赫斯 (HES) 2011 Q4 法說會逐字稿

Good day ladies and gentlemen, and welcome to the Fourth Quarter 2011 Hess Corporation Earnings Conference Call. My name is Erica and I will be your coordinator for today. At this time, all participants are in a listen only mode.

We will be facilitating a question and answer session towards the end of this conference. (Operator instructions). I would now like to turn the presentation over to your host for today's call, Mr. Jay Wilson, VP, Investor Relations. Please proceed.

Thank you Erica. Good morning everyone. And thank you for participating in our Fourth 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.

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

Thank you, Jay. Welcome to our Fourth Quarter Conference Call. I would like to review key achievements for 2011 and provide some guidance for 2012. Greg Hill will then discuss our Exploration and Production business, and John Rielly will review our financial results.

Corporate net income for the full year 2011 was $1.7 billion. Exploration and Production earned $2.7 billion, and Marketing and Refining lost $584 million. Compared to 2010, our results reflected lower crude oil and natural gas sales volumes, weaker refining results, and the impact of higher crude oil selling prices.

Included in our fourth quarter 2011 financial results is an after-tax charge of $525 million related to the closure of the HOVENSA joint venture refinery, which was announced last week.

In 2012 our Company's capital and exploratory expenditures are budgeted at $6.8 billion, with substantially all dedicated to Exploration and Production. Over the past several years, we have significantly increased our commitment to unconventionals to generate more predictable growth in reserves and production. 2012 we plan to invest $2.5 billion, or nearly 40% of our projected spend, in unconventionals. In addition, we plan to invest $1.6 billion for production, $1.8 billion for development and $800 million for exploration.

We expect to fund the majority of our 2012 capital programs from internally generated cash flow and asset sales. To protect our cash flow, we have hedged 120,000 barrels of oil per day, or approximately 45% of our forecasted oil production for the calendar year 2012 at an average Brent price of $107.70 per barrel.

In the fourth quarter, we agreed to sell our 3% interest in the Snohvit LNG project in Norway to Statoil for $170 million. This transaction will reduce our 2012 production by approximately 3000 barrels of oil equivalent per day, and is expected to close on January 31.

With regard to Exploration and Production, in 2011 we replaced 147% of production at an FD&A cost of approximately $36 per barrel. At year-end our proved reserves stood at 1.573 billion barrels of oil equivalent, and our reserve life was 11.4 years. Including last year's results, our five-year average reserve replacement ratio was 153% and our average FD&A cost is about $23 per barrel of oil equivalent.

In 2011 our crude oil and natural gas production was 370,000 barrels of oil equivalent per day, an 11% decrease compared to the 418,000 barrels of oil equivalent per day we averaged in 2010. Most of last year's production issues were due to short-term setbacks including weather-related delays in North Dakota, the temporary shut-in of the Llano 3 well in the deepwater Gulf of Mexico, a fire at the Valhall field in Norway, and civil unrest in Libya. We continue to make progress in restoring these lost production volumes.

In 2012 we forecast crude oil and natural gas production to average between 370,000 and 390,000 barrels of oil equivalent per day. This projection includes the sale of Snohvit, but excludes the impact of any other potential asset sales and any production that may result from the restoration of our operations in Libya.

Our sustainable long-term growth target for production and reserves remains 3% to 5% per year. However, if 2012 were used as a base which includes some residual effects from the production issues we experienced in 2011, we would project growth through 2017 to be in the range of 4% to 7% per year.

Last year we continued to grow our portfolio of unconventional resources. In the Bakken oil shale play in North Dakota, we generated strong growth throughout the second half of the year and exited 2011 at a peak net rate of approximately 50,000 barrels of oil equivalent per day. We maintain our 60,000 barrels of oil equivalent per day forecast for the Bakken in 2012.

We also plan to continue the appraisal of our acreage in the Eagle Ford Shale in Texas and the Utica Shale in Ohio.

Regarding developments, in the third quarter of 2011 we sanctioned the Tubular Bells project in the deepwater Gulf of Mexico. Hess has a 57% interest in the field and is the operator. In 2012, we will work with our partner Chevron to advance the project and we anticipate first production in 2014.

In terms of exploration, the Andalan number 1 well on the Semai V Block in Indonesia encountered reservoir sands and hydrocarbons, but not in commercial quantities. This well, along with a follow-up well, was expensed in the fourth quarter.

With regard to Marketing and Refining, our full year 2011 financial results were lower than 2010. Last week HOVENSA, in which Hess has a 50% interest, announced it will close the joint venture refinery in St. Croix, US Virgin Islands. The refinery has commenced shut down and will become an oil storage terminal.

Overall losses at the HOVENSA refinery have totaled $1.3 billion in the past three years, and were projected to continue. These losses have been caused primarily by the global economic slowdown and the addition of new refining capacity in emerging markets. In addition, the low price of natural gas in the United States put HOVENSA, an oilfield refinery, at a competitive disadvantage. HOVENSA examined every strategic option to maximize value, but ultimately severe financial losses left no other choice but to close.

In retail marketing, while 2011 convenience store sales and average gasoline volumes per station were both down 2%, reflecting the weak economic environment, year-over-year earnings were higher. Also, our Energy Marketing business delivered strong operating results, but earnings were lower than last year.

Our financial position remains strong. Our debt to capitalization ratio at year-end was 25%, essentially unchanged from year-end 2010.

2011 was a difficult year operationally, but important strategically. With the closure of the HOVENSA refinery, we have completed our transition to being predominately an exploration and production Company. Also, with the addition of our newly acquired a great position in the Utica Shale, the Company now has the critical mass for shale resources to make a significant contribution to our future production and reserve growth, with lower risk than has been the case historically.

