康菲 (COP) 2014 Q2 法說會逐字稿

Welcome to the Second-Quarter 2014 ConocoPhillips earnings Conference Call.

My name is Christine, and I will be your operator for today's call.

(Operator Instructions)

Please note that this conference is being recorded.

I will now turn the call over to Ellen DeSanctis, Vice President Investor Relations and Communications.

You may begin.

Thanks, Christine, and thanks to our participants for your interest.

We know it's a very busy day.

On today's call, Ryan Lance, our CEO and Chairman, will provide a very brief overview of our strong operational performance for the quarter.

Jeff Sheets, our EVP of Finance and our Chief Financial Officer, will then address the financial results for the quarter.

And finally Matt Fox, our EVP of E&P, will cover the operational highlights and our production outlook for the rest of the year.

Finally we'll turn the call over to you for Q & A. We would ask respectfully that you try to limit your questions to one plus a follow-up, and then hop back in the queue if you have additional questions.

We will make some forward-looking statements this morning, and obviously, the risks and uncertainties in our future performance are described in the Safe Harbor Statement shown on slide 2 of today's presentation materials, as well as in our periodic filings with the SEC.

That's also available from our website, along with our GAAP and non-GAAP reconciliations, and supplemental data.

With that, I'm going to turn the call over to Ryan.

Thank you, Ellen, and let me extend my thanks to all of you who have also joined the call today, and for your interest in the company.

We're at the halfway mark in 2014, and I'm pleased to say that our company's performance is progressing consistent with our plans this year.

Top line growth and margin expansion are showing up in our performance, and we're delivering on our commitments.

The second-quarter was certainly a volatile one geopolitically, and there was a lot of sector activity on the domestic front.

All of which we of course watch closely, but we continue to take what we believe is a sound, long-term approach to the business.

So we're staying the course, and sticking to our plans.

And our goal, as we've mentioned numerous times, is to deliver predictable, consistent performance.

And I think we achieved that again in this second-quarter.

Operationally, the business ran very well.

We produced 1.556 million BOE per day from continuing operations, excluding Libya, which represented growth of 6.5% year-over-year.

Now adjusted for downtime and Libya, we grew underlying volumes 4% this quarter compared to one year ago.

And this performance exceeded our prior guidance, which Matt will cover in a bit more detail in his comments.

But our growth came from several places, notably the Eagle Ford and the Bakken, but as well as recent start-ups in Europe, Asia Pacific, and in the oil sands.

And the work continues to bring additional major projects online later this year, and into 2015 and 2016.

Now if I switch financially, the quarter was also very strong.

Adjusted earnings were $2 billion or $1.61 per share, that's up 14% year-over-year.

Our cash flow from operations, including the equity affiliate distributions, funded our capital and dividend for the first half of the year.

That leaves our cash position relatively unchanged from year-end 2013.

And we're also seeing the visible margin growth.

And that should accelerate later in the year and into 2015, as our volumes continue to increase in high margin areas.

Now strategically while we're focused on our high value asset base that has a lot of running room, we're also looking to add organic options and choices through exploration.

Today, in addition to our unconventional and Gulf of Mexico exploration activities, we're drilling in Senegal and Angola.

Now these two areas have higher risk, but also higher reward if successful.

And we recently took a position in a large exploration concession offshore Nova Scotia.

And yesterday, we announced the completion of our sale of our Nigerian business, and that's a big milestone that completes the strategic divestiture program we announced two years ago.

That program has generated nearly $14 billion of proceeds for our company, so with these divestitures behind us, we're now fully focused on executing our growth plans.

Finally, earlier this month, we approved a dividend increase of 5.8%.

Giving back capital to our shareholders remains a top priority, and we believe an attractive dividend is the key part of our investment offering.

Now that's kind of a quick recap of the quarter, but let me just recap the key messages.

The business is on track.

We're delivering on our commitments, and are building a strong momentum for the second half of the year and beyond.

So with those brief opening comments, now let me turn it over to Jeff for a financial review of the company.

Thanks, Ryan.

I'll begin by reviewing the second-quarter's results, which are found on slide 6.

As you will see, it was a straightforward quarter overall.

Production volumes exceeded guidance, and the balance sheet remains strong.

Looking at earnings, second-quarter 2014 adjusted earnings were $2 billion or $1.61 per diluted share, 14% above last year's second-quarter.

Second-quarter earnings are shown on the chart on the lower right.

Segment earnings are shown on the chart on the lower right.

The financial details of each segment can be found in the supplemental data that accompanied this morning's release, but I'll highlight a few items for you.

