赫斯 (HES) 2014 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the second-quarter 2014 Hess Corporation conference call. My name is Stephanie, and I will be your operator for today. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes.

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

Thank you, Stephanie. 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. These 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 information provided on our website.

With me today are John Hess, Chief Executive Officer; Greg Hill, President and COO; 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 provide some key highlights on the quarter and the progress we are making in executing our strategy. Greg Hill will then review our operations, and John Rielly will go over our financial results.

With the sale of our retail business which was announced in May, we have essentially completed our transformation to a pure-play E&P company. We have built a focused, balanced portfolio of low-risk, high-margin growth assets. And we are well positioned to deliver 5% to 8% compound average annual production growth through 2017 from our 2012 pro forma base and to generate free cash flow after 2014 based upon a $100 Brent.

With regard to our financial results for the second quarter of 2014, net income was $931 million, or $432 million on an adjusted basis. Adjusted net income per share was $1.38 compared to $1.51 in the year-ago quarter.

Cash flow from operations before changes in working capital was $1.3 billion. Compared with the second quarter of 2013, our results were impacted by asset sales which reduced production by 43,000 barrels of oil equivalent per day and the shut-in of production in Libya, which reduced production by 24,000 barrels of oil equivalent per day.

Net production in the second quarter averaged 319,000 barrels of oil equivalent per day or 310,000 barrels of oil equivalent per day on a pro forma basis, excluding divestitures. This represents an increase of 17% from pro forma production of 265,000 barrels of oil equivalent per day from the year-ago quarter, excluding Libya.

Our production growth is underpinned by five key areas. The Bakken in North Dakota, the Utica shale play in Ohio, Tubular Bells in the Deepwater Gulf of Mexico, the Valhall Field in Norway, and North Malay Basin in Malaysia.

Let's look at highlights from the quarter for these growth assets. Starting onshore, net production in the Bakken averaged 80,000 barrels of oil equivalent per day in the quarter, up 25% from second quarter of 2013 following the successful startup of the expanded Tioga gas plant. We project net Bakken production for the third quarter to average between 85,000 and 90,000 barrels of oil equivalent per day, and we are on track to deliver our full-year 2014 production forecast of 80,000 to 90,000 barrels of oil equivalent per day.

At the same time, our Bakken team continues to drive our well costs lower. In the second quarter drilling and completion costs averaged $7.4 million, down 12% from the year-ago quarter. As we have said before, our goal is to deliver the highest-value wells, and our results continued to demonstrate that we are consistently delivering wells with some of the highest returns in the Bakken.

In the Utica we and our partner, CONSOL, have a premier acreage position in the wet gas window, featuring highly productive wells with high liquids content and high net revenue interests, which will enable us to generate strong financial returns. During the quarter we continued delineating the play, and well results remain encouraging. While current production is fairly low at this stage, the Utica asset is positioned to be a material contributor to our production growth over the next five years.

Moving to our offshore assets in the Deepwater Gulf of Mexico, final commissioning of the Tubular Bells field, in which Hess has a 57% interest and is operator, is currently underway. We expect Tubular Bells to achieve first production in September and to deliver net production of approximately 25,000 barrels of oil equivalent per day following a ramp-up period.

Regarding the Valhall Field in which Hess has a 64% working interest, net production averaged 31,000 barrels of oil equivalent per day in the second quarter. This compares to 13,000 barrels of oil equivalent per day in the year-ago quarter, when production was ramping up following completion of the multiyear field redevelopment project.

Our full-year net production forecast remains 30,000 to 35,000 barrels of oil equivalent per day. Valhall is a long-life material resource that generates significant free cash flow and offers potential in terms of unbooked reserves and production growth.

In Malaysia net production from the North Malay Basin, where Hess is the operator with a 50% interest, averaged 42 million cubic feet per day in the second quarter. The early production system commenced in October 2013 and is expected to maintain production at current levels through 2016. During the quarter we continued to progress full-field development, which should result in net production increasing to 160 million cubic feet per day in 2017.

Our natural gas assets in the Gulf of Thailand, which include North Malay Basin and the Malaysia/Thailand Joint Development Area, or JDA, are material long-life assets with oil-linked pricing and exploratory upside. Combining our North Malay Basin production with that of the JDA, we anticipate that net production will reach 70,000 barrels of oil equivalent per day beginning in 2017 compared with 46,000 barrels of oil equivalent per day in 2013.