Our principal focus in 2012 will be to execute our investment opportunities to sustain profitable growth and create value for our shareholders. I will now turn the call over to Greg Hill.

Thank you, John. My remarks will be primarily focused on our key investment priorities for 2012.

With regard to unconventionals, we built a very strong position in the Bakken oil shale play in North Dakota, and enjoyed significant competitive advantages in terms of scale, infrastructure and export capacity. In 2012 we plan to invest about $1.9 billion, and operate 16 rigs with five dedicated hydraulic fracturing crews.

We will continue to be in the HBP mode of drilling this year, with most of the wells planned to be single laterals on [1208 -- 80] acre spacing. This program will enable us to get the vast majority of our core acreage held by production by year-end 2012. We will also continue to invest in infrastructure projects, including the Tioga gas plant expansion and our crude oil rail loading and storage facility, which will become operational in February.

Net production from the Bakken in 2012 is forecast to average 60,000 barrels of oil equivalent per day, or double the 2011 average of 30,000 barrels of oil equivalent per day. We expect net Bakken production to further increase to 120,000 barrels of oil equivalent per day in 2015.

In the Eagle Ford shale, we plan to continue to delineate our acreage position, operating a three rig program and drilling approximately 25 to 30 wells in 2012.

Regarding the Utica Shale, our appraisal drilling program will be designed to delineate the oil, liquids and gas-rich areas on both our 100% owned acreage and that owned by our 50/50 joint venture with CONSOL Energy. On our 100% owned acreage, we plan to acquire 200 square miles of seismic and drill approximately 7 wells. The joint venture will also acquire approximately 200 square miles of seismic and plans to drill 22 wells. We'll also continue to pursue and delineate unconventional opportunities globally.

Now in addition to appraising and developing our unconventional portfolio, we will continue to invest in our conventional opportunities. Regarding the Valhall field in Norway, in which Hess has a 64% interest, a multiyear field redevelopment project is scheduled to be completed in the third quarter. This project extends the field life by 40 years and provides a platform for future growth in reserves and production. In addition to investments in facilities, BP also plans to operate two drilling rigs in 2012.

In the deepwater Gulf of Mexico we're progressing the development of Tubular Bells field, in which Hess has a 57% working interest and is the operator. Facilities construction is underway and drilling is planned to commence in mid-2012. First production is planned in 2014 with a peak annual net rate of about 25,000 barrels of oil equivalent per day.

In Australia we will complete appraisal of block WA-390-P by mid-2012 and aim to select the final liquefaction facility for the project during the year. Hess has a 100% interest and is the operator.

Regarding exploration, results in recent years have not met expectations. In response, we are decreasing the level of spend in 2012, reducing risk through strategic partnering, focusing on fewer geographic areas and strengthening our organizational capability. Exploration remains an important growth engine for the corporation, however, but we are committed to improving its performance.

In Ghana, we plan to commence further explanation drilling in the first quarter of 2012, following up on the previously announced Paradise discovery on the Hess-operated deepwater Tano Cape Three Points South block. Our 2012 drilling program will target several other geologic structures and play types on the block.

In Brunei, we plan on continue drilling in 2012 on block CA1 in which Hess has a 13.5% interest. Although the first well, Julong Centre, failed to find commercial hydrocarbons and was expensed, we remain optimistic about the overall potential of the block.

In Kurdistan we plan to commence seismic acquisition on the Dinarta and Shakrok blocks in mid-2012 and progress drilling plans for 2013. Hess has an 80% interest and is operator of these blocks.

In the deepwater Gulf of Mexico we're advancing a number of Miocene prospects to drill-ready status, and plan to provide additional details regarding this program later in the year.

In closing, while we experienced a tough year operationally in 2011, we remain enthused about our portfolio of investment opportunities. And I want to reinforce what John said in his opening remarks. Our principal focus in 2012 will be to execute.

First, deliver on our production and reserve growth targets; second, manage our operating costs and capital expenditures; and third, improve exploration results. Thank you. I will now hand the call over to John Rielly.

Thank you, Greg. Hello everyone. In my remarks today I will compare fourth-quarter 2011 results to the third quarter.

The Corporation generated a consolidated net loss of $131 million in the fourth quarter of 2011, compared with net income of $298 million in the third quarter. Excluding items affecting comparability of earnings between periods, the Corporation had earnings of $394 million in the fourth quarter of 2011 and $379 million in the third quarter of 2011.

Turning to Exploration and Production, Exploration and Production had income of $527 million in the fourth quarter of 2011, compared with $422 million in the third quarter. Third quarter results included net after-tax charges of $81 million from items affecting comparability of earnings between periods.

Excluding these items, the changes in the after-tax component of the earnings are as follows -- higher sales volumes increased earnings by $155 million. Higher selling prices increased earnings by $39 million. Higher exploration expenses decreased earnings by $142 million.

Higher DD&A decreased earnings by $40 million. All other items net to an increase in earnings of $12 million, for an overall increase in fourth-quarter adjusted earnings of $24 million.

Our E&P operations were over lifted in the fourth quarter compared with production, resulting in increased after-tax income of approximately $40 million. The E&P effective income tax rate was 38% for the fourth quarter and the full year of 2011.

Turning to Marketing and Refining, Marketing and Refining incurred a loss of $561 million in the fourth quarter of 2011, compared with a loss of $23 million in the third quarter. Fourth-quarter results included an after-tax charge of $525 million related to the announced shutdown of HOVENSA's refinery in St. Croix. This charge includes estimates of the Corporation's share of future funding commitments for preserving assets, severance and other costs related to the shutdown, of which approximately $400 million is expected to be funded in 2012.