The Lower 48 segment earnings this quarter largely reflected ongoing volume increases, led by Eagle Ford and Bakken, which contributed to a 22% increase in Lower 48 liquids production year-over-year.

This benefit was partially offset by wider differentials, and $85 million of higher exploration expenses, as a result of the Coronado Miocene appraisal well and the Deep Nansen wildcat well being deemed non-commercial.

Canada continues to have a very solid year.

This quarter's earnings reflected strong bitumen prices, and steady production growth.

Alaska performed in line with expectations.

Europe production benefited this quarter from continued major project ramp, and better than planned turnaround activity.

Sequentially, earnings in Europe were negatively impacted by lift timing, increased maintenance costs, and lower natural gas prices.

Our Asia Pacific and Middle East segment, continues to perform well.

Earnings this quarter benefited from some favorable lift timing versus the first-quarter.

One quick note on our Other International segment, effective this quarter, we moved our Latin American and Poland operations into this Other International segment.

And our Corporate segment results were also in line with guidance.

Lastly, you'll see from our earnings release this morning that we have reaffirmed our prior guidance for capital, DD&A and our Corporate segment.

Exploration expense guidance of $1.5 billion is also unchanged, and includes risked dry hole expense.

The outlook for production and SG&A costs is up modestly from our prior guidance to a range of $8.7 billion to $8.9 billion compared to the original guidance of $8.5 billion.

If you'll turn to slide 7, I'll cover our production results for the quarter.

As you know, our convention for production is continuing operations, excluding Libya.

On this basis, our second-quarter averaged 1.556 million BOE per day, which compares to 1.461 million per day in the second quarter of 2013.

This is a headline increase of 95,000 BOE per day or 6.5%.

2.5% of this growth was due to lower downtime, and 4% or 60,000 BOE per day represents organic growth.

This 60,000 BOE per day of growth was essentially all from increased liquids production, with the largest source of growth being the Lower 48 unconventionals.

Declines in North America gas production were offset by increases in international gas production.

I'll review margin growth next on slide 8. This slide shows changes in cash margins from second quarter of 2013 to the second quarter of 2014, and also on a sequential basis.

On the left side of the chart, are the margins on an as reported basis, which were up 11% year-over-year.

And on the right, are our margins on a price normalized basis.

So on a price normalized basis, margins improved 2.4% year-over-year.

Among the factors influencing margins in the second-quarter were positive impacts from lower production in Libya, and a positive impact from increased liquids production in the Lower 48, and adverse impacts from increased cost levels and wider differentials.

As we've said previously, this metric will tend to be volatile on a quarter-by-quarter basis.

But we expect margins to improve, as we continue to shift production to higher-value products into places with more favorable fiscal terms.

Once the heavy maintenance is completed in the third-quarter, we expect to see stronger underlying margin growth in the fourth-quarter, as higher margin volumes grow.

And this sets us up well to achieve full year 3% to 5% margin growth in 2014.

Finally, I'll review our cash flow waterfall for the first half of the year on the next slide.

As Ryan mentioned, we remained cash neutral over the first half of the year.

We began with $6.5 billion of cash and short-term investments.

We generated $8.6 billion from operating activities, and also added $1.3 billion from the FCCL distribution earlier in the year.

With this, we've funded our capital program and dividend, and ended the first half of the year with $6.4 billion in cash and short-term investments.

The recent Nigeria closing will add net proceeds of approximately $900 million in the third quarter.

Recall, approximately $550 million of the $1.4 billion of sales proceeds were already collected and included in our cash balance.

I'll wrap up the review of our financial performance by noting that we continue to have a strong balance sheet, which gives us significant flexibility to execute on our investment plans.

Now I'll turn the call over to Matt for an update on our operations.

Thanks, Jeff.

As Ryan and Jeff already mentioned, the business is running well, and we're delivering on our organic growth goals.

We exceeded our production guidance in the second-quarter across several of our business segments, but particularly in the Lower 48.

Now some of this outperformance is probably not repeatable, and I'll explain that in a minute or so.

More importantly, once we are through our annual turnaround activity in the third-quarter, we expect to accelerate our growth in the latter part of the year.

And that's going to position us for a strong 2015 and beyond.

So it's an exciting time for the business.

Please turn to slide 11 for an update on our Lower 48 and Canada segments.

In the Lower 48, the second-quarter production averaged 540,000 BOE per day.

That's a 10% overall increase from the second-quarter of last year, and represents a 30% increase in crude oil production over the same period.

Sequentially, volumes grew 33,000 BOE per day or 7%, and the biggest contributors to growth in the quarter were the Eagle Ford and Bakken.