In terms of overall Company production, we are on track to deliver our 2014 pro forma production forecast of 305,000 to 315,000 barrels of oil equivalent per day, excluding Libya. This would be up between 13% and 17% from 2013 pro forma production of 270,000 barrels of oil equivalent per day.

Capital and exploratory expenditures in the first half of 2014 were $2.5 billion, which was down 23% from the first half of 2013. This decline reflects both improved capital efficiency and increased activity planned for the second half of the year in the Bakken, as well as the impact of asset sales. We continue to project 2014 capital and exploratory expenditures will be $5.8 billion.

In terms of divestitures, we reached a major milestone in the second quarter with the agreement to sell our retail business for a total consideration of $2.9 billion. The transaction is scheduled to close before the end of the year.

In addition, we completed asset sales totaling $1.6 billion during the second quarter, comprising the sale of our exploration and production assets in Thailand; the sale of our 50% interest in the joint venture power plant under construction Newark, New Jersey; and an additional 30,000 acres including related wells and facilities in the Utica dry gas window. The divestiture process for our HETCO energy trading business is also ongoing.

We continue to make progress in our plans to monetize our Bakken midstream infrastructure in 2015 through an MLP structure, which will allow Hess to retain operational control while realizing additional value from our infrastructure investment. As we announced today, we expect to file our initial Form S-1 with the SEC in the fourth quarter of this year.

Based upon the sale of our retail business, we increased our share repurchase authorization to $6.5 billion from $4 billion. Year to date through July 29, we have repurchased 23.3 million shares for $2 billion. Since commencement of the program in August of 2013, we have repurchased 42.6 million shares for $3.5 billion. We will continue to implement this program in a disciplined manner and provide quarterly updates on future conference calls.

In closing, we are delivering strong performance and executing well against our plan to drive cash-generative growth and sustainable returns for our shareholders through a focused, balanced portfolio of world-class E&P assets. We are excited about the future we are building and look forward to talking more about our portfolio and growth prospects at our investor day, which will take place on November 10 in Houston.

I will now turn to call to Greg for an operational update.

Thanks, John. I'd like to provide additional details on the execution of our strategy. In the second quarter we again demonstrated continuing strong delivery against plan. Starting with unconventionals, in the second quarter net production from the Bakken averaged 80,000 barrels of oil equivalent per day, up from 63,000 barrels of oil equivalent per day in the first quarter of 2014.

In the second quarter approximately 30% of our operated oil was produced from the Three Forks, and some 30% of our wells were completed in the Three Forks. This demonstrates the high quality of our acreage position in the Three Forks as well as the Middle Bakken.

First gas was introduced to the Tioga gas processing plant on March 23. First residue gas sales commenced on March 25 and ethane recovery on April 23.

The plant will be a major enabler for us to reduce flaring to less than 10% by 2017. Plant gross inlet capacity has increased to 250 million cubic feet per day, and natural gas liquids processing capacity has more than doubled to approximately 50,000 gross barrels of oil equivalent per day.

Current plant gross inlet volumes are approximately 180 million cubic feet per day. And we are processing approximately 35,000 gross barrels of oil equivalent per day of natural gas liquids. Looking forward, we intend to debottleneck the plant to enable processing of up to 300 million cubic feet per day.

In the second quarter we operated 17 rigs and brought 53 Bakken wells online compared to 30 wells in the first quarter. Our plan is to bring a further 140 to 150 wells online over the course of the second half of this year. In the third quarter we forecast net Bakken production to average between 85,000 and 90,000 barrels of oil equivalent per day. And our full-year 2014 Bakken production guidance remains at 80,000 to 90,000 barrels of oil equivalent per day.

Drilling and completion costs continue to be reduced, with the second quarter averaging $7.4 million per well versus $8.4 million per well in the year-ago quarter and 7.5 million per well in the first quarter of this year. We continue to make significant progress in drilling cycle time improvements. Compared to the year-ago quarter, we have seen a 19% decrease in spud-to-spud days, which leads not only to lower drilling costs, but also accelerates production.

This continuing cost reduction, coupled with the above-average productivity of our wells, means we are delivering some of the highest returns in the Bakken play to our shareholders. Our 13- and 17-well-per-DSU downspacing pilots are progressing well and performing in line with expectations. These pilots are critical for us to determine optimal spacing across the play.