Excluding the refinery shutdown charge, the Corporation's share of HOVENSA's results of operations was a loss of $65 million in the fourth quarter of 2011, compared with a loss of $36 million in the third quarter. Port Reading had a loss of $6 million in the fourth quarter of 2011 and broke even in the third quarter.

Marketing earnings were $48 million in the fourth quarter of 2011, an increase from $41 million in the third quarter, principally reflecting higher earnings in Energy Marketing. Trading activities generated a loss of $11 million in the fourth quarter of 2011, compared with a loss of $26 million in the third quarter.

Turning to corporate and interest, net corporate expenses were $40 million in the fourth quarter of 2011 compared with $44 million in the third quarter. After-tax interest expense was $57 million in the fourth quarter and third quarter of 2011.

Turning to cash flow, net cash provided by operating activities in the fourth quarter, including a decrease of $275 million from changes in working capital, was $1.138 billion. Capital expenditures were $2.115 billion. Borrowings were $458 million.

All other items amounted to an increase in cash of $43 million, resulting in a net decrease in cash and cash equivalents in the fourth quarter of $476 million. We had $351 million of cash and cash equivalents at December 31, 2011 and $1.608 billion at December 31, 2010.

Total debt was $6,057,000,000 at December 31, 2011 and $5,583,000,000 at December 31, 2010. At year-end 2011, we had more than $3.8 billion available on our revolving credit facilities. The Corporation's debt to capitalization ratio at December 31, 2011 was 24.6%, compared with 24.9% at the end of 2010.

Turning to 2012 guidance, net corporate expenses in 2012 are estimated to be in the range of $160 million to $170 million. We expect our 2012 after-tax interest expense to be in the range of $245 million to $255 million.

For full year 2012 unit costs, our E&P cash operating costs are expected to be in the range of $20 to $21 per barrel of oil equivalent produced. Depreciation, depletion and amortization expenses are expected to be in the range of $20.50 to $21.50 per barrel, for total production unit costs of $40.50 to $42.50 per barrel. We currently expect our E&P effective tax rate to be in the range of 36% to 40% for the full year of 2012. Both cost and tax rate guidance exclude the impact of any Libyan operations.

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

(Operator instructions) Doug Leggate, BofA Merrill Lynch.

Thank you. Good morning everybody. I'm going to try three quick ones, if I may.

On the production guidance, John, can you quantify the impact Valhall down time? Conversely, Bakken looks pretty strong if 60,000 is the average for the year. Can you give us (technical difficulty) and your anticipated exit rate will be or should be in 2012? And then I have a couple of quick follow-ups, please.

You broke in and out a little bit. I just want to get clarity on the three questions, please, just repeat them real quick.

I'm sorry. Can you hear me better now?

Yes.

Okay, I picked up my handset now. I only asked one, John, I'm going to do the two afterwards. So, the first one was can you quantify the Valhall down time given the maintenance that they tie in your planning in the third quarter?

And the Bakken looks strong at 60,000 as an average. So can you give us an idea with the exit rate was in 2011 and what your expectations are for the exit rate in 2012? And as I say, I have a couple of quick follow-ups.

On Valhall we have a 30 day shutdown, so it we will be approximately a month that it will be in the third quarter. So, from a production standpoint, Valhall's productive capacity is above 30,000 barrels a day, so it will be shut down during that period in the third quarter. We're not exactly sure what the timing will be. So, you will see the impact in the third quarter of about a month shutdown.

And the Bakken exit rates?

I'm going to turn that over to Greg.

Yes, let me provide a little context on the Bakken first that John briefly mentioned in his opening remarks. So, first of all, production from the Bakken has fully recovered. And we're firmly on the growth ramp, with production averaging about 38,000 barrels a day in the fourth quarter, which is an improvement of about 6,000 quarter on quarter.

And as John mentioned, we achieved a new high peak rate of just over 50,000 barrels a day in mid-December. Now, as you all know, because of the timing of new completions where you get flush production followed by steep declines, daily production will fluctuate. However, these increasingly higher peaks, continued quarter on quarter improvement, and continued reduction of the completion backlog due to the addition of our fifth frack crew in Q4 give us pretty high confidence in our ability to achieve that 60,000 barrel a day average rate in 2012.

Doug, as you know, we don't really quote exit rates for prospectively, but the one thing I will say is we're in good shape at the year-end 2011 to continue to build that ramp in 2012.

Great. My second one is actually fairly quick. Greg, can you comment on the result of the Marquette well that had been drilled in the Utica? I believe you were going to try to complete that in Q4. Any results you can share?

Yes, Doug, I can. So, again, just a little bit of context on the Utica for others on the call. We're up to about 198,000 acres now in the Utica Shale, so we're very pleased with our early entry into that position and feel like it's a strategic acreage position in an emerging unconventional play.

Remind everybody most of the land is either owned in fee or held by production, with the balance being under long-term leases. And finally, the acreage has very high net revenue interest, so, again, a very nice position in an emerging play.

You know, regarding the well, we recently completed that well in December that was drilled by Marquette prior to the acquisition. The well was drilled in a dry gas location. We knew that, but it was ready to complete, so we went ahead and completed it.

And while we are still testing the well, we can report that the initial rate from the well was 11 million cubic feet per day on a [2464 choke]. So that's a very good result. We're very pleased with that result.

It's very encouraging, but obviously there's a lot more appraisal drilling necessary to delineate our acreage position, and in particular to figure out where the oil condensate and dry gas windows are.

So that's a 24 hour rate?

Yes, that's initial rate.

Great. My last question and I will jump off is really on risk in terms of -- it's really quite comforting to hear your comments about (inaudible) risk. So this one is really for John.

John, what is behind the change of view on hedges? And if you could also talk about what your future thoughts are on taking working interest levels in exploration wells, are we now moving away from 100% working interest on big wells? And I will leave it there. Thank you.