The Eagle Ford grew at 12% sequentially from an average of 140,000 BOE per day to 157,000.

We experienced a strong second-quarter as we brought on a higher than average number of wells in March, commissioned a number of compressor projects, and experienced flush production coming from the recovery of first-quarter weather impacts.

The remainder of 2014 will see a flatter production profile, as we continue to move to multi-well pad drilling, and the medium term slows down the number of new wells coming on production.

But production from those wells will start to show up late this year and into next year.

The Bakken was up 19% from last quarter, averaging 51,000 BOE per day compared to 43,000 in the first-quarter.

This growth was helped by flush production and backlog reduction.

We expect to have multi-pad drilling effects, and we're anticipating winter weather impacts in the fourth-quarter, so the rate of growth will slow in the second half of the year.

The net effect of this is we're still on track to achieve our 2014 volume targets for both the Eagle Ford and Bakken.

But we do expect rates to flatten in third and fourth quarters, and then begin to ramp up as we head into 2015.

Unconventional appraisal also continues in the Permian and the Niobrara, and we remain optimistic about these emerging plays.

In addition to our unconventional activities, appraisal continues this year in the deepwater Gulf of Mexico on all four of our significant discoveries: Shenandoah, Tiber, Gila, and Coronado.

Our Canada business also performed very well operationally during the second-quarter.

We produced 284,000 BOE per day, which includes a 19% increase in liquids production year-over-year.

In the oil sands, Foster Creek Phase F is expected to start producing in the fourth quarter of this year, and Surmont Phase 2 remains on schedule for first steam in mid-2015.

Our western Canada program continues to deliver good returns, with a large identified drilling inventory.

And we continue to explore and appraise our unconventional plays in the Duverney and Montney.

On the exploration front, we acquired a 30% working interest and approximately 5 million gross acres off the coast of Nova Scotia, and drilling is expected to begin there in late 2015.

Next, I'll cover our Alaska and Europe segments on slide 12.

Alaska average production was 193,000 BOE per day, in line with expectations.

At CD-5, the Alpine Central Facilities tie in project has begun, and all fabrication is now underway.

This project remains on track for startup in late 2015.

In the second-quarter, we resumed exports from our Kenai LNG plant in April, and we've already sold two cargoes.

We're also making good progress at our Drill Site 2S, Greater Mooses Tooth 1 and 1H News projects.

1H News is the third new project we've initiated since the passage of the More Alaska Production Act last spring.

On June 30th, the AKLNG parties executed a joint venture agreement.

In addition, we've jointly applied for an export license from the Department of Energy.

So we're making progress on the technical work to assess the feasibility of this project as a way to monetize the significant North Slope gas resource space.

Finally, we recently executed a contract for a new-build rig to begin drilling in 2016.

The one last point on Alaska, as you probably know, Alaskans will vote in August on whether or not to uphold the More Alaska Production Act, commonly known as SB21, and we certainly hope the legislation prevails.

We believe it's important for continued oil and gas development in Alaska.

Where we have identified and are actively developing opportunities for growth.

Moving on to Europe.

Second-quarter production averaged 213,000 barrels a day, up 23% year-over-year, reflecting major project startups at Ekofisk South, Jasmine, and EIS, as well as lower downtime than the second-quarter of last year.

During the second-quarter of this year, we completed our J-Area turnaround work ahead of schedule, and brought online the J12 exploration well.

The Britannia Long-Term Compression Project is on track to start up later this quarter.

Sail away and installation of the top sides was completed at Eldfisk II, and the project remains on schedule for early 2015 start up.

With significant turnarounds underway in the UK this quarter, this will impact third-quarter volumes as we expected.

But overall, the Europe segment is operating well and remains on schedule to deliver on its growth commitments.

Now let's review our Asia Pacific and Middle East segment, and our Other International segment on slide 13.

In APME, we produced 322,000 BOE per day in the second-quarter, roughly flat with last year.

But the segment remains positioned for high-margin growth in the second half of the year and into 2015.

Our partner operated Gumusut project is progressing toward first oil late in the third-quarter.

In June, the top sides sailed away for our Kebabangan project and was successfully installed.

And we remain on track for first production there in the fourth-quarter.

At APLNG, the first Condabri gas processing facility started up this quarter, and that was an important milestone for the upstream project.

On a combined downstream and upstream basis, this project is now about 75% complete and remains on schedule for a mid-2015 start up.

Finally, we continued evaluating opportunities with ongoing appraisal offshore in Australia at Poseidon and Barossa.

In our Other International segment, the key 2014 activities are exploration related.