By the end of this year, we expect to have sufficient data to provide updated guidance for well spacing, production, forward drilling locations, and estimated recoverable resources.

In the Utica the divestment of our 100%-owned dry gas acreage to American Energy Partners is allowing us to focus on the more profitable wet gas area of the play. The appraisal and early development of our 43,000 core net acres in the Hess/CONSOL joint venture continues to be encouraging.

In the second quarter the joint venture drilled 10 wells, completed 11, and tested 5. So in total, the joint venture has now drilled 52 wells, completed 37, and tested 20 since inception in 2012. Results on our recent Cadiz B wells in Harrison County are particularly encouraging, with rates of up to 3,450 barrels of oil equivalent per day, with 51% to 53% liquids based on 24-hour tests.

Turning to offshore, progress continues in Tubular Bills Bells, North Malay Basin, and Valhall. At our 57% owned and operated Tubular Bells development in the Deepwater Gulf of Mexico, we remain on time and on budget. We have completed wells A, B, and D and remain on target for field startup in September 2014.

We expect net production to build to approximately 25,000 net barrels of oil equivalent per day within eight weeks of first oil. Also in the Gulf of Mexico, the Stampede development project, in which Hess holds a 25% working interest and is operator, we continue to progress and project sanction is expected later this year.

Stampede is a Miocene development that will build on the successful execution of our Tubular Bells project.

At the North Malay Basin in the Gulf of Thailand, where Hess holds a 50% working interest and is operator, second-quarter net production averaged 42 million cubic feet per day through the early production system. Regarding the full field development project, we signed the gas sales agreement with the Malaysian government, awarded contracts for the construction and installation of the central processing platform and four wellhead platforms, and we progressed construction of the gas export system. Upon completion of full field development in early 2017, net production is expected to increase to 160 million cubic feet per day.

At the BP-operated Valhall Field in Norway, in which Hess has a 64% interest, second-quarter production was reduced by approximately 6,000 barrels of oil equivalent per day compared to the first quarter. This was primarily due to a temporary reduction of South Flank production due to a mechanical problem -- now resolved -- and the need to shut in the G4 producer during well G3 drilling operations. G3 has now finished drilling, and we expect G4 will be restarted in August.

We expect full-year production guidance for Valhall to remain unchanged at 30,000 to 35,000 barrels of oil equivalent per day. Looking ahead to the third quarter, planned seasonal maintenance shutdowns are scheduled this summer at our Gulf of Mexico and North Sea assets, which combined are expected to reduce third-quarter production by approximately 20,000 barrels of oil equivalent per day.

Companywide production on a pro forma basis and excluding Libya is forecast to average between 300,000 and 305,000 barrels of oil equivalent per day in the third quarter of 2014. Our full-year 2014 forecast on this same basis remains unchanged at 305,000 to 315,000 barrels of oil equivalent per day.

Moving to exploration, in Kurdistan, where Hess has a 64% interest, the Shakrok-1 well encountered noncommercial quantities of hydrocarbons and was plugged and abandoned. We are currently drilling the Shireen-1 well on the Dinarta Block, where we expect to drill and complete testing by year-end 2014.

In Ghana in the second quarter, Hess and its partners commenced drilling a three-well appraisal program. The first well, Pecan 2A, was completed in June; and the second well, Pecan 3A, was drilled and logged. And we are now preparing to production test the well.

The third well, which will appraise the Almond discovery, is expected to be drilled in the third quarter. By year end, following completion of the appraisal program, we will provide an update on results and our forward plans.

In closing, this quarter is yet another demonstration of strong execution against our plan and on-target delivery of key milestones. I will now turn to call over to John Rielly.

Thanks, Greg. Hello, everyone. In my remarks today I will compare results from the second quarter of 2014 to the first quarter of 2014. The Corporation generated consolidated net income of $931 million in the second quarter of 2014 compared with $386 million in the first quarter of 2014.

Adjusted net income was $432 million in the second quarter of 2014 and $446 million in the previous quarter. E&P had income of $1.057 billion in the second quarter and $508 million in the first quarter of 2014. E&P adjusted net income was $483 million in the second quarter of 2014 and $514 million in the previous quarter.

The changes in the after-tax components of adjusted net income were as follows. Higher sales volumes for crude oil and NGLs, partially offset by lower gas volumes, increased net income by $71 million. Changes in realized selling prices increased net income by $7 million.

