赫斯 (HES) 2013 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the second quarter 2013 Hess Corporation conference call. My name is Derek and I will be your operator for today. At this time, all participants are in a listen-only mode. Later we will facilitate 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, Derek. 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. The risks include those set forth in the risk factors section of Hess's Annual and Quarterly Reports filed with the SEC.

Also on today's conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental earnings information provided on our website.

With me today are John Hess, 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 high level comments on the quarter and the progress we are making in executing our strategy to become a pure play E&P company. Greg Hill will then discuss E&P operations and John Riley will then go over our financial results.

Net income for the second quarter of 2013 was $1.4 billion, or $520 million on an adjusted basis. Adjusted earnings per share were $1.51 compared to $1.72 in the year ago quarter.

Net production in the second quarter averaged 341,000 barrels of oil equivalent per day, compared to 429,000 barrels of oil equivalent per day in last year's second quarter. Asset sales associated with our strategic portfolio reshaping accounted for approximately 70,000 barrels of oil equivalent per day or 80% of the decline versus last year's second quarter.

Planned downtime at the Valhall field in June and lower entitlement under the production sharing contracts at the Malaysia-Thailand JDA accounted for the balance of the decline, which was partially offset by higher production from the Bakken. In the second quarter, net production from the Bakken averaged 64,000 barrels of oil equivalent per day, up 16% from a year ago. As a result of our transition to pad drilling, we expect to see an increase in production in the second half of the year.

Our full-year 2013 production forecast for the Bakken remains 64,000 to 70,000 barrels of oil equivalent per day.

Bakken well costs declined to $8.4 million in the second quarter, down 28% from the year ago quarter.

For the Corporation, our full-year 2013 production forecast remains 340,000 up to 355,000 barrels of oil equivalent per day. Taking into account the impact of asset sales, our pro forma 2013 production is expected to average 290,000 to 305,000 barrels of oil equivalent per day, up from pro forma production of 289,000 barrels of oil equivalent per day in 2012.

From our pro forma 2012 base, we expect to achieve a five-year compound annual growth rate of 5% to 8% through 2017, and growth in the mid-teens in aggregate from 2012 to 2014. This production growth will come from captured lower risk assets including the Bakken, Valhall, Tubular Bells, North Malay Basin, and the Utica.

Our portfolio reshaping moves have improved our cash margin. Second quarter 2013 pro forma upstream cash margin was $54 per barrel of oil equivalent, up $6 per barrel of oil equivalent from last year's actual second-quarter results. Despite Brent oil prices declining more than $5 per barrel.

Capital and exploratory expenditures in the first half of 2013 were $3.2 billion, which was down 20% from the first half of 2012. This decline reflects improved capital efficiency in the Bakken, the impact of asset sales, as well as the declining capital intensity of our portfolio.

Our full year 2013 fall capital and exploratory expenditures forecast remains $6.8 billion. We continue to project that 2014 capital and exploratory expenditures will be significantly lower than 2013, and more aligned with our cash flow.

We continue to make steady progress in executing our divestiture program. During the second quarter, we completed approximately $2.2 billion in asset sales, including the sale of our interest in Samara-Nafta for $1.9 billion. This brought completed asset sales as of June 30 to $3.5 billion.

Proceeds were used to repay $2.4 billion of debt and to strengthen our balance sheet so that the Company will have the financial flexibility to fund our future growth.

Yesterday we announced the sale of our Energy Marketing business to Direct Energy for $1.025 billion. This business markets natural gas, electricity, and fuel oil to 23,000 commercial, industrial, and small business customers in the eastern half of the United States. The sale of our Energy Marketing business brings year to date asset sales to $4.5 billion and puts the Company in a position to commence our previously announced share repurchase program.

The remaining divestment processes for our upstream assets in Indonesia and Thailand, as well as our downstream terminals, retail and trading businesses are well underway. We believe that our strategy to become a pure play E&P company will create significant long-term value.

Our focus is on execution -- growing production, driving further reductions in capital expenditures and operating costs, completing our remaining asset sales, and increasing cash returns to shareholders.

With that, I will turn the call over to Greg, who will provide an operational update.

I would like to provide a brief review of the progress we are making in executing our E&P strategy. As previously discussed, Hess is executing a three-pronged growth strategy through, one, unconventionals, with growth driven by the Bakken and Utica; two, exploitation with growth driven by Tubular Bells, Valhall, and North Malay Basin; and, three, focused exploration in areas such as Ghana. This balanced strategy underpins the 5% to 8% compound annual production growth rate that John just laid out.

Starting with unconventionals, in the second quarter, net production from the Bakken averaged 64,000 barrels of oil equivalent per day, up 16% from the second quarter of 2012. As we had previously indicated, our Bakken production was relatively flat in the first half of 2013 as a result of our transition to pad drilling. That transition is now largely complete and we will see higher production in the second half of the year.