Currently, we're drilling the Kaxomi well in Block 36 in Angola, and the FAN well in Senegal.

We expect to have some initial drilling results in these wells later in the year.

In Poland, we recently safely completed a 25-stage, 7.5 million-pound hydraulic stimulation of the Lublewo well, and will shortly put the well on an extended flow test.

And in Colombia, we expect to begin exploration drilling in the La Luna shale later this year.

Our volume outlook is shown on slide 14.

So this is our typical chart of quarterly volume guidance for continuing operations, excluding Libya.

The first- and second-quarters represent actuals, and the third- and fourth-quarters show our expected ranges, which are unchanged from prior guidance.

However, our full-year range has narrowed, and the mid-point has increased to reflect our strong operational performance year-to-date.

As expected, third-quarter production drops, primarily due to customary planned downtime.

And this year, the key areas for scheduled turnarounds include Alaska, Canada, the UK and Bayu-Undan.

Importantly, the Bayu-Undan shutdown, which will take about 36 days, will include brownfield activity for the tie in of two new subsea wells that should come on in 2015.

We expect to achieve a strong finish to the year, with an exit rate of over 1.6 million BOE per day.

By the fourth-quarter, our turnarounds should be complete, and several additional incremental projects should come online in the UK, Malaysia, and the oil sands.

In addition to these, we should have ramp gas sales to QCLNG in Australia, which are scheduled to commence in the fourth-quarter.

The bottom line, is we expect to deliver 3% to 5% production growth this year, with strong momentum going into 2015.

So this concludes my comments, and I'll turn it back to Ryan for closing remarks.

Thank you, Matt.

So our story this quarter is really no different than our previous several quarters.

We're focused on delivering our stated goals of 3% to 5% volume and margin growth, while returning capital to our shareholders through an attractive dividend.

Our capital plans are on track, cash flow neutrality is getting closer, and we continue to create options and choices to sustain our long-term success.

So we're following the plan and the path that we laid out over two years ago, and it's working.

So with those comments, I'll turn it over back to the operator, and we'll take your questions.

Thank you.

(Operator Instructions)

Our first question is from Ryan Todd of Deutsche Bank.

Great, thanks, everybody.

If I could start with one on the US onshore.

I appreciate the clarity on the trajectory over the second half of the year.

But if we look at the Eagle Ford and the Bakken, I know you're quite active on both spacing pilots and then in the Eagle Ford as well with the upper Eagle Ford there.

Any comments on what you've seen so far, and what the trends are in that direction?

So we're still executing all of those pilots, as we announced earlier this year that we had enough evidence accumulated to go to what we call an 80-acre high/low development plan in the lower part of the Eagle Ford.

So we're implementing that now.

And we're continuing the pilot tests looking at the upper Eagle Ford, and looking at tighter spacing there.

And the same comments really apply in the Bakken.

We're still looking at the opportunities to tighten up well spacing and other layers.

But there's nothing really new to report there, Ryan, this quarter.

Okay, great, thanks.

And then if I could -- maybe one follow-up on the cash margin trends.

There was a slight down tick there, and I realize this is on the quarter basis, it's pretty dangerous.

But, a slight down tick in 2Q.

Were there mix shift issues?

Can we think about how mix shift affected this?

Was it a result of some of the cost increases that we saw in the quarter?

And looking forward over the rest of the year with the heavy turnaround schedule in 3Q, how would you expect trends to go?

Yes, I think you have the correct observations there, Ryan.

Mix shift continues to be a pretty substantial positive for cash margins.

I think what we saw this quarter is that was offset somewhat by wider differentials that we saw across our portfolio.

When we look at cash margins, we do a price normalization based on how much marker prices have moved.

And when we don't see the same kind of movement in realized prices that we saw in marker prices, that has adverse impacts on cash margins.

And that was the case this quarter, when we saw some wider differentials across the portfolio.

And we did see some level of higher costs as well.

But mix shift is still long-term what's driving higher cash margins, and we're going to continue to see that trend develop.

I think your observation at the very beginning is this is volatile from quarter-to-quarter is something that we're going to continue to emphasize.

But if you look over the whole year, of course as we mentioned earlier, we are on track to be in the 3% to 5% margin growth range on a price normalized basis.

That's, great.

Well on your comments on the cost increase side, on the cost, was some of that driven by just the fact that you guys have raised production guidance a little bit?

Where the higher production has brought some -- a little bit of higher cost, or was it all inflation?

There's a bit of that, both of those in there.

If you think about what we've done with cost guidance overall, if we started the year with a cost guidance of $8.5 billion, that compares to a number that was more like about $8.25 billion or so last year.