Higher cash costs decreased net income by $54 million. Higher depreciation, depletion, and amortization decreased net income by $43 million. Higher exploration expenses decreased net income by $39 million. All other items net to an increase in net income of $27 million, for an overall decrease in second-quarter adjusted net income of $31 million.

Our E&P crude oil operations were overlifted compared with production by approximately 550,000 barrels in the quarter, which increased after-tax income by approximately $25 million. We currently expect an underlift of approximately 500,000 barrels in the third quarter.

In the second quarter the Corporation added 10,000 barrels per day of Brent crude oil hedges, for a total of 40,000 barrels per day for the remainder of 2014 at an average price of $109.17 per barrel. In addition, during the second quarter the Corporation added 20,000 barrels per day of WTI crude oil hedges for the remainder of 2014 at an average price of $100.41 per barrel.

The E&P effective income tax rate, excluding items affecting comparability of earnings, was 34% for the second quarter and 39% in the first quarter of 2014, primarily reflecting the mix of earnings.

Turning to corporate, corporate and interest expenses net of income taxes were $91 million in the second quarter of 2014 compared with $89 million in the first quarter of 2014. Adjusted corporate and interest expenses were $82 million in the second quarter and $81 million in the first quarter.

Turning to cash flow, net cash provided by operating activities in the second quarter, including a decrease of $368 million from changes in working capital was $946 million. Net proceeds from asset sales were $1.610 billion. Capital expenditures were $1.214 million.

Common stock acquired and retired amounted to $692 million. Net borrowings amounted to $431 million. Common stock dividends paid were $77 million. All other items amounted to a decrease in cash of $52 million, resulting in a net increase in cash and cash equivalents in the second quarter of $952 million.

Turning to our stock repurchase program, during the second quarter we announced an increase in our existing share repurchase program to $6.5 billion from $4 billion. We also purchased in the quarter approximately 8.3 million shares of common stock at a cost of approximately $768 million or $91.85 per share, bringing cumulative purchases for the program through June 30, 2014, to 40.2 million shares at a cost of $3.3 billion or $82.09 per share.

We have continued to buy back our common stock. And through July 29, total program-to-date purchases were 42.6 million shares at a cost of $3.5 billion or $83.03 per share.

We had $2.240 billion of cash and cash equivalents at June 30, 2014, compared with $1.814 million at the end of last year. Total debt was $6.077 billion at June 30, 2014, up from $5.798 billion at December 31, 2013. In June the Corporation issued $600 million of notes comprised of $300 million of 1.3% notes due in June 2017 and $300 million of 3.5% notes due in July 2024. The Corporation's debt to capitalization ratio at June 30, 2014, was 20% and 19% at the end of 2013.

Turning to 2014 guidance, I would like to provide estimates for certain metrics. For the third quarter E&P cash operating cost per barrel of oil equivalent are estimated to be in the range of $22.50 to $23.50. And E&P depreciation, depletion, and amortization per barrel of oil equivalent are expected to be in the range of $29 to $30.

Full-year 2014 guidance is now expected to be $21.50 to $22.50 per barrel for cash operating costs and $28 to $29 per barrel for depreciation, depletion, and amortization. Total production unit cost for the full year of $49.50 to $51.50 per barrel remains unchanged.

The third-quarter E&P effective tax rate is expected to be in the range of 33% to 35%. And the full-year 2014 rate is now expected to be in the range of 36% to 40%, down from our previous guidance of 37% to 41%.

Third-quarter corporate expenses are expected to be between $30 million and $35 million after taxes. And after-tax interest expenses are expected to be in the range of $55 million to $60 million. The estimate for corporate expenses in 2014 remains in the range of $125 million to $135 million after taxes. And after-tax interest expenses are now estimated to be in the range of $215 million to $225 million, down from our previous guidance of $225 million to $235 million.

Turning to midstream, as we announced earlier this morning, we are pursuing the formation of a Master Limited Partnership for our Bakken midstream assets. We expect to file an initial registration statement with the SEC in the fourth quarter.

The SEC imposes restrictions on communications when a securities offering is in process. We are therefore limited in the information that we can share with you at this time, and we will not be able to answer questions about future plans and expectations for the MLP on this call.

As we move through the offering process towards an IPO, we will continue to be restricted in the information that we can give you other than the information provided in the registration statement. This concludes my remarks. We'll be happy to answer any questions. I will now turn to call over to the operator.

