give you the details of that, which will be in that fourth-quarter conference call most likely in January of 2013, we will give it. But as soon as we are in a position to give that specific number we will give it to you.

Okay. Then two follow-ons for Greg. I don't know if you can share any of the latest Eagle Ford sort of IP rates from your recent wells, well costs, and if you have had any further wells drilled in the Utica.

Let me do the Utica first. So again, on the Utica we have got two wells in the ground. One was the well that we completed, remember, on our Marquette acreage; that was the 11 million cubic feet a day well. That well is on.

It is facility constrained, pipeline constrained, and producing about 3 million to 4 million cubic feet a day. Seeing very little pressure drop so it is a good well. It is a good, high rate well.

The second well that has been drilled is over on the far west and that is a CONSOL well. That well is waiting on rod pump artificial lift, so we will see what that well is going to produce, and then we are in various of drilling -- really both CONSOL and us in various stages of drilling additional wells. So no results to report on those yet just because we are still in the drilling phase on all of them.

I think just a general statement about the Utica; we remain pretty pleased and pretty optimistic. When you take into account what we have seen, albeit limited, and what industry is seeing, we still feel good about our acreage position in Utica.

In regards to the Eagle Ford, on our retained acreage, so this is the Cotulla area, we have now got 43 wells in the ground, of which 40 are now in production. Only 34 of these have 30-day IPs and those range between 250 and 650 barrels of oil equivalent per day. Production in June is averaging about 4,000 barrels a day net to us, and that is two-thirds liquid, so that gives you some sense or some color of the Utica results to date. I am sorry, the Eagle Ford.

Thanks, Greg. Just one smaller question around the Bakken in terms of its variability and working interest. Obviously in the first quarter it was low, in the second quarter it was high. How does that process work in terms of is it your choice, or is it around the working interest that the partners are taking in the wells?

Yes, it is a mixture of both because, of course, we -- as part of our lean manufacturing process we nominate or put wells in our schedule really about 18 months in advance. So we have a 12- to 18-month drilling schedule that we are planning to and, of course, in that we know the working interest assuming a certain level of participation by the other parties.

Now, if somebody elects to go non-consent on a well obviously that working interest will float up in that particular well. So our forecasts are based upon this 80% average working interest, which assumes that most of the partners participate in the well. Obviously if people elect not to that working interest will float up over time.

And as you are thinking about the 54 to 58 that potentially could be some upside if you could get a higher working interest in those wells, or is that sort of adjusted in the guidance?

Well, it is sort of adjusted in the guidance, but if you look at the annual impact of that it is going to be fairly small.

Okay, thank you.

John Herrlin, Societe Generale.

Some quick ones on the Bakken. You changed your completion techniques; any difference with EURs?

No, John, and we have done quite a study actually comparing plug-and-perf/hybrid to sliding sleeves and we see no difference. Now having said that we are still early in the type curve phase, but certainly there is no difference between the performance of the wells.

Are you engaging in controlled flow back techniques to increase EURs?

In the Utica or in the Eagle Ford?

Both.

Well, in the Utica, yes. What we do is we shut in the well for an extended period of time; the nature of the Utica is quite different than the Bakken. But in the Bakken, no, we don't.

Okay. In Ghana you had mentioned that Hickory was gas condensate. Is it retrograde?

Yes, it is.

And last one for me is Australia. Any other news with respect to that? You haven't mentioned anything.

Yes, so Australia we recently completed our appraisal drilling and testing campaign on our WA-390-P block. That appraisal campaign included four wells and five DSPs and has yielded some pretty important information for future development.

For example, we were able to successfully drill the first offshore horizontal well in Australia which will reduce the number of development wells required for the project and the DSPs also confirmed good reservoir continuity, high flow rates, and minimal contaminants in the gas stream.

One final point I would make is the Australian government has granted major project facilitation status to us and that really streamlines and assists in securing approvals in order up for a development decision to be reached. As has been ongoing for several months, as you all know, the commercial discussions with all the potential liquefaction partners are ongoing, so that is our next step really.

Are you thinking about bringing in an equity partner? We are seeing that with a lot of the deals for LNG in Asia. Are you considering that?