There will be planned downtime in the Bakken during the fourth quarter as we complete the expansion of the Tioga gas plant and, while natural gas production will be partially curtailed for approximately 6 weeks, oil production is expected to be only modestly impacted. This downtime is incorporated into our 2013 Bakken production guidance, which remains 64,000 to 70,000 barrels of oil equivalent per day.

In terms of individual Bakken well performance, we remain focused on driving superior returns, which is a function of well cost, productivity, and price realization. Well costs in the second quarter averaged $8.4 million per well, down 28% from $11.6 million per well in the second quarter of 2012, and down from $8.6 million per well in the first quarter of 2013.

In addition, the productivity of our wells continues to be among the highest in industry, as 18 of the top 50 wells, or 36%, in the North Dakota Bakken play since the beginning of 2012 are Hess-operated wells. During the quarter, we brought 42 operated well onto production of which 27 were middle Bakken and 15 were Three Forks. For the full year, we expect to bring approximately 170 wells on production with two-thirds targeting in the middle Bakken and one-third targeting the Three Forks.

We continue to conduct pilot programs to test optimal well spacing. While these tests are ongoing, our current thinking is that the core middle Bakken can be down-spaced to approximately 180-acre spacing in many areas. Although we are still early in the testing in the down-spacing of our Three Forks acreage, we believe the infill potential will be broadly similar to the middle Bakken.

Our Tioga rail facility ran at capacity in the second quarter, delivering an average of 53,000 barrels per day to higher-value markets. Our Tioga gas plant expansion project, which will increase wet gas input capacity from 120 million cubic feet a day to 250 million feet a day is on schedule for commissioning at the end of 2013, enabling us to capture more liquids in value from our own gas and from third parties.

In summary, we are on track to deliver our 2013 production and capital guidance for the Bakken, and we are increasingly optimistic about the long-term upside.

Turning to the Utica, the appraisal of our acreage continues and we are increasingly encouraged by well results to date. In the second quarter, ten wells were drilled, three were completed, and three were flow tested. Two of the three tested wells were operated by Hess.

On our 100%-owned acreage, the Richland B1-H34 well in Belmont County, tested at a 24-hour rate of 2985 barrels of oil equivalent per day, including 29% liquids. On our joint venture acreage, we, as operator, tested the Cadiz A1-H23 well in Harrison County at a 24-hour rate of 2250 barrels of oil equivalent per day, including 57% liquids.

In 2013, Hess and CONSOL expect to spud approximately 40 wells and drill 25 across both our 100%-owned and joint venture acreage.

Turning to the second element of our strategy, exploitation, progress continues at Valhall, Tubular Bells, and North Malay Basin. At the BP-operated Valhall field in Norway, in which Hess has a 64% interest, net production averaged 13,000 barrels of oil equivalent per day in the second quarter. The field was shut in for one month during the second quarter, due to planned downtime at Ekofisk.

Full year 2013 net production from Valhall is forecast by the operator to be in the range of 24,000 to 28,000 barrels of oil per day, which we believe will come in at the lower end of this range. In July, net production has averaged approximately 26,000 barrels of oil equivalent per day from Valhall.

At our 57%-owned and operated Tubular Bells development in the deepwater Gulf of Mexico, our second production well was drilled during the quarter and we are currently drilling the third. We are on track for field startup in mid-2014, delivering 25,000 net barrels of oil equivalent per day of high-margin Gulf of Mexico production.

At North Malay Basin in the Gulf of Thailand, where Hess has 50% working interest and is operator, the jacket and topsides were installed and the floating production storage in offloading vessel for the early production system arrived on location in June. In addition, the five-well development drilling program is underway. We anticipate an on-time startup of production in the fourth quarter at a net rate of 40 million cubic feet per day.

With regard to full field development, as a result of an upward revision in net gas sales from 125 million cubic feet a day to 165 million cubic feet a day, additional engineering and construction work will be required, which will push first gas toward year-end 2016.

In terms of exploration, following seven consecutive discoveries on the Deepwater Tano Cape Three Points Block in Ghana, where Hess has a 90% working interest and is operator, we submitted our appraisal plans to the government in June. We plan to commence appraisal drilling in 2014 and are continuing our predevelopment work, including preliminary front end engineering and design. Consistent with our exploration strategy, in August we plan to open a data room with the intent to farm down our Ghana interest.

In Kurdistan, where Hess has a 64% working interest and is operator of the Shakrock and Dinarta blocks, we will spud the first of two planned exploration wells in August and anticipate spudding the second well in the fourth quarter. Here, we also recently opened a data room and plan to bring in partners.

In closing, strong execution performance in the first half of the year means that we are on track to deliver both our short and long-term goals. I will now turn the call over to John Rielly.

Thank you, Greg. Hello, everyone. In my remarks today I will compare results from the second quarter of 2013 to the first quarter of 2013.