Sure, Doug. I'll first talk about the hedges. Hedges were put on in order to protect our 2012 cash flows, I mean, as you know, during this period of higher capital and testament for our unconventional business. So, again, it's just to deal with the capital spent for the unconventional business.

It's a volatile cyclical business and we wanted to protect our cash flows during this period. And then I will turn it over to Greg to talk about exploration.

Yes, Doug, as I said in my opening remarks, one of the changes we're making to our exploration program is that we are going to take on more strategic partners. So that is code for -- get our working interest down. You know, we're actively working a number of partner discussions in Ghana, in the Gulf of Mexico, so that is all part of our strategy.

Great. Thanks very much indeed.

Evan Calio, Morgan Stanley.

Good morning guys. Thanks for taking my call. Maybe I'll start on the downstream, given the recent HOVENSA announcement.

I understand that you intend to take Port Reading down FCCU for maintenance in early February. Should we expect to restart there in four weeks? Or is there maybe a broader strategic review related to viability asset versus required CapEx, and particularly following HOVENSA closure and very minimal CapEx allocation in the downstream into 2012?

Right. Well, Port Reading represents a much smaller part of our portfolio than HOVENSA does.

Sure.

And we plan to operate the facility as long as it generates acceptable financial returns. In regards to its current operating problems, they've had some catalyst losses and are evaluating different options, which probably include a short-term shut down to restore normal operations.

So, those plans are being formalized. The time that it will be out might be about three weeks. But that has not been finalized yet as that's the option that is going to be pursued, but it is looking that way as of right now.

But the bigger picture thing about the strategy is that obviously, with the move in HOVENSA, we've become and we've completed our transition to predominately an E&P Company. And Port Reading itself -- smaller part of the portfolio and we'll run it as long as it generates acceptable returns.

I think another point, just to provide clarity, is that our marketing businesses -- both Energy Marketing as well as Retail Marketing -- are a long-term strategic part of our portfolio. They generate strong financial returns and offer selective growth opportunities. So in terms of the sizing and shape and focus of our portfolio going forward, marketing will still be a key component of it.

Great, I appreciate that. Another question on the upstream and relating to Eagle Ford, I know you updated us on the pace of activity in 2012. But how do you -- given some portfolio rationalization or some de-risking, how did you view this asset within your portfolio over the longer-term? Is it a position you feel has sufficient relative scale or is it for potential divestment or a growth opportunity? How are you thinking about the Eagle Ford here?

Yeah, thanks Evan. You know, we're really not in a position to answer that question yet because we're still in delineation mode. So our current focus remains on continuing to delineate our acreage, particularly the Northeast as we move into 2012. And we're pleased with the results today.

We've got 109,000 net acres in the Eagle Ford. We drilled 29 wells. We've got 22 completed and on production now, 18 with 30-day IP rates. And those are ranging between 350 and 650 with an average of about 500. So, you know, so far so good on the Eagle Ford.

If I could just slip in a last -- just question if you could give us a quick update on the Bakken rail transloading facilities and if we started railing barrels out of the Bakken yet?

Yes, so the facility will be fully operational at the end of February. We've got nine train sets on location, which will give us an initial capacity to ship of 54,000 barrels a day. Now, just to kind of test the rail and all that kind of stuff, we did sell five trainloads of Bakken crude and achieved some premium Gulf Coast sweet crude pricing.

That's good. Good. Thank you.

Paul Sankey, Deutsche Bank.

Thank you good morning everyone. John, it interesting that you decided to hedge this quite significant proportion of your production at $107.70, I believe you said, for 2012. When we look at your CapEx for the year upcoming, and the cash flow that you made in 2011, there still seems to be a significant disconnect.

That is to say, at an average of about $110 Brent in 2011, your cash flows came in at about $5 billion -- around $5 billion depending on what we include and don't include. You've got more like a -- well above $6 billion spend for 2012.

The fact that you're hedging suggests that you like $107 as an oil price. You consider it to be an attractive price to sell at. Can you just square the circle in terms of how we get to living within your means, I think was always the line for the spend in 2012, and what we should assume you're planning the Company at from an oil price point of view, and any other observations you have? Thank you.

No, it's a very fair question. Obviously during this period where we are having these high investments made, driven from predominantly by the attractive opportunities we see in the unconventional space, led by the Bakken. And also in light of the uncertain economic environment we're in, it's not so much that we're making an oil price call per se, but we thought it prudent to hedge some of our production for 2012. And mind you, it is just for 2012 that we're talking about, to protect our cash flows.

And between our internally generated cash and the asset sales that we have contemplated, most of that gap should be covered. We feel very comfortable with our liquidity. Obviously in the capital intensive business we're in, and the commodity business we're in, it's important to have a robust, strong balance sheet and financial flexibility. We will do what we have to do to ensure that.

And between the asset sales that are contemplated, that we will update you on as the year proceeds, and the internal cash flow protected by our hedges, we feel pretty good about our liquidity situation, the ability to fund the majority of that capital.

Great, thank you. So the majority essentially will be an asset sale process, if I'm not wrong?

Yes, there are more asset sales contemplated. And as we progress those we will give you updates will give you updates as appropriate.

Great. And then if we move on to the volume guidance, if I'm not wrong, it's a range of zero to 5% year-over-year. Would we expect you to get back to a 3% to 5% from the base in 2012 longer-term now, given that there was the significant step down in 2011? But we've still retained, if you like, around a zero to 5% growth as a safe for 2012?

Yes. The first point there is that Libya, as you know, just to be clear, is not in the numbers. Libya is currently producing. We want a little more political stability to be shown in terms of conditions on the ground before we would feel comfortable putting that in the numbers. So that is one component that's out of the numbers that makes the numbers lower, but we think it is prudent to treat it that way right now.