(Operator Instructions) Evan Calio, Morgan Stanley.

Good results. My question is on the Bakken and Hess's approach to completion design and technological change. First, have you experimented, or do you plan to experiment with coiled tubing completion technologies in the Bakken? I know a few others are beginning to use these completions. Schlumberger recently highlighted at its analyst day the potential to significantly improve frac effectiveness via those completions. And I have a follow-up, please.

Yes, Evan, thanks for the question. In fact, I just had a review of that yesterday. So, yes, we are planning to deploy some coiled tubing completions and give them a try.

Great. How about any other variables that you are experimenting with and the process there in isolating -- whether it's completion variables, well design variables, or being kind of faster adopter to change? Can you talk about your approach there as things continue to rapidly change?

Yes. I think, first of all, our current standard design is 35 stages now. That's compared to 29 last year, so we've upped our stage count. We've also upped our sand loading a bit to around 100,000 pounds per stage.

We just continue to learn, and watch, and try new things to see what the best approach is; pay close attention to what competitors are doing as well; and then to try some of those things on our own and see what the results show us.

And slickwater fracs? Any potential there to limiting decline rates?

Yes. We are evaluating that, as well -- the slickwater. We haven't run one yet, but we are going to do that.

Great. That's great. And then maybe lastly for me, the analyst day is a newer announcement. And I know it's been a while since you had one. I know there's been significant portfolio changes.

What drives the decision? What does the Street not understand about the Hess story, in your view? And I'll leave it at that.

Well, we wanted to get portfolio restructuring to a pure-play E&P behind us. And with the announcement of the retail sale in May, and God willing, Tubular Bills ramping up; and Bakken ramping up; and Utica ramping up, we thought it would be a good time to give an update on the performance of our assets in deeper detail as well as some of the exciting investment growth opportunities we have.

Great, guys look forward to it. Thank you.

Guy Baber, Simmons & Company.

I had two on production -- one near-term and then one longer-term question. So I wanted to talk a little bit about the 3Q guidance. You mentioned 300,000 to 305,000 barrels a day pro forma, which looks a little conservative, even in light of the 20,000 barrel a day of maintenance that you called out, just considering that you should get back some significant JDA maintenance from last quarter, and then you have Bakken ramping up.

Are there any other negative offsets in the 3Q number that we need to be thinking of? And was the maintenance really kind of what keeps you leaving your full-year guidance unchanged, considering you guys have outperformed 1Q and then outperformed 2Q, and things seem to be ramping according to plan? And then I have a follow-up after that.

Okay. Yes, I think the maintenance is routine. It was part of our forecast. So if you look at kind of a walk-down between second-quarter and third-quarter pro forma guidance, as mentioned, the Bakken -- we plan an increase there. But all of the offset to that is the maintenance shutdowns that we talked about in the Gulf of Mexico and in the North Sea. So there's no other thing going on other than maintenance and being partially offset by the Bakken.

Okay. That's helpful. And then my follow-up is on longer-term, your E&P production guidance -- you mentioned that the Bakken, Utica, Valhall, and North Malay Basin are really the major assets that underpin that longer-term growth; and you've given us a pretty specific framework around how to think about the contribution from all of those assets aside from the Utica.

So I was hoping you could just provide a little bit more color around how we should be thinking about that multiyear ramp in the Utica, and kind of what type of volumes you think you could deliver there -- or if that's something that we will need to wait for for the analyst day?

Yes. I think, again, we are continuing the appraisal program in the Utica. And our plans would be to -- certainly by the end of the year to give much more visibility on the forward growth plans for the Utica. But again, we are very encouraged by what we see in the Utica.

Thank you.

Doug Leggate, Bank of America Merrill Lynch.

I've got two questions, if I may -- one for Greg and one for John, if that's okay. Greg, the supplemental information just hit during the call here, and it looks like the average 30-day rates for the wells that you brought on in the second quarter were quite a bit up and have been trending higher over the last, I guess, six quarters or so.

There was also a slight change in the mix towards Three Forks wells, it seems. I'm just wondering if you could help us connect the dots as to what's happening there that might be driving that improvement, and whether or not you think it's sustainable? And I've got a follow-up, please.

Yes. I think, Doug, it's related to two factors. One is increasing the stage count. So our standard design now is 35; in the quarter we filled 33. That's because we had a few wells where we use lower stage counts intentionally in some 6-40 patterns.