The Corporation generated consolidated net income of $1.431 billion in the second quarter of 2013 compared with $1.276 billion in the first quarter of 2013. Excluding items affecting comparability of earnings between periods, the Corporation had earnings of $520 million in the second quarter of 2013 and $669 million in the previous quarter.

Turning to exploration and production, E&P had income of $1.533 billion in the second quarter and $1.286 billion in the first quarter of 2013. Excluding items affecting comparability of earnings between periods, E&P had income of $600 million in the current quarter and $698 million in the previous quarter. Second-quarter income included a nontaxable gain of $951 million related to the sale of the Corporation's 90% interest in its Russian subsidiary, Samara-Nafta.

Second quarter 2013 results also included an after-tax charge of $18 million for employee severance and exit costs. The changes in the after-tax components of adjusted earnings were as follows.

Lower sales volumes decreased earnings by $165 million. Changes in realized selling prices decreased earnings by $40 million.

Lower cash costs improved earnings by $60 million. Lower depreciation, depletion, and amortization improved earnings by $55 million. All other items net to a decrease in earnings of $8 million for an overall decrease in second-quarter adjusted earnings of $98 million.

Our E&P crude oil operations were over-lifted compared with production by approximately 550,000 barrels in the quarter, which increased after-tax income by approximately $30 million. Based on our current crude oil lifting schedule, we expect this over-lift to reverse in the third quarter.

The E&P effective income tax rate, excluding items affecting comparability, was 44% for the second quarter of 2013.

We have provided quarterly operational data for the Bakken in the supplemental earnings presentation posted on our website, including production data, number of rigs, middle Bakken and Three Forks well counts, average gross 30-day initial production rates, well costs, working interest percentages, and acreage totals. The supplemental earnings presentation also includes pro forma E&P results for 2012 and 2013.

The pro forma information presents our results as if our asset divestiture program had all been completed effective January 1, 2012, in order to present a historical comparison of the performance for the ongoing portfolio. This pro forma information includes operational data and cash margins.

Turning to corporate, corporate expenses after income taxes were $50 million in the second quarter and $44 million in the first quarter of 2013. Corporate expenses are higher than normal in both periods due to severance charges and increased proxy costs and professional fees. After-tax interest expense was $63 million in the second quarter of 2013 compared with $66 million in the first quarter.

Turning to cost savings, as part of our transformation to a pure play E&P company, we are taking steps to realign the organization and reduce costs. During the second quarter of 2013, we continued to reorganize the E&P and corporate functions to support the new portfolio and announced the closure of our London office by the end of the first quarter of 2014. These initiatives are anticipated to result in annual cost savings of $150 million.

Turning to discontinued operations, earnings from the downstream businesses were $11 million in the second quarter and $100 million in the first quarter of 2013. Second quarter 2013 results included after-tax charges totaling $21 million for employee severance, related to the Corporation's planned exit from its downstream businesses and costs to idle refinery equipment at the Port Reading refining facility.

First quarter 2013 results included net after-tax income of $30 million from items affecting comparability. Adjusted earnings decreased for the quarter, principally reflecting seasonally lower natural gas and oil volumes in Energy Marketing, partially offset by higher retail gasoline margins and improved trading results.

Turning to cash flow, net cash provided by operating activities in the second quarter -- including a decrease of $70 million from changes in working capital --was $1.247 billion. Capital expenditures were $1.500 billion. Net proceeds from asset sales were $2.291 billion. Net repayment of debt were $1.688 billion.

All other items amounted to a decrease in cash of $69 million, resulting in a net increase in cash and cash equivalents in the second quarter of $281 million.

Turning to our financial position, earlier this year we committed to applying the proceeds from our asset sales program to improve our financial flexibility to fund growth and provide current returns to shareholders. More specifically, proceeds from divestitures are to be applied to repay debt, provide a cash cushion, fund the 2013 cash flow deficit, and return cash to shareholders by repurchasing up to $4 billion of shares.

To date, we have used proceeds from divestitures to repay debt, begin to build the cash cushion, and fund the cash flow deficit. In the third quarter, the Corporation plans to increase its annual dividend and, with the announcement of the sale of our Energy Marketing business, we are in a position to commence our share repurchase program.

We are progressing plans to monetize our Bakken infrastructure assets by 2015 and use the proceeds to return additional cash to shareholders.

We had $725 million of cash and cash equivalents at June 30, 2013, and $642 million at December 31, 2012. Total debt was $5.800 billion at June 30, 2013, and $8.111 billion at December 31, 2012. And the Corporation's debt to capitalization ratio was 19.5% at June 30, 2013 compared with 27.7% at the end of 2012.

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

(Operator Instructions) Evan Calio, Morgan Stanley.

Good morning, guys. And thanks for all the additional data. Let me start with a strategic question -- strategy question.