And the longer-term will remain a 3% to 5% (multiple speakers)

Yes. Our long-term rate is 3% to 5%, but we wanted to make it clear for people that given that we had these setbacks last year, that 3% to 5% is not on the lower base. If you talk about the lower base using 2012 and you look over the next five years, the production and reserve growth rates that we're looking at, underpinned by our investment in our conventionals as well as the conventional opportunities that we have, is really more in the range of 4% to 7%.

But to be very clear, our long-term rate, once we restore ourselves to the production trajectory that we have envisioned, is the 3% to 5%. So that's the reason we tried to make it more clear for people, not confuse people. If you look at 2012, let's face this, 4% to 7% over the next five years, if you look at that longer-term rate once we restore the production volumes lost, the normalized rate is really the 3% to 5% production reserve growth target.

That is clarifying. Thank you, John. And then very finally from me, the status as a US E&P would potentially be advantageous to you from a tax and accounting point of view. Does the retention of Retail prevent that? Can you just clarify exactly what your status would be, because I think you said quite clearly that you want to retain the Retail as part of Hess' overall operations? Thank you.

That is correct. We're intending to keep Retail Marketing and Energy Marketing as a long-term strategic position in our Company.

Thank you.

Arjun Murti, Goldman Sachs.

Thank you. Just at least one longer-term question here. Given the comments you made on exploration and the change in emphasis there, is there a corresponding change in emphasis in how you think about acquisitions?

You've done a number of, let's just say joint ventures or kind of acreage type deals, but they're kind of more classic acquisitions. I think really since Triton, which I think is now 11 or 12 years ago, you've not participated in a meaningful way in the acquisition market. How do we think about that being a part of Hess' strategy going forward? Thank you.

Arjun, you know, obviously you're always looking at outside opportunities to see if they upgrade your portfolio. At the same time with the capital commitments we have, both in unconventional and conventional investments for 2012, our focus is going to be on executing those investments to deliver the profitable growth that we are aspiring to.

And I think, John, it's probably fair to say that relative to the lower 2012 number, the 4% to 7% growth is all from stuff you have in hand, whether it is Pony, Tubular Bells, Bakken and so forth. I guess the question then becomes does the Eagle Ford work? Does the Utica work? And then, do you have enough of an inventory beyond that?

That, I presume, is then how you think about the toggle of acquisitions needing to play a greater role.

Yes.

Point being you've got the next four or five years kind of lined up, but then you do need some of these other things to work out if you're going to perpetuate this longer-term.

Fair enough.

Exploration.

The Utica really, God willing it works out, and as Greg pointed out, we're encouraged by the first well. But we've got upwards of 25 to 30 wells to go in 2012 to give us a better feel for the opportunity that we have here. We need to appraise it.

But if you look at our growth rate, the majority of that growth rate has been secured or ready because of our work in the Bakken, what we think we're going to get it out of Valhall, Tubular Bells. You listed the different options there. So it's not wishful thinking in terms of how are we going to secure that growth rate.

We've really secured those investment opportunities already, and the key now is to execute and deliver performance from them. Obviously if we're lucky enough to get some upside on that, all the better. Exploration is delivering better performance in the longer-term, all the better.

But acquisitions are not part of that production growth. It's really from the internally generated opportunities we already have in our portfolio.

That's terrific. And sorry for another hedging question, but should we expect you to have some decent portion of your production on a rolling forward basis when we get to the end of this year? It obviously depends on price to some degree, but is this part of your ongoing strategy now?

It is something we will always consider as a way of reducing the risk and securing our cash flows. This was more a 2012 decision in terms of, we think, a prudent -- given the uncertain economic environment that we're in, and also the high capital spend, for us to take some insurance out. At the same time, it is not indicative of what we're necessarily going to do in 2013 or future years.

Thank you. And then just a last one just on the Bakken, I believe you are sticking with plus or minus the 16 rigs for this year. And I understand it's more about holding the acreage, so you're not doing the dual laterals or being in manufacturing mode. Can you just remind me when you get through that, and then where you think that rig count can grow once you get to kind of -- let's just call it manufacturing mode for your core areas of the Bakken?

Yes, Arjun, I think for this year again, as you mentioned, we're an HBP mode with 16 rigs. We will get through all of that during 2012. 2012 is really -- let's get all of our core acreage held, particularly the stuff that we picked up in acquisitions from Tracker and American Oil & Gas.

After that, we'll be back into pad drilling and our long-term development strategy. Right now, we'll say we'll do that with 16 rigs, but that is subject to change. It could be more. It also depends on infill. There's a number of factors that could drive that rig count higher. (multiple speakers)

I'm sorry to interrupt. To hit your long-term Bakken targets, we assume present you'll have to drill. You'll have to use additional rigs, unless there's something in there that the IP's are coming in better or the EUR's are coming in better. We assume you'll need more rigs to get to your longer-term targets. Is that fair?

No, you shouldn't. Basically the 120,000 barrels a day is premised on a continuous 16 rig program through 2015.

That's very helpful. Thank you so much.

Paul Chang, Barclays Capital.

Great. In Bakken in the past, you've given some well data. Now that you should have more well data under the 38 stage frack, can you give us some data and what is the 30 day IP on those? And if you have any better indication that what is the recoverable rate (inaudible) that you're going to be and also the cost right now?

Yes, sure. Let me kind of hit all three of those, Paul. So first of all on the well rates, we've got 113 34-plus stage systems installed in the Bakken with 76 on production now. And those wells have 30 day IP's that are continuing to average 1000 barrels a day. So we're very pleased by those results.