So we increased our costs about equivalent to what we were projecting production growth.

And what we're finding is a little bit higher production growth and just a little bit higher costs than what we've seen before.

There's not any one particular item we can point to on costs, but costs are generally a couple percent higher than what we thought at the beginning of the year.

Great.

I appreciate that, I'll leave it there.

Thank you.

Thanks, Ryan.

Our next question is from Blake Fernandez of Howard Weil.

Folks, good morning.

Thanks for taking the question.

I was curious, some of your peers in the Eagle Ford have applied and received permits for exporting condensate.

And I'm curious if you can comment as to whether, for one, you have applied for a similar permit, and if not, do you think that would be something that could benefit your realizations in the basin?

Yes, thanks, Blake.

We're aware of what a lot of people are doing on the export.

We've been out pretty publicly as a company supporting and advocating on behalf of not only the condensate exports but the crude oil exports as well, which we think the condensate solves a very, very small problem.

The larger issue we are having in North America, as you're aware, is the growing light oil production and the inability or the capacity being used up in the refining sector to really absorb that creating some of the differential issues that Jeff talked about and even facing back.

But we follow it pretty closely.

Right now, we're getting most of our condensate to the Gulf Coast, putting it on ships, and getting it around.

We don't see the net back, but certainly we watch it pretty closely.

And if we think there's an advantage to doing that, we'd be in talking with the Department of Commerce as well.

Okay great.

The second question, this is probably a long shot.

But in the past, you had used proceeds from asset divestitures to buy back stock.

I fully appreciate that you're past that program, but at least looking first half of the year, you're technically cash flow neutral.

And I'm just curious if there would be consideration to maybe use those proceeds to buy back some additional stock?

Yes, thanks, Blake.

Appreciate it.

I think as I said before, we're executing the plan we laid out.

And that plan from a couple years ago, we knew we were being a little bit short of cash flow neutrality.

But we grow into that by 2016, so we're really using the cash on the balance sheet to fund the programs that we've got.

We made those assumptions at modest commodity prices, because commodity prices have maybe been a little bit higher than our expectation.

It's freed up a little bit of cash, but it's really going to our investment program.

And to the extent we fully and fund all of our high-quality investment programs, we'd consider share buyback at that point in time.

But right now, it's being used to fund our dividend and our capital program.

Thank you, Ryan.

Our next question is from Paul Sankey of Wolfe Research.

Hello, everyone.

Morning, Paul.

Hey, guys.

Your CapEx is high relative to the $16 billion that you've guided to on an annual run rate.

Could you talk about whether you're tempted to spend a little more given things are going so well for you?

And particularly I'd noticed that the exploration expense is up, so whether or not that you may be spending a bit more in exploration given that as I said things are going so well.

Thanks.

So CapEx for the year is running pretty much right on track with our guidance.

We've guided to $16.7 billion for the year, and I think we're $8.1 billion through half of the year.

So a little bit less than the CapEx base.

We still think we're on pace for about $16.7 billion for the year on capital.

But are you going to keep that flat going forward?

I'm still working I guess back on the old number of $16 billion as the run rate that we were working towards when you started the --

Yes, as we talked about at our analyst presentation in April, I think we see capital in the $16.5 billion, $17 billion range for the next few years.

[Management note added by the company after the call: At the April 10th Analyst Meeting, the company disclosed a capital program averaging ~16 billion per year from 2014 through 2017.]

Yes, I think that what I'm trying to drive at is really the exploration program, and whether or not you're happy with how much is being spent there, and whether or not you'd consider spending more.

Yes, I would say, Paul, we're taking advantage of some opportunities.

We talked about Nova Scotia, and we're drilling now in Angola and Senegal both.

I view sort of the capital the $16 billion that we've talked about is running this year at about $16.7 billion as we said earlier at the analyst meeting.

But that's looking at opportunities that we have in the portfolio and some of the extra cash we're getting from the higher commodity prices and deploying that into places we think are adding value.

Both in a little bit faster pace in the Eagle Ford and Bakken, and some of the exploration that we're doing around the world.

And deepwater Gulf of Mexico?

Yes, so we have an appraisal program going there, Paul, in all of our existing discoveries and that's what dominates our exploration capital for this year in the Gulf of Mexico.

Okay, I get it.

I'm just trying to really focus on the idea that we want to keep the capital down.

But I understand that, particularly in the GOM, there was the potential to spend more on outright exploration.

You successfully closed the -- keeping it on the cash theme, you've successfully closed the Nigeria deal, which I think was pretty much the last one if I'm not wrong of the previous program.

Is there potential for you to further improve the cash balances by more, another round of major disposals?