John, you have reconstituted the board since last earnings call -- 10 new and experienced members. The board has met. While you appear to have clear operational momentum, I was just -- could you update us on any broader strategic review occurring or any update on the strategic assessment, or comments on how the board transition has gone so far?

Yes. The board transition has gone very well. I would characterize the first board meeting that we had in June as very constructive, and we are totally focused on executing the strategy we have outlined.

That's great. And, keeping on the asset sale theme or structuring theme, sale proceeds have exceeded expectations, I think yesterday's included. It may be harder to reconcile from a deconstructed historical EBITDA on the retail segment.

Maybe a few questions that could help. I mean, for -- could you provide a 2012 EBITDA or cash metric for the Energy Marketing business for the OM?

Evan, so, obviously we are in the middle of these processes, right, the sale processes. And we don't want to front run the process. You saw, I think in Centrica's release, that they had $200 million of estimated EBITDA for 2013. That's a reasonable estimate for the business.

Last year, obviously it was a warmer winter. So it was at least 20% less heating-degree days last year. So that obviously would have impacted the EBITDA in 2012 as it related to Energy Marketing. But that is really as far as we are going to go. We are not going to front run the sale process.

Okay. Maybe risk of getting a similar response, on the terminal sales, can you give us any of the historical utilization rates or any metric there, because I presume some uptick in potential value will be improved utilizations to a potential buyer?

So Evan, every buyer is going to look at the business potentially differently from how they want to manage it. So we are not providing that data right now. We are well into the process.

Obviously, selling the terminal business in this current environment is a positive thing. It's a very good environment. The assets are strong. We have got a nice set of assets here on the East Coast. And the interest has been keen in these assets.

So that's as far as I think we want to go. And, just as John said earlier, the sales progress is well underway and is going according to plan.

Let me, lastly, if I could -- could you provide any tax basis in assets held or how much coverage -- how much tax coverage you have for those assets that are announced, yet you have not yet received -- closed yet?

There will be significant gains on the assets on an overall basis to be sold. From a tax leakage guidance standpoint, from the overall sale proceeds of that we are getting as part of this program, we have talked about that our tax leakage will be less than 5%. That's overall. That's with the E&P businesses and the downstream businesses.

Great, guys. That's helpful. I will leave it there. Thanks.

Ed Westlake, Credit Suisse.

Good afternoon. Just continuing on that downstream thought process, are there any corporate costs that are in the downstream that would be discontinued if those assets were sold? Just trying to true up historical reporting to what a seller might look at for these assets.

There are allocated costs, and for the most part, the corporate costs, if you want to call it that, are assigned to the business unit are allocated and are within the segments. Now, there is no question, as I said, as part of our cost saving initiative that we are looking at overall our functions and are going to right-size and reorganize the functions for the smaller portfolio that we have. But I would tell you, in general, most of the costs are allocated into the segments.

Right. Okay. And then switching to the Bakken, obviously you have guided that the shift of pad drilling would constrain volumes and that there will be an inflection in the second half. As we look out into 2014, 2015, 2016, any sort of feeling at this stage in terms of which of those years would be the faster growth on towards the sort of 120,000 barrel a day that you have discussed in the past, in terms of the rates of that growth, any color there would be helpful.

Yes, sure, Ed. So I think that's going to be a function of obviously how much capital we put in it. But I think once we get through the gas plant commissioning at the end of this year, I think for all practical purposes you assume a relatively steady ramp from there to 120,000 barrels a day over a couple of years.

Okay. And, initial volume estimates for the Utica, given the well results you have had?

In terms of what year, Ed?

Say next year, 2014.

We haven't finished our plan yet and we are still in the appraisal phase, so next year will be another appraisal year.

Okay. Good. Thanks very much.

Doug Leggate, Bank of America Merrill Lynch.

Good morning, everybody. John, congratulations on this execution plan. It seems to be going pretty well. A couple of questions, please, I guess first for Greg.

Greg, the Three Forks opportunity in the Bakken, on our numbers you're going to be pretty much getting into a sort of cash breakeven type of situation and probably within the next 12 to 18 months.

What are the plans there as it relates to optimizing the development of our inventory? Should we expect you to step up capital and development in the Bakken, or shift capital towards the more aggressive plan in the Utica? And I've got a couple of follow-ups, please.

Yes, Doug, I think, again, we haven't finalized our business plan for next year. I think, as we've done in the past, we will put that capital to wherever the best return is. And so, obviously, as we appraise and understand the Three Forks -- and that is going very well, by the way -- the Three Forks are actually some of our best wells in play -- we will allocate capital between the middle Bakken and Three Forks to drive whatever the highest return is.

But in terms of the absolute rig count activity level, Greg, I mean, as you get to cash breakeven, are you going to step that up a bit or maintain the current operating plan?

Yes. I think, again, Doug, we are still finalizing our plans for next year and the following year, so too early to kind of be specific on that. But, suffice to say, it will be an aggressive program for the Bakken.