And as we continue to improve our subsurface understanding, of course, we'll optimize those frack stages and designs to maximize profitability. So, areas with very good rock, we may reduce the number of frack stages from 38 to something smaller as a way to maximize their profitability.

Well cost, while we are in HBP mode, still about $10 million per well. One thing that I think people sometimes don't remember is that first well that you're drilling in this HBP mode carries a lot of the cost, because we build the pad for six to eight wells. We bring up the infrastructure to the well pad, getting ready for that pad drilling. So, $10 million is still a pretty good HBP well cost.

Regarding the EUR's, we're still sticking with the 550 for now. We're just waiting to get enough statistical data to have confidence to increase those EUR's.

And Greg, do you have a cash operating cost on those wells that have been running for more than 30 days?

Paul we -- (multiple speakers)

On a BOE basis?

I'm sorry, Paul, we don't give that kind of detailed data on the individual assets, but you can see our cash operating costs have been relatively flat; actually dropped a little bit in the fourth quarter. And guidance for next year is relatively flat on an overall basis for the portfolio on a cash basis, and that is with high commodity prices, so we are affected by higher production taxes.

Okay. This is also for Greg. Greg, you have said that you want to lower your future risk on the exploration front, so two questions on that. One, you still budget for $800 million for this year, and you probably do say based on your estimate midpoint 380,000 barrels per day for the year, you're going to do roughly 140,000,000 barrels.

And so that means that you're spending about $6 per BOE of your production, give or take. Do you think that, given your focus on conventional oil sites, that seems to be still a bit too high? Secondly, on that base, in Indonesia in deepwater, are you still going to drill the next well if you cannot find a partner?

Let me speak to the Indonesian well first. So this was the Semai V well. Recall that block has a three-well commitment. We drilled two wells.

The first well was the deep well, the Semai V well, whereas John mentioned in his opening remarks we did find a significant amount of sand and we did find hydrocarbons. It just wasn't -- and saturations just weren't commercial.

So actually, from a geologic modeling and for this giant basin in the Banda Arc, I'm actually pleased with understanding that well. The second well was a shallower well that we drilled, a commitment well. Third well we have to discuss with the government just to basically understand all the data.

So are you still going to drill the third well?

Don't know; subject to discussions with government.

Okay. Two final questions. One for John Rielly. John, your US cash tax, what is the percent of the IPD that you can (inaudible) or you can use? And are you paying any US cash tax? And what may that look like in 2012?

And then the last question is that, Greg, can you give us an idea that -- where is the process of the Ghana (inaudible). You closed the data room on the 15 by now, that you are still under evaluation. Is that because you have too many bids, or you don't have enough bids? Just give us some idea of what that (inaudible) that it may take a bit longer before you come to a conclusion on that.

Okay, Paul, so I'll start with your question on the IDC in the US. So as an integrated oil Company, we can write off or expense 70% of our intangible drilling costs in the year that it's incurred. So from that standpoint, as Greg has mentioned, Greg and John talked about our unconventional budget, we have significant drilling going on obviously in the Bakken, Utica and Eagle Ford.

So, of the well costs that relate to IDC we can take 70% of those costs. The remaining 30% then is amortized over five years. So it does provide us significant deductions in the US and that will continue in 2012.

John can you give us -- what estimate, how much is spent? Is that -- of the drilling cost, how much is IDC?

Of a well -- it differs per well, so it can be anywhere from 65% to even up to 90% of a well cost, somewhere in that range from an overall standpoint.

Thank you.

Okay, Paul, in regards to the Ghana well, we have a number of interested parties in the well. We're evaluating all of the offers and are in discussions with multiple parties.

Any rough timeline when you may come to a conclusion?

Well, I mean, we're going to start drilling late first quarter or early second quarter, so we'd like to have our partners before we start drilling the well.

Thank you.

Mark Gilman, The Benchmark Company.

Good morning. I had a couple of things. Greg, could you give us a little bit of color on the CA1 well? You know, I think it was considered to be really more of an appraisal than necessarily a wildcat, in terms of what you learn from it.

Yeah, thanks Mark. The first well that was drilled where -- it was called the Julong Centre well. And that was chosen by the operator to test the aerial extent of a very large structure (inaudible). So although the well failed to encounter commercial quantities of hydrocarbons, we remain encouraged by the potential on the block.

Obviously there's some direct offsetting structures that come down from the [Kekay and Gumasu]. This was designed to test something else that was a look-alike basically. So the current plan is to drill five additional wells on that block, and in fact the drilling rig is en route to begin drilling the next well, which is called Ju Long East.

Okay. If I could go to the Bakken for just a sec, Greg, I think I saw something that suggests you've relinquished a pretty good slug of what had been your pre-existing position. And you're down to something in the neighborhood of 650,000 net. Could you confirm if that is accurate, and any thoughts you might have as to what the ultimate spacing is going to be, in terms of what you're going to do when you get to a pad drilling kind of environment?

So thanks for that, Mark. Our acreage position is still around -- just under 900,000 net acres. Now we've always said that we believe about two-thirds of that is core. And as we continue to focus on our core acreage, we'll divest or we'll let leases expire that we don't consider optimal to our development. But we're still close to 900,000 acres today.

And the spacing question?

You know, we've got a number of spacing pilots underway; too early to draw any conclusions. As I've said before, Mark, my gut is that you're going to go to a tighter spacing on the Bakken ultimately.

Okay. John Rielly, I am curious as to what you need to do, from an accounting standpoint, in terms of lease amortization with respect to the Utica acreage that you acquired. Is there a clock that starts running that says so much of that has to be amortized over the term of the lease?

Basically what happens is, as we drill we will allocate acquisition cost from that acreage to the wells. And it will flow through our DD&A as the wells are drilled. So there will be a higher DD&A on those wells. And that's the same for the JV and our 100% owned acreage.