Thanks, and I'll leave it there, thank you.

Thanks, Paul.

Yes, no I think in terms of the announced large disposition plans, Nigeria really completes that out of what we talked about when we spun the company a couple years ago.

As I tell people, we continue to look at the portfolio, and try to high grade it as opportunities present themselves.

And we'll continue to look at that, but I don't see another major capital disposition program or announcement that you'll see coming from us.

But we'll be constantly looking at trying to high grade the portfolio, and clean up the bottom end.

And focus all of our investments in the top end of the portfolio that really is driving the growth in the higher margins and the returns.

Our next question is from Doug Terreson of ISI Group.

Good morning, everybody.

Morning, Doug.

In Australia, it appears that exploration or maybe appraisal success has continued or recently near the Poseidon discovery, which I think Matt might have alluded to.

And on this point, I wanted to see if there were any updates there.

And also, whether one type of development is more likely than another, meaning is this hopefully going to eventually feed the LNG facility nearby.

So just a general update on that situation is what we're after.

Okay, thanks, Doug.

We're getting close to completing our appraisal program on the Poseidon complex.

And we've designed that program to get us the information to do exactly what you were asking, Doug, to make sure that we were optimizing the development plan for Poseidon.

And we've got the same goal in mind in the exploration that we've just commenced in the Barossa area.

So basically, this appraisal activity is designed to establish what is the best back fill opportunity for the Darwin LNG plant, for example.

Okay, thanks a lot.

Thanks, Doug.

Our next question is from Ed Westlake of Credit Suisse.

Hello, good morning.

Actually good afternoon then.

Just actually a quick follow-up on Australia.

How much gas do you think you'd be able to get over and above APLNG from sales to the other projects in the area?

I think you mentioned QCLNG gas.

Any rough order of magnitude?

Well it depends very much on when these projects start.

We do intend to take the opportunity to sell ramp gas to those projects, but the exact magnitude of that will be dependent upon the timing of those startups relative to our start up.

So it's hard to put a number on that just now, but we have the capacity available to provide those ramp gas sales when the opportunity arises.

I'm going to get to something more closer to home, but any progress on Venezuela or timing around that?

Yes, Ed.

On Venezuela, we're in discussions with the tribunal, both sides, ourselves, and the Venezuelans are now putting in their damages assessments and putting forward our positions with respect to damages that were created from the tribunals earlier award indicating that we were unlawfully expropriated by the Venezuelans.

So that award is old.

So we're in the process now of our damage assessments on both sides, and we're saying that that probably takes about a year to go through that process.

It started a few months ago, but that's the timeline we're operating under.

Okay.

And then moving back into the US, let's just talk briefly about the Permian.

I think in your analyst day slides, you were testing an area over in the Delaware, and then the southern Midland, and I think you gave us the numbers.

I think it was 150 million-acres in the Delaware, and I think just under 100 in the Midland.

So first question, are those the total acreages that you have in those two shale Basins?

Or is it just those areas that you're testing?

And then maybe give us some color about the recent well results and your rig plans for those two basins as we go forward.

And then I have a quick follow on.

So those numbers that you quoted, the 150,000 and 90,000-acres respectively for the Delaware and Permian, those really represent the acreage where we're looking at unconventional development.

We've got over 1 million acres in the Permian as a whole, but those are really representative of the areas where we're focusing on the unconventional exploration and appraisal.

Right now we have four rigs running, and they're all focused just now on the Delaware Basin.

We have well tests underway from wells that we've previously drilled in the Midland Basin, but we don't have drilling activity there right now.

So that's really -- and what we're doing is basically testing the whole section.

As we described at the analyst day, there's 4,500 feet of perspective section within the Permian Basin, and certainly in the Delaware.

And we're going through the process of making sure that we explore and appraise those different horizons so that we've got a clear understanding of what the development plans should be for that going forward.

And are they mainly -- is that mainly lease acreage with royalties, or is there some fee acreage mixed in there from legacy production in terms of royalty position?

The areas that we're focused on for unconventionals are predominantly leased acreage.

Okay, thanks very much.

Thanks, Ed.

Our next question is from Paul Cheng of Barclays.

Hey, guys.

Paul.

On Venezuela, there's a market rumor that Citgo may be selling their refinery.

I'm wondering have you checked with your legal advisor whether you guys can in the event that they the go forward, can you put an injunction on that to force Venezuela to speed up the settlement?

It's probably not appropriate for us to comment on tactics that we might take in that regard, Paul.

Okay, or that maybe as a curve ball for Ryan.

The North American crude [inaudible] market looks like it continues to be extremely volatile.