I think, Doug, how we think about it conceptually, and Greg and I were up in North Dakota couple of weeks ago -- our team is doing an outstanding job, and our hats off to them really working on capital efficiency. As Greg in his remarks talked about down spacing, and also less of our money going forward is going to be for infrastructure. So there will be more money for drilling.

So we are really coming forward now with optimizing our investment program for next year and the year after and, as we get that defined, obviously we will be able to share it with you.

Great. Thank you. Couple of follow-ups, please. John, just thoughts on a potential, I guess -- I was going to say restructuring, but that's not the right word -- a potential MLP of the midstream business led by Tioga.

Sure. So as I mentioned, Doug, we are on track. By 2015 we are going to be looking at monetizing that Bakken infrastructure, and obviously an MLP is a potential key strategy for doing that.

The big key to this, as Greg had mentioned, is to complete the Tioga gas plant. So, all hands on deck to complete that expansion at the end of this year.

What we are looking to do is, then, as we start 2014, to begin to break out the midstream segment, so to be able to start reporting kind of EBITDA as we see going forward and how the midstream segment would operate, with the goal, again, of being ready in 2015 to be able to monetize or have an MLP in place for the Bakken assets.

Right. But, John, an outright sale as opposed to an MLP -- is that possible given that -- I mean, we all know MLPs need growth. And if you don't have a lot of drop downs, would a potential trade sale be on the table as well or not?

Well, first of all, we'll look at all options, but it doesn't appear that that would be the case, Doug. And why we see -- we see good growth in that midstream asset.

So, one, we have got several types of assets that can be put into it in the Bakken. One is the rail terminal aspect. So you can always start with a drop down of pieces of it. So you have the rail terminal, you have all the gathering of facilities that are in place, and then you have the gas plant.

And so we view, one, that there is great growth in this business and, two, we want to maintain control, because control is critical for us as you would ask before about as ramping up our production in the Bakken. And, with the production growth coming through that, obviously drives some growth.

And, as we'll move forward, we have other potential asset in our portfolio that can be included in the midstream and also drive growth. So we see some good growth there and it looks like it can provide very good value for our shareholders.

Thanks. Last one for me, maybe to John Hess. John, it looks like you are going to do substantially better that the than the disposal proceeds than a lot of people I think expected. What is the chances of upsizing the buyback and what is the mechanism for implementing the buyback? And I will leave it there. Thanks.

I'm going to let John Rielly answer the buyback question.

So where we are right now, Doug, from a planning standpoint, I can talk at a high level. As John mentioned, earlier, we are in a position to begin repurchasing the shares under our $4 billion authorization. So we have an authorization of the $4 billion.

We expect the repurchases to be spread fairly consistently over time. And, as a result, we will incur short-term bet debt periodically as we purchase shares in advance of receiving divestiture proceeds. So just as part of that, any such debt that we incur will be paid off with subsequent sales proceeds, like the Energy Marketing transaction that we have.

And then we will keep you informed of our progress with the plan on future quarterly conference calls. It is just early to say anything more with that as far as our share repurchase plan.

All right. Thanks very much.

You are welcome.

Paul Sankey, Deutsche Bank.

Good morning, everyone. Could I just follow up straight away on the buyback versus debt type question? Do you have a notional longer-term target for leverage now? I know in the past you have given one.

We are looking right now. As you saw, we are under 20% of our debt cap. And our portfolio, as we see going forward, as John had mentioned, in 2014 we always referred to that as type of the tipping point with our portfolio where free cash flow will approach our capital spend.

And, post 2014, our portfolio can deliver this 5% to 8% growth that we have targeted with our cash flow from operations. So from that standpoint, we don't have to increase debt. So there is no increase in leverage planned from that standpoint.

And, again, with the share repurchases, again, we are funding that with our proceeds from asset sales. So we are very comfortable that we will have a very strong balance sheet. And, obviously, from that standpoint, we are not looking to lever up going forward, but would be in a position if their commodity prices decreased that our balance sheet would be able to handle any cash flow deficits that could occur from that standpoint. So we like our leverage where it is.

Great. That's a clear answer. Thank you.

On the announcement of the Bakken monetization of the midstream, is there any implications there for the spin of the entire Bakken that was [muted]? Is the board considering that spin now? Thank you.

Obviously, the board will consider all moves to maximize shareholder value, but the plan we have outlined as a pure play E&P, having both the onshore and offshore business we think is the best way to maximize value. And the best way we are going to do that is focus on execution of the plan that we have outlined already.

Yes. Okay. So to be very clear, I think the announcement of the MLP doesn't have any implications for any potential or not spin of the Bakken.

Not at all. And to reemphasize John Rielly's point, it is very important that regardless of the financial structure that we move forward with our infrastructure in the Bakken -- it could be an MLP, it could be a joint venture -- Hess will continue to control and operate that infrastructure. That is essential for our future production and controlling that, and accessing the markets as we move forward.