But you don't have to separately amortize the acquisition cost?

No, we don't have to separately amortize it. Let me just talk about DD&A in general for the portfolio. So, I mean, I just want to point out that the majority of our production as liquids, right? So in general, our unit cost, because our production is focused on the liquids side, is going to be higher because it costs more to produce oil than it does natural gas. But obviously in this environment, it generates much higher margins.

So from an overall standpoint, just while you're on that point, from the acquisitions that we have related to Utica as well as in the Bakken, our DD&A costs are moving higher from 2011 and into 2012 primarily due to those significant upfront investments in the unconventionals. So besides the acquisition costs, it includes large infrastructure investments, and so we believe these will create shareholder value for many years.

So what happens is the initial DD&A rates, they are high because the reserve bookings lag the investment dollars. But the life of field rate is expected to be much lower. So that is the reason from an overall standpoint on our DD&A costs.

Okay. If I could just probe the asset sales question a little bit, strikes me that a potential candidate might very well be your mature UK North Sea assets. Am I on the right track in that regard?

We're not going to comment on speculated or prospective sales, Mark, for obvious reasons. But, as we make progress on some of these asset sales, we'll inform investors appropriately.

Okay, and Greg, my final one -- just to clarify your comments about Julong and Brunei. The well that you drilled was not testing the offsets to Kekay, but rather a look-alike prospect?

Yes, that's true. So it was not testing the offsets. It was actually testing another structure that had a similar look as Kekay and Gumasu. Very long structure; the well was drilled all the way out on the very far area of (technical difficulty) of the structure. It had hydrocarbons in it, but just not in commercial quantities.

Okay. I'm going to sneak in just one final one. Any interest that you've observed in terms of the intent to farm out an interest in BMS 22? But I think the partners have agreed to take a look at that for the purpose, potentially, of drilling another well or two.

So the data room was open. That farm out process is closed now. The partners are due to meet in February to discuss options and a plan forward. Beyond that, you will have to refer to Exxon, Mark.

Thanks, guys.

Blake Fernandez, Howard Weil.

Good morning guys. Thanks for taking my question. I was hoping maybe you could elaborate a little bit on Libya. If I heard you correctly, it sounds like you're not currently producing from there, which I guess I'm a little confused. I thought that field was back online at least to a certain extent.

And on that front, if you could also just kind of give us some clarity on getting back to peak production. I mean there is there capital investment required? And if so, is there any kind of discussion on renegotiation of fiscal terms?

Fair enough question. No, Libya is producing and I think the gross rate of Waha or Oasis in English, the name of our concession, is about 200,000 barrels a day. So we have about 8% of that. And I think the number is about 13 or so.

But in terms of forecasting the volumes in our production forecast, we don't feel comfortable putting that in yet. So it is producing. And in terms of reentry, we're talking to our partners and the Libyan National Oil Company about that.

Everything is encouraging, but there's still a long way to go to iron out a lot of the details. As you can well understand, they are recovering from a civil war. So it's going to take some time to provide more clarity that you are looking for. We are looking for the same clarity that you are.

Great. That's helpful. Thanks.

And the only other one I have for you, on CapEx I know you've given us '12 guidance here. But in order to achieve this 4% to 7% growth through 2017, can you give us just a general feel of what kind of number we should be looking at post-2012? Is that like a roughly a $6 billion type of number?

Again, we'll give you the update on 2013 as we get closer to '13.

Okay, thanks a lot.

Ed Westlake, Credit Suisse.

Yes, just two questions. The 4% to 7% volume growth, have you put anything in there for Libya for Australia LNG?

Yes, we do. Over the longer term we are projecting in that forecast that we will get the Libyan volumes back on. So, again, that's what -- as John was talking about before, just trying to take those temporary setbacks out of that. As far as Australian LNG at this point, no. We have that further out so that is not in that number.

Okay, good. And then just coming back to Bakken well costs, obviously $10 million today but in HBP drilling, what sort of scale of cost reduction do you think you can achieve from a change -- as you move to pad drilling and maybe sliding sleeve? And the other question is what are you seeing in terms of pricing, particularly on the pressure pumping side given gas markets are weak; any improvements?

Yes, let me address the pressure pumping question first. Just for clarity, all of our rigs are full time pressure pumping services. So that's the five frack spreads are locked in under the longer-term contracts.

So, we don't anticipate significant cost increases in 2012, other than those things that fluctuate with commodity prices, because that's the way the contracts are written. So fuel and chemicals and things like that are allowed to float and are negotiated, obviously, you know, with commodity prices. So that is kind of what we see there.

And on the ability to reduce costs as you shift out of HBP?

Yes, well costs, again, I think these HBP wells, they are heavy loaded because you do build a big pad and you build the road to the facility, and you build the piping up to the edge of the pad. As we get into lean manufacturing and pad drilling, I can expect we can bring that well cost much closer to [9] and also sliding sleeves as well.

Thanks very much.

Pavel Molchanov, Raymond James.

Yes, thanks very much. On the Utica, do you guys expect any permitting difficulties as you expand your footprint in the play?

No, we're engaging with all of the authorities as we speak along with our partner CONSOL, and so far we haven't encountered any permitting difficulties whatsoever.

Okay, good. And a similar question, different geography, anything new that you're hearing happening in the Paris basin, on the regulatory front in particular?

No, I think as we said before, we're in the midst of a presidential election, so we don't anticipate any major breakthroughs until after that presidential election. But our plans for the Paris basin this year are to commence drilling conventional wells later in 2012. These wells are going to be non-fractured vertical wells design to obtain maximum subsurface data.