And it's still not 100% clear that when or if the government is going to allow the export of crude oil.

I know that it's only two years ago that you spinoff the refining.

Have you ever thought about to recreate an integrated operation, or that this is totally behind and you guys not consider given that looked like there's a pretty large refining system may be available in the market now?

Yes, that's a bit of a curve ball, Paul I'll give you that.

Well no, we're pretty much focused on our plans as an independent E&P company.

So we're pretty focused on trying to grow our production, grow our margins as we've outlined.

And be one of the best E&P companies in the space today.

And part of that does, we have a large North American position certainly with the Eagle Ford and Bakken, the unconventionals, and our legacy position in North America.

So the export issue is something that's pretty important to us, and we're spending quite a bit of time advocating on behalf of that both on the Hill and with the administration.

Two final questions.

First, can you share with us any preliminary CapEx and production estimate for 2015?

Well I think we're in the middle of putting our plans together.

But what I would say goes back to the analyst presentation that we did back in April, and our plans really are unchanged from what we described to you guys back then, both capital and production.

And maybe this is for Matt.

Matt, if I'm looking out, you indicate that the third-quarter with the downtime from planned maintenance I know that maybe some of the third-party operation that the startup may be a bit delayed.

If you look at from your standpoint what is the biggest risk for you to achieve your production target or that your planned target for the next 6 to 18 months?

Is there any major project that you think is a little bit more concern or any particular area on the supply chain or anything?

No, I think that the range that we've given for both the third-quarter and the fourth-quarter captures the uncertainty that we see in the overall portfolio.

And the third-quarter is a bit uncertainty on the duration of some of our down time, and the fourth-quarter is dominated more by the timing of new projects coming on.

But one of the advantages that we have as a diversified company is that no individual, no single project is going to make a big difference in the overall scheme of things.

And that diversification in the portfolio helps us to limit the exposure to individual project surprises.

So I think the range that we've given for the third- and fourth-quarter captures all of that.

Our next question is from John Herrlin of Societe Generale.

Three unrelated questions, hopefully not stream of consciousness.

With AKLNG, if you got approval, how long would it take to really develop it?

I know it's beyond the scope of an investor call, but I'm just curious.

Well so we've made a lot of progress in AKLNG this year.

I mentioned that we've signed a joint venture agreement, and applied for export to FTA and non-FTA countries.

So we're starting pre-feed now, that will take 12 to 18 months or so, feed would then take two or three years.

So that our final investment decision would be in the 2016, 2017 time frame, and first production would be out in 2022 to 2025.

So that's the sort of time line that we're looking at, John.

Okay.

Thanks, Matt.

With respect to Poland, Matt, did you run a core on the well you're now testing?

And if so, how did the rocks compare to say gas shales of the US?

So we didn't core the horizontal section, but we do have core information from the vertical wells that we've drilled there.

And it's difficult to tell.

There's a good looking section that we've drilled the horizontal well in.

But as you know, until you actually frac and produce these unconventional reservoirs, it's difficult to know what you're going to get.

So we do have core data.

We have all of the usual data that we would collect in the US.

And the frac that we've just done on this well is basically an Eagle Ford style frac, and so we're giving it our best shot.

And we'll get a sense of whether or not -- what sort of rates we can achieve by the time we get to the end of the year this year.

Okay, great.

The last one for me is regarding your deepwater exploration in Angola and Senegal, are you going to be releasing well results individually or just on the quarterly call?

I suspect that certainly in Senegal, we have smaller companies involved, they will be releasing information about Senegal on a regular basis.

And on the Angola well, I don't know, we'll wait and see where things go.

But we may give some information in advance of the quarterly call, we'll just see how it goes.

Thanks very much.

Thank you, John.

Our next question is from Doug Leggate of Bank of America Merrill Lynch.

Thanks for getting me on guys.

I wanted to follow-up on Paul's question earlier about the front loaded CapEx, or what seems to be front loaded CapEx this year.

In the Eagle Ford specifically, Matt you talked about more completions in the second-quarter.

Can you just give us an idea of what the pace has been relative to I think it was like 190 wells you were planning for the year originally?

Are you running ahead of that, or is that still a good number?

And how much of that are we through so far?

And I've got a follow-up, please.

Yes, so that's a good number, so it's about 50 wells a quarter that we're working through, and that pace has been pretty consistent in terms of getting the wells drilled.

As you know, as we move to pad drilling, there tends to be more batch like as the production comes on.

But in terms of executing, the number of wells that we're drilling, we're on pace for around 190 or so that we thought we would be for this year.

So the second-quarter, I thought from your prepared remarks you had a few more wells come on.