Great. Thank you.

Robert Kessler, Tudor, Pickering, and Holt.

Good morning, gentlemen. I wanted to see if you wouldn't mind quantifying the degree to which you generate rens in your, I assume, your terminal business or retail, as the case may be?

Sure. We are in a position that we are benefiting from the current ren environment. Now, just to point out, Hess does remain an obligated party for rens because we do import transportation fuel to meet marketing's gasoline demand. But our retail and terminal and networks do generate more renewable credits than required to meet our supply needs.

In the second quarter our excess rens already generated a $17 million after-tax benefit. So that's what it was in the second quarter.

If you are looking at the third quarter, I would tell you we are generating rens around $20 million of month of excess rens. So if you were to take the current pricing that's in place right now, and just say you sold all the rens at that price for the third quarter, you could expect us to record an after-tax benefit in the $35 million to $40 million. Now, again, that's additional. So that would be in the second quarter with the $17 million have already been recorded in the first quarter.

Now, however, I have to add this, and it's not quantifiable. But the cost of rens rising in recent months has led to some rens-sharing, I'll call it, at the wholesale level, which is reducing our retail fuel margins and offsetting some of the direct benefit from selling the excess rens.

Now, how do you think about this as it relates to marketing the assets? I mean, presumably, different buyers might have different interests as far as how much value they attribute to the ren integration. Are you considering different options as far as whether it is packaged with the terminals or retail or sold independent of the other two pieces?

Each one of our businesses, the terminal business and the retail business, will be divested separately to maximize value. The processes for those as well as Indonesia, Thailand and our trading business are underway. Obviously, it is premature to share any details, but we are going to obviously pursue all alternatives to maximize value.

If you don't mind, I just wanted to clarify, because it was pointed out. When I said the $35 million to $40 million, that would be a third quarter benefit. I guess I had said second quarter. So that's a third quarter. And the rens generated a $17 million after-tax benefit in the second quarter. So just to make sure I got that right.

Thanks for the clarification. And then, separately, for me, the Bakken rail dynamics and pipe dynamics out of the basin have shifted quite a bit in recent weeks. I am wondering what you might be seeing so far in the third quarter as it relates to your movement of third-party volumes by rail versus by pipe.

Right. Through the second quarter, we had been maximizing our rail shipments between 53,000 and 55,000 barrels a day out of Tioga.

In July, as you rightfully point out, the market dynamics shifted where the WTI Brent spreads started to narrow, and it even narrowed more in August. As a consequence because we have three alternatives to maximize our net-backs of our crude in North Dakota -- one is supplying local refinery, another is accessing pipeline and bridge for the Mid-Continent and the third is our rail.

We were in a position to maximize value by moving approximately 4500 barrels a day in July to pipeline markets, and upped that number to 12,000 barrels a day to pipeline markets in August. Right now, where the differentials are looking forward, the rail is actually more attractive again.

And remember, the rail doesn't just go to St. James. It also goes to the East Coast and West Coast. So we are in a unique position to capture the highest value wherever the market offers it, and we continue to do so.

Good to see. Thank you very much.

Arjun Murti, Goldman Sachs.

Thanks. Just a couple quick ones. I think, John, you mentioned the pro forma ex-asset sale numbers for 2013. Is the 2014 number still the [325 to 340] I think you previously articulated?

Yes, there is no change in our guidance. Our guidance was, is that our pro forma production in 2012 was 289,000 barrels a day. And then by 2014 we would have aggregate mid-teens growth there. And there is no change in that.

Got it.

And, again, the growth driven by Bakken, Valhall, and Tubular Bells coming online.

That's great. And just one follow-up on the Bakken. I think, in part, the lower cost savings comes from different completion methodology. Looks like the IPs are still doing quite well. I don't know, Greg, if there's any additional color on how you're feeling about overall EURs or what they might be with the change in completion methodology.

Sorry. I didn't have my mic on. Yes. I think the EURs are within the range that we discussed previously. We are at a little bit at the higher end of the range in the second quarter versus the first quarter.

Completion costs continued to come down this quarter. That was due to efficiency as a result of pad drilling as well as some pricing concessions that we got from some frac contracts.

That's great. Thank you.

Guy Baber, Simmons & Company.

Thanks for taking my question. Just one quick one from me. But I was just hoping you could address some of the planned maintenance at Valhall in a little bit more detail, because I didn't recall any maintenance there being telegraphed at the time of the last call.

And obviously that asset has had some significant downtime since the second half of last year. But was that strictly related to the Ekofisk shutdown? Or was there anything specific you had to address there at Valhall? Just hoping for little bit more detail there, and then if you could just confirm your confidence in the longer-term targets there as well.

So, on the first thing, no, this was all just planned maintenance at Ekofisk, so Valhall was taken down for a month. And I do believe that we telegraphed that earlier, that that was an upcoming maintenance then in the second quarter.