Yes, we are considering that. And obviously, like all LNG deals, typically you give a buyer a certain percentage of the equity and the gas.

Thank you.

Paul Cheng, Barclays.

Good morning. I have to apologize that I came in a bit late, so if you already covered it just let me know. I will check the transcript later on. Greg, have you given any well costs on the Bakken and Eagle Ford in the second quarter?

Yes, Paul, actually in my opening remarks. In the first quarter -- this is related to hybrids and sliding sleeves, so in the first quarter nearly 70% of our wells were hybrid wells with an overall average drill and complete cost of $13.4 million per well. Now during the second quarter only 40% of our wells were those hybrid so our overall average drill and complete cost was $11.6 million. So that is a reduction of 13%.

In looking forward to the second half, our HBP drilling will be substantially completed by year-end and then 100% of our wells will be sliding sleeve wells by the fourth quarter, which leads to an estimated drill and complete cost of under $10 million for the second half.

Okay. How about in Eagle Ford?

Eagle Ford we have seen significant cost reductions as we have taken over operatorship of the well. So if you look at the wells, currently we are about $8.9 million on 2012 drilling and completion costs in the Eagle Ford.

Greg, can you give us some idea how much you are spending, CapEx, in the Eagle Ford this year, Australian, and also Utica, as well as the infrastructure spending in Bakken this year?

Yes, I will pass that on to John Rielly, but the one thing I do want to say, Paul, on the Eagle Ford is relative to our 2011 performance, which was $10.3 million per well, we have already got those costs down to $8.9 million drill and complete in the Eagle Ford and there is more improvement under way as we speak. So that is the average cost; recent wells have actually been cheaper than that in the Eagle Ford.

Sure, that is great.

Paul, if I remember your question I think you asked for the Eagle Ford, the Utica, and Australia, so (multiple speakers).

And also the infrastructure spending this year in Bakken, the CapEx expectation I should say.

Sure. So in the Eagle Ford -- actually both the Eagle Ford and Utica there is some land costs as well in these costs, so not just infrastructure and drilling. But Eagle Ford is approximately $380 million this year forecasted, Utica is about $350 million forecasted of total capital spend.

In Australia beat forecast is $220 million for this year, as Greg was saying, finishing up the appraisal program. And as far as the facility costs or the infrastructure costs, all infrastructure costs, not just major, including the gathering systems that Greg spoke about, we are forecasting $760 million of facility costs in the Bakken this year.

John, so in theory you say that Bakken infrastructure costs will come down after this year, so should we assume going forward it will be $200 million or $300 million a year?

You have to get ultimately to a recurring number to get to that type of level, so we still do have to finish the Tioga gas plant, as Greg had mentioned in his remarks, so that will still be going on next year. Then it just depends on where the drilling is and getting the further gathering systems and pipelines in there. But we expect a reduction next year in the facilities and then you can see maybe a slow trend depending on the development program that Greg spoke about that we are looking into right now.

And, John, wondering then if you can share with us you are talking about there is $1 billion to $2 billion of potential asset sales that is currently under way of the negotiation. Let's assume that you is going to be actually complete, what is the production [won and] impact may look like?

Again, Paul -- and this question was asked before -- we can't give that kind of specific point until the asset sales are finalized and the terms are finalized. So we don't want to be in front of our blockers on this one, because some of the deals may not meet our expectations and we will do some other deals. Until all these deals are finalized, one by one when they are we will give you the details of that and then, obviously, you can update your production accordingly.

The key point is the focus going forward is going to be capital efficiency and profitability, and the things we are going to be selling are going to be more mature, not as strategic. We will still be global independent, but we are going to have a more profitable portfolio and invest in the capital projects that offer the best financial returns.

Okay, very good. Thank you.

At this time I would now like to turn the conference over to management for closing remarks.

That is it, that is fine. Thank you all for your attention.

Again, we have our strategy laid out. We are focusing on the capital expenditures and as we execute our strategy we are confident that it is going to create a lot of value for our shareholders. We appreciate everybody's interest.

Thank you for joining today's conference. That concludes the presentation. You may now disconnect and have a wonderful day.