But the average IP for the quarter was over 1,000, and that was driven by -- there were over 20 new wells in the quarter that averaged well over 1,000 barrels a day. 15 of those were Middle Bakken, and 5 were Three Forks. So it's a mix of where we are drilling, but also the higher stage counts.

So I think, certainly, from the higher stage counts, that is sustainable; but rates will creep up relative to historic. Obviously, the mix will change as you kind of move around the field.

Okay. Thank you for that. John, my other question is a capital expenditure question, because this year I seem to recall you had about $400 million on TD and a bit on midstream. And now that you have obviously announced the MLP, and TD goes away, I'm assuming that the CapEx, same-store sales kind of thing would be lower next year unless you step up activity.

So given that you are in a very strong growth trajectory in the second half of the year, hard to imagine cash flow doesn't go up. So my question is: how do you think about the use of that free cash flow? Were buybacks only through proceeds from asset sales -- in other words, with operating cash flow, should we realistically think that that goes through organic growth, and perhaps a step-up in the Bakken, given your positive results from your downspacing?

Thanks, Doug. And yes, so now, as you begin to see the Tubular Bells comes on; Bakken continues to ramp; Utica begins to grow. So obviously there's some nice cash margins coming in, and our cash flow will continue to grow as this production increases.

To your point on where we are with our portfolio -- and we haven't laid out there our capital is going to be next year -- but as we said, we are looking to become free cash flow positive post-2014, with Brent prices that stay at at least $100. So where we are from a focus on our free cash flow generation is that we are focusing on executing that strategy to profitably grow that production and reserves, to generate that cash flow and generate, hopefully, enhanced shareholder value.

And then we will continue to allocate capital to growth opportunities that offer the highest risk-adjusted returns. But we'll be balancing those investments in the business with current returns to shareholders. So it's not just asset sale proceeds.

So to be clear, John, previously I believe you have said that sales proceeds would fund buybacks. So should we look for organic cash flow to fund buybacks? Or would that be more skewed towards dividends? I'm just trying to understand if you are changing your position a little bit on the use of operating cash flow?

So where we are right now and in the strategic transformation that we went through, yes, it was the proceeds -- and basically, excess cash flow from the proceeds -- we were utilizing those to buy back shares.

But as we get past that, and now we are in our -- that was a nonrecurring cash flow that came in, and we used that proceeds for that. When we get to the organic cash flow, yes, that can be balanced. And we will be looking for the high-risk returns that we have within the portfolio, and we will balance the use of that cash flow for that with current returns to shareholders.

All right. Thanks very much.

Ed Westlake, Credit Suisse.

This is Zak Deschaine, standing in for Ed right now. So a couple of questions, first regarding the Bakken. We've seen some good results from Blue Buttes and Hawkeye up in McKenzie County; I know you guys have touched on this a little bit. We're trying to understand -- is the uplift from new completion technology used here that isn't used elsewhere? Or do you see it more as a geology sort of focus? If you could just address that, then I have a quick follow-on. Thanks.

Well, again, it's both in the quarter. So certainly where we are drilling matters. We are drilling in some good sweet spots right now -- both for the Three Forks and for the Middle Bakken.

And then, as I said, with the stage counts going up and proppant loadings going up a bit -- that's obviously contributing to a higher IP rate. So it's really a mix of both geology and completion design.

Okay. So your new techniques are being used kind of across the board? It's not a --

They are. Our standard design now is 35 stages.

Right. And just a follow-up, unrelated -- sorry if this was addressed before. Where do you guys see the peak production from the Tubular Bells?

Well, I think what we said in our opening remarks is that we will bring three wells on. At first oil we will ramp those over a period of about eight weeks. Gulf of Mexico experience shows that you need to ramp them up slowly so you don't get sand influx.

We think that that will -- once we get those three wells up, we'll be around 25,000 barrels a day. And hopefully there's a little bit of upside to that number, but right now we are quoting 25,000 barrels a day.

All right. Perfect. Thank you.

Ryan Todd, Deutsche Bank.

If I could follow up on the Bakken. Maybe it's a slightly more focused way of looking at the earlier questions on use of cash, but what's the right way to think about your management of the pace of development in the Bakken? I realize you won't have downspacing results until later this year, but a high-level -- what are the governing factors in terms of your Bakken development? Is inventory a governing factor? Is it cash flow, infrastructure and logistics, some of all of the above? And if inventory goes up via downspacing, does that necessarily increase your long-term activity levels?