I think over the long haul, our strategy is the same -- just work with the operator BP to get that facility as maximum capacity as possible. And we are at -- in July, we are back up around 26,000 barrels a day on Valhall.

Thanks for the clarification.

John Malone, Mizuho Securities.

So one question on Ghana and on Kurdistan. You said the data rooms will be open, if not now, it will be open shortly. Do you expect to get partners in there before the end of 2013? And can you kind of give a range of what your ideal retained working interest would be in both of those assets?

Well, I think as we've said before, part of our exploration strategy is to reduce our higher working interest opportunity set. And as we have said before, it's going to be case-by-case, but in this kind of 40% kind of a working interest, would be our ideal sweet spot.

Regarding timing, again, the data rooms have -- in Kurdistan have just opened. Obviously, we would like to get a partner as soon as possible in Kurdistan because we will start drilling in August.

And then on Ghana, that data room hasn't opened yet, but will open imminently. And, clearly, we would like to get a partner in there as soon as possible as well.

Okay. Thanks. And then just getting back to the Bakken for a second. It looks like in this quarter you had a higher proportion of gas in production. Is that a trend that will continue and how does that Tioga refit influence that higher proportion in gas?

I think, with time, as the Tioga gas plant comes on, you will end up with a little bit higher proportion of gas in your stream. But it won't be a significant major shift.

Okay. So the proportion we are at now I think will go up a little bit from the proportion in gas in (multiple speakers)

[Or up] slightly. Yes.

Okay. Thank you.

Paul Chang, Barclays.

Good morning, guys. (multiple speakers) Earlier [they were] talking about (inaudible) on Ghana and Kurdistan. What is the primary consideration when you consider that whoever is going to come in? Is it a financial consideration or just have more importance on the other strategic implication that may represent?

Yes. I think there is two -- there is to drivers. I think on Ghana, obviously, the main driver there is reduce some financial exposure for Ghana. And then, for Kurdistan, it's the same -- reduce some financial exposure, but also reduce risk.

This, Paul, if you recall, this is part of our overall exploration strategy to reduce working interest in order to allow us to get more drill bit exposure for the same investment. So obviously, if I am a third, a third, a third, I can drill three times as many wells as if I am 100%.

Sure. Totally agree. I just want to see that -- is the most important in terms of who is going to win the bid, is it based on how much they pay you or there is other factor that is more important? I guess that's my question.

Yes, I think there is other factors. I mean, obviously, price will be a key consideration. But if you think about Ghana, we would obviously look at the technical capability of the partner as well, as being an important consideration in that.

But, will you be looking at that sort of like swapping also in the case of Ghana? Or that's not really the preferred route?

That's not really the preferred route.

It is getting someone with the financial capability to help us reduce risk and maximize value for the risk we will be taking. So I would say the economic concerns would be the primary one.

Okay. And, John Rielly, earlier, based on the way that you talked about the buyback, have you already started the buyback, or that you are still waiting for the Energy Marketing deal to be closed before you start?

We have not started the buyback, so just to be clear on that. And then, to your question, no, we are in the position now that we expect our repurchases to be spread over time. And, as I said, we can incur debt here periodically because we will be buying shares that prior to receiving divestiture proceeds. So we won't be waiting for the Energy Marketing proceeds.

Will you start the buyback, say, in the third quarter or that is going to be later?

So I mean we want to keep this at a high level from a planning standpoint. So we clearly, as with the Energy Marketing sale, which we expect to close in the fourth quarter, we will be buying ahead of that. So, yes, we do expect to start in the third quarter, but I don't want to say anything more than that.

Okay. That's fair. And John mentioned earlier that you were talking about the potential tax leakage on the asset sales would be less than 5%. Is that also based on the assumption that you are going sell the retail and not a tax-based spinoff?

From an overall standpoint, right, we are on a dual track on the retail. But from -- either way, if we are looking at that from an overall asset sale proceeds, including E&P, yes, we still say it will be less than 5% of the overall proceeds.

So even if you are going to sell retail, not tax-based spinoff, you would still be less than 5%, you believe?

I think the key point there, Paul, is we are going to pursue all alternatives to maximize value for retail. And it's just premature to share any details further than that.

Okay. Greg, on Utica, on the (inaudible) can you tell us what is the (inaudible)? Is it [C-3, C-4, C-5, C-6?] I mean, what kind of component are we talking about?

Sorry. I had to turn my mic (multiple speakers) (laughter). I apologize.

For the majority of the wells that we have tested so far, so the ones in second quarter, the one that I quoted of 2250 barrel equivalents per day, that has got about 360 barrels of condensate in it, so -- and some NGLs. So of that 2250, 57% is liquids on an all-in basis. So all it really -- just depends on where you are in this play.