Now, how do we feel about the Paris basin? While we believe it will take time to work through the issues, we're confident of course that drilling in completion operations can be done safely and responsibly. So, we remain very actively engaged with local and national stakeholders to progress the appraisal of those licenses.

Okay. And then just last quick one, having appraised your initial discovery in Ghana, any sense of the pre-drill resource estimate for the follow-on well?

No, there's not. So Paradise itself, it's going to require another appraisal well to figure out how big that is. What we do know is we've got good sand, and we've got oil, and we've got gas condensate in on that reservoir.

Very good, thank you.

Faisel Khan, Citigroup.

Thanks, good morning. Given your desire to de-risk your exploration program, how should we expect or how should we look at your exploration expense or exploration capital trending over the next couple of years?

It's similar to the capital expenditure point for 2013. We'll give you an estimate on that as we get closer to 2013.

But Greg's comments were the key ones, which is we need to improve the performance of exploration. And as a consequence we are downsizing the dollars, and also bringing in strategic partners, bringing more focus and also strengthening our organization capability, all in the interest of improving the performance of that. But to be clear, exploration is a long-term strategic part of Hess.

Okay. And you talked about needing to hedge out your production for this year to protect your operating cash flow for your CapEx program. And you talked about kind of this peak level of CapEx that you have for this year, and I don't know for how long, but how long do you expect this sort of peak capital intensity to continue in your unconventional program?

The same question answer that I gave before. We're just focusing in on '12. We're not making any forecasts for '13 or '14.

Okay. Then the $36 F&D costs that you guys reported last year, do you think that number is the right number going forward? Or is that going to trend down over time?

In 2011 our FD&A costs -- I mean, again, it increased primarily as a result of the shift towards unconventionals which, as I mentioned earlier, require significant upfront investment in the acreage, infrastructure, and drilling.

And so if we are going to talk about just one year, to your question, I just want to give you some additional context. So included in the 2011 FD&A cost was $1 billion of acreage acquisition costs in the Utica in Kurdistan, which added no reserves last year, as you would expect. But over time, obviously, as we drill it up we'll be able to book those reserves.

In addition to that, we had PSE effects which resulted in negative price revisions of 25 million barrels. So if you're just looking at one year, if you were to exclude these items, our F&D cost would've been approximately $28 per barrel.

And then as John Hess had mentioned earlier, I mean that's where we look at this more from a long-term standpoint. Our five-year average replacement ratio was 153% at an FD&A cost of $23 per barrel.

Do the infrastructure costs in the Bakken, the processing plant and the rail terminals, do those go into that F&D calculation?

Yes they do.

Okay, and how much was that number last year?

We've been running approximately $400 million in the Bakken for infrastructure-related costs.

Does it ever make sense to kind of offload those sort of costs to infrastructure players?

Again, we're managing our growth right now, and with the amount of growth and the upside that we see in the Bakken, we like having those facilities in our portfolio.

Okay, I was just thinking from a cost to capital perspective. Obviously guys who have pipelines in infrastructure have a much lower cost of capital than upstream companies do.

That's a fair question, but you also have to understand the scale of our infrastructure gives us a competitive advantage in terms of the development of the Bakken itself. So it's actually a strategic advantage to create value for shareholders that we actually hold onto the infrastructure.

Okay, fair enough. Thanks for the time.

John Herrlin, Societe Generale.

Hi. Some quick ones. Regarding proppant, any problems acquiring it for the unconventional plays?

Yes, John, I think we did see some tightness in the Bakken market this year on proppant where we couldn't get enough white sands, so we had to switch to some medium strength proppant. I think you're seeing -- as the gas rigs fall off and whatnot, we think that's going to ease the tightening.

Okay. Regarding your deepwater program going forward, are you looking at it as a net reserve exposure basis, or a net capital exposure? And will you try to balance a Gulf of Mexico versus international pursuits, or it's just really prospect dependent or concession dependent?

Yes, John, I would say it is prospect dependent. I mean we're going to go wherever we think the most profitable opportunities are to add reserves and production.

Okay. Last one for me. With Port Reading would it behoove you to run at less than 50,000 barrels a day so you'd be treated completely as an independent?

I am not sure if Port Reading is going to -- when you say independent, I'm not sure quite what you're driving at. You might elaborate on that a little bit.

From accounting purposes for SEC, if you process less than 50,000 barrels a day you are an E&P. Remember Louisiana Land, remember [Winoco] a decade ago, they were E&Ps with refining assets, so then you get full [IDCs].

No, John, in that case once the retail stations also count in that from an integrated standpoint. So, no, as John said, the Energy Marketing business, the Retail businesses and we're continuing operating at Port Reading, they're a part of our core business. So wouldn't matter if Port Reading was not in the portfolio. We would not be considered independent.

Okay, great. Thank you.

Katherine Minyard, JPMorgan.

Hi, good morning. Just a couple of quick questions. Can I confirm -- are the hedges -- are they swaps or are they puts?

They are swaps.

Okay, great. And then in terms of Pony, are we still looking at potential sanctioning in this year?

What I will say about Pony is we're still in discussions with the partners about trying to advance that project. Obviously, with five companies, it's difficult to progress things quickly.

Okay, sure. And then just a final question. I believe John Rielly just talked about $400 million a year in Bakken infrastructure spending, is that also the right run rate for the current year as we look at the $1.9 billion? Is about $400 million of that related to infrastructure again in 2012?

It's actually a little higher in 2012, so we're seeing about $500 million will be infrastructure related. And then you should see it tail off because the gas plant expansion, it's a heavy year related to the gas plant.

Great. All right, thank you very much.

You're welcome.

This concludes the Q&A session for today's call. Thank you for your participation in today's conference. This concludes the presentation. Everyone may now disconnect and have a great day.