So was it less in Q1 and more in Q2?

Or I'm just trying to understand the pace is you see what I mean.

We had a batch of wells that came on right at the beginning of the quarter, which meant that those wells were in production all the way through the quarter.

So that was one of the reasons that the quarter was a higher production than we expected.

But overall, from a pace perspective, it's much the same from a drilling pace from a completion and bringing on production perspective, that of course is influenced by the batch drilling associated with the pads.

And that's what I was trying to indicate in the prepared remarks, that that's going to be a bit more lumpy than it has been in the past because of the pad drilling.

Got it.

Thanks for that.

My follow-up is a bit more conceptual.

I think it straddles a number of issues, asset monetization amongst them.

But mindful of Ryan's comments earlier, but when you look at some of your peers, Devon Energy for example, with their EnLink situation and Hess has announced that they're now going to do a midstream MLP.

How do you buys think about your midstream infrastructure spending?

Because obviously, it's a big enabler.

And as you guys know, I've been trying to reconcile the level of spending in the Eagle Ford relative to the activity, and I'm guessing midstream is a big part of that.

So how do you think about how you might be able to perhaps more efficiently monetize your midstream given the high level of CapEx?

And I'll leave it there, thanks.

So when you look at our midstream position overall, Doug, going back in history, most of that midstream position went into the DCP joint venture, which has then since gone of course with Phillips 66.

So there's not a lot of midstream assets that are out there that or could form the core of an MLP for us.

As we go forward, we are having some midstream investments in the Eagle Ford and in the Permian.

But those are really not of a size that we feel like we have the critical mass to be thinking about an MLP, but that's something that we'll just continue to evaluate as we go through time.

Our next question is from Roger Read of Wells Fargo.

Hello, good morning.

Or nearly afternoon anyway.

I guess a quick question for you, getting back a little bit to the Lower 48.

We've seen I guess a two-pronged question.

One is, your gas production only down slightly here on a year-over-year basis after declining fairly aggressively for the last several quarters or years.

Is that something now that we see the size of your shale play associated gas enough that gas production itself is done going down?

And I think of that as consistent with what we've seen across the broader industry, but I was hoping for some clarity on that.

Yes, gas production, in the broad sense, is going to remain relatively flat in the Lower 48.

We're not drilling any wells dedicated to dry gas, but we have associated gas production with the Eagle Ford and the Bakken, for example.

Such that on a broad basis, we're going to be relatively flat in overall gas production probably for the next several years.

The follow-up to that, we've seen one company, a very large one in this space, do a swap of one type of likely very gassy assets for stuff in the Permian.

Is that something within an overall, I don't want to call your CapEx constrained, but let's say at least a capped level of CapEx, that you would be interested pursuing?

The big asset sales are essentially done with Nigeria, but I was wondering if that's maybe something on the little more imaginative side that you'd be willing to pursue here?

Yes, really that goes along with what Ryan was saying earlier about -- on an opportunistic basis, the things like swaps of underlying assets might make sense to us.

So we're always open to consider those sort of things, but it's not a big part of our ongoing plans.

And if you were to look at more acreage in either the Permian or the Niobrara given your efforts that are ongoing right now, is that how we should think of the funding?

Or is it, that's a future unallocated CapEx in 2015, 2016 or 2017?

In the plans that we've laid out for around $16 billion of capital, we're including in there the fact that we intend to be developing our overall unconventional resource base.

Including the Permian and the Niobrara.

And that includes, Roger, some lease acquisition moneys as well.

So we're in the market every day, every week in these areas trying to build our positions and core up what we think are good deals.

Okay, I appreciate it.

Thank you.

Thanks, Roger.

Our next question is from James Sullivan of Alembic Global Advisors.

Hey, folks, thanks for taking the questions.

I just wanted to look ahead a little bit, as you guys are absorbing the results of the non-op US Gulf of Mexico program that you guys have been participating in the last couple years, could you speak just a little bit about what looks interesting to you as you contemplate launching the operated program next year?

Yes, our primary focus in the Gulf of Mexico has been and will continue to be the Paleogene.

We do have some interest in Miocene prospects that we will drill when we get our operated rig slots available.

But I would say that the primary focus going forward will be in the Paleogene.

And we've had a lot of success there as you've seen with the four significant discoveries.

And we've got over 2 million-acres of deepwater position there, and I think it's about 70% or 80% Paleogene focused, but we do have some interest in the Miocene opportunities as well.

Okay, great.

The other thing I want to talk about quickly on the onshore, obviously you guys have commented generally about the programs in the Permian and the Niobrara.

But