We are still delineating all of those lines. Where is the condensate? Where is NGLs? Where is dry gas? And so it's a mixed bag right now.

So you are still not seeing an established pattern based on the well that you test in terms of the split between condensate and NGL?

We just don't have enough well data yet. Just keep in mind, as far as test, since 2012 we only have 12 or 13 wells that we have tested. So it's still very early and we are trying to appraise all those various windows, as industry is doing as well.

And, Greg, when we are talking about Bakken, you have that pocket of 120,000 barrels per day, back I think in maybe late 2009, 2010, early. And that pocket, does that already incorporated your potential in Three Forks or just on the middle Bakken?

I think either/or, I guess, is how we would answer that. It is mainly going to be a function of how much capital you put in and how fast you ramp that up. Because we will interchange Three Forks and middle Bakken wells as necessary, again, trying to go where the highest return is. (multiple speakers)

No, I understand. I just think that in terms of the resource potential, including the Three Forks and the middle Bakken -- can they support even bigger than 120,000? I guess that's my question. Or that the resources really can only support 120,000.

No, no, no. They could definitely support a higher peak rate and, again, it's just going to be a function of how much capital you put into the Bakken on an annual basis, right -- (multiple speakers) resources there.

Two final questions. One, John, do you have a number in terms of what is the unit operating cost at Bakken in the second quarter, and in terms of the cash operating cost and including the transportation cost?

And second one, just wanted to confirm, you said you generate about 20 million [gallons] a month in the excess ren. I just wanted to confirm that number.

Yes, Paul, it is 20 million a month of excess rens that we generate per month. And then, as far as the Bakken unit costs, in general, our guidance has been is that our operating cash costs, including production taxes are a bit below our portfolio average that we have for the overall portfolio.

And our unit DD&A cost, including all the infrastructure related costs associated with it, are higher than our portfolio average. Now, we do anticipate and it has been happening that our unit cash costs will decline as volumes increase, and that the unit DD&A will also decrease going forward. As a result of increasing the reserve bookings relative to investment and also, as John mentioned earlier, decreasing infrastructure spend.

Sure. Just a request, if possible, that, in your supplemental data that is great value for all this information on Bakken, if you can also add on the operating cost and the DD&A, that would be really helpful. Thank you.

Okay. Thank you.

Pavel Molchanov, Raymond James.

Thanks for taking the question. You referenced the appraisal plan in Ghana. Any sense of the timetable for getting approval on that and any particular conditions that you are concerned about?

Greg and I were in Ghana; met with the top government officials in June. Got a very warm reception and encouragement, and the ball is in their court to tell us when they will approve the appraisal program. But I would say the signs are encouraging as well as the signs for us bringing in a partner or partners.

So we have a very good relationship there and the ball is in their court. And when we have something to report, we will tell you.

Understood. And regardless of when you got approval, what is the anticipated timetable for bringing Ghana on to production?

I think -- so just the timetable would be, once we get approval of the appraisal plan, and the clock runs for two years for that appraisal period. Obviously in parallel we are doing pre-feed studies. So the soonest you would be able to sanction the project would be at the end of that two-year appraisal program, then you have to submit a development plan to the government and go through the approval process there.

So the soonest you would be able to submit that plan would be at the end of the appraisal program.

As we pointed out before, it doesn't factor in, assuming the investment would be attractive returns -- versus other opportunities we have, it doesn't factor in our five-year production forecast. It is beyond that. So it is beyond 2017.

All right. Appreciate it, guys.

John Herrlin, Societe Generale.

Just a couple quick ones for me. Greg, you didn't mention the China shale JV. Is there anything you can talk about with that?

Yes. Sure. We signed those in China last week and signed a PSC which covers about 200,000 gross acres in the Santanghu basin in the northwest part of China.

Now, it is a phased program and under this contract, we are going to invest about $25 million over two years, to drill two vertical wells and one horizontal sidetrack. So a very small amount of money to kind of do a proof of concept.

Okay. Any kind of update on [Pawnee], or still working on that?

Yes. No, I think the partners are working towards a sanction pack. Early 2014 would be when we would anticipate a sanction decision.

Okay. Regarding partnering with [El Kurstin] in Ghana, are you looking for a carrier or a heads up deal, or promote basically?

Yes, obviously, we are looking for some form of carry.

Okay. And last one for me, for the new slim fasted at Hess approximately what will be ballpark on the headcount? Because obviously you have a lot of people in retail. I was just curious.

Well, obviously, the retail would be out of the headcount. The exact type of numbers we are working on and finalizing, and not in a position to give you the final details on it yet. But it will be a significantly slimmer headcount because we are just going to be a pure play E&P and we'll be right-sized to support that.

Thanks, John.

At this time, ladies and gentlemen, as there are no further questions in queue, this will conclude the second quarter 2013 Hess Corporation earnings conference call. Thank you for your participation and you may now disconnect. Have a great rest of your day.