Yes. So first of all, once we are complete with the results of all the downspacing pilots, by year-end we will update guidance on pace and recoverable reserves, all the things that we talked about in our opening remarks. I think that the main objective that we are trying to accomplish in the Bakken is to maximize asset value. And that is a function of pace and infrastructure buildout.

So we are constantly trying to manage those two dimensions to ensure that we maximize ultimate NPV from the Bakken development. Because you can go really fast and overbuild infrastructure that you don't need, and so we are really trying to optimize based on those two dimensions to maximize value from the asset.

Okay. I appreciate that. And then if I could ask one quick one on the Utica as well. I'm not sure if this showed up in the supplemental data, or if you said; but did you say what the current production, or could you say what the current production in the Utica is? And maybe talk a little bit about the marketing of your gas. What do you have in the way of firm transport and your medium-term expectation on pricing out of the Basin?

Yes. I think in Q2 we produced around 3,000 barrels a day from the Utica. That's our JV acreage with CONSOL. And in Q3 we expect to double that to approximately 6,000 barrels a day and then continue to build through the end of the year.

And as we mentioned before, we plan to provide additional data and forecast later in the year on our outlook for the Utica.

As far as the gas, we have dedicated third-party contracts in place for 2014 and negotiate new ones for expanded volumes. And we don't expect any bottlenecks or issues. Regarding NGLs and pricing and all that, you know revenues received by us are on realized spot market prices in the surrounding areas.

And have you signed long-term contracts on the gas side?

No, we haven't.

Okay. Great. I appreciate that. Thanks.

(Operator Instructions) Paul Sankey, Wolfe Research.

Back to the Bakken, I had a couple of questions. The first is certainly specific, and then the second is a high-level question. The specific question is on the Tioga plant and the impact it had on your liquids cut. You've beaten our estimates there. Can we assume that that cut continues to rise as the plant ramps up? How much higher can we expect that to go? Thanks.

You know, just to kind of highlight what the Tioga gas plant has done to us in terms of increased capacity, so on the inlet side, the plant can currently process about 250 million cubic feet per day gross on the inlet side. It also -- the expansion increased our liquids processing capability to some 50,000 barrels of oil equivalent per day.

And if you look at what we are putting through the plant today, it's about 35,000 barrels of oil equivalent per day gross liquids. So you can see that there's further upside beyond that as we expand to plant capacity. Importantly, we also intend to debottleneck the plant to take the inlet capacity up to 300 million cubic feet a day. So we can see our way to another 50 million coming into the plant. And we have the liquids capacity to deal with that.

And would that, then, be another potential expansion beyond that debottlenecking?

That will be a question, I think, for the MLP in the future to decide.

That's what I was driving at without mentioning MLPs. Thanks, Greg.

The high-level question is: now that you've focused the Company more towards the Bakken and it's become so important to the story, can you just remind us what you believe your competitive advantage is? What makes you as good as or better than the competition in the Bakken? Thank you very much.

I think really three things. Obviously, we've got a great acreage position in both the Middle Bakken and the Three Forks. We have a privileged infrastructure position that we are reaping the benefits now and will in the future.

And then, thirdly, we have a distinctive operating capability through Lean manufacturing. And that's people, basically -- people and culture. And that's what's allowing us to continue to drive down quarter on quarter on quarter our well costs and also on productivity. Yes.

And we are also scaling that capability over to the Utica, and we are seeing significant reductions in Utica as well as we leverage those Bakken Lean manufacturing learnings over to that play also.

Great. Thanks, Greg. Appreciate it.

Paul Cheng, Barclays Capital.

I will first make a request. I know you are still in the early stage, but if you gentlemen would be able to share the Utica operating data -- somewhat similar to the format that you gave on the Bakken in the supplemental. It may not be in the next one or two quarters, but say a couple of quarters down, that would be really helpful.

Okay, Paul; that's something, clearly, that we are looking at, especially -- I mean, as Greg mentioned, we are focused on getting what our ultimate field development plan will be. And we were planning to add that, but thanks for the comment.

John, since I've got you here, maybe let me ask that -- the Company today is a much stronger company, both financially and operationally, comparing to, say, anytime in the last five years. So from that standpoint, is there a need of continued hedging, or what is your overall view on the hedging? Should we change it, seeing that given your position today, you really don't need to do any hedging?

So what we've said, Paul, is that looking forward, what we will do -- you are right; we are in a much better position with our balance sheet. But we will look at our price exposure on an annual basis. We are, we think, privileged, because we have -- our portfolio is tilted towards oil. 70%-plus of our production reserves are oil-based.

So we'll look at our price exposure on an annual basis. And we may hedge to provide some insurance, but it will only be for that one year at a time.

And this -- maybe that is for both John Hess and also Greg: outside the existing, already identified asset sales program for the next, say, one to two years, should we assume there's any additional meaningful asset that you guys will consider; or that you are pretty much done and that is behind?

Yes, Paul. With the sale of our retail business, our portfolio restructuring to transform to a pure-play E&P company is substantially complete. Going forward, however, portfolio optimization will be ongoing, to address your question, and be part of the normal course of business -- whether it's buying assets or selling assets.

Our focus now and in the future is to invest for growth of our production and reserves; deliver strong operating performance from our focused portfolio; and, most of all, sustain value generation for our shareholders.

And final one, not related to the quarter: Greg, looking at your 10-K on the PV-10 table, and I was a little bit surprised that for Norway, the future development cost is about $8 billion. I thought we were already done with all the CapEx spending, and it was just incremental wells that we need to drill. Why that the development expense on that is going to be so high? Does that mean the CapEx related to Norway will remain high for the coming years?

Paul, I will answer that. From a capital expenditure program -- there is a decent amount of capital that we are putting in here that will grow for a number of years. If Valhall -- as I think Greg has said in the past, we just redeveloped that field, so it's got a 40-year-plus life, the facilities that are on there.

So when you look at those PV-10, you've got development costs going out for a number -- 40-plus years of development costs there. So there is a well program, and as you said, it's an asset that generates very good cash flow for us. And we'll continue to invest in infill in the field. So that's what those development costs are for. In essence, they're for the project.

John, should we assume that Norway -- the CapEx is going to be flat over the next several years, or that it actually should be lower than this year?

I would assume for now -- because we haven't given any guidance, and we will go as we get towards the end of the year; and we have to work, obviously, with the operator -- BP being the operator. But I would assume there's some -- you know, a flattish-type CapEx in there, because there's opportunities for drilling in the field.

Thank you.

Pavel Molchanov, Raymond James.

First one on Ghana. After you wrap up the three-well appraisal program, presumably by the end of the year, is that going to provide you enough data to make a full development decision either way?

Yes, we believe it will. I mean, I think we will be in a good position to determine what our go-forward strategy is.

Okay. Understood. And then on Kurdistan, I think you mentioned in passing that you wrote off a portion of your acreage. And that was followed by one dry hole at Shakrok. Is that right?

Yes, that's right. So the Shakrok well -- although we discovered gas condensate in the Triassic, so there was hydrocarbons in the well -- you know, the well was deemed noncommercial.

Got it. So in other words, is that Block essentially kind of leaving the scene completely?

Yes, it's in the process of being relinquished, which will take several months.

Okay.

But we are drilling the Shireen well now, which is a much larger block. And it appears to be -- and it's offset, so the two are completely unrelated.

Okay. Appreciate it.

David Heikkinen, Heikkinen Energy.

As you think about the Gulf of Mexico volumes, with Tubular Bells coming online and maintenance downtime, just trying to familiarize myself with how you incorporate just normal, seasonal hurricane downtime into your annual operating plans?

Yes, that's essentially built into our contingency that we build in every year. And so it's just an average number based upon historic performance of hurricanes in the Gulf of Mexico. And that's just a bottom-line correction to our overall production that's built-in.

It's like seven days for oil fields and 10 days for oilfields -- something like that?

Yes. Round numbers, that's about right.

And then on the Tioga gas plant, with the expansion and then really the debottlenecking, just -- and this is details, but how do you think about the shrink from inlet to outlet? Is there a change to shrink with the expansion of capacity -- or what is, really, I guess the outlet gas plus the 50,000 barrels of fluids that you are processing?

Yes. So with the expansion of the plant -- and obviously, as Greg had mentioned earlier, the boosting in the liquids output, there is a higher shrinkage factor associated with the gas. So you are probably going from previously a 15% type shrinkage to over 50% type factor there.

That's helpful. Thank you.

Thank you very much. This concludes today's conference. Thank you for your participation. You may now disconnect and have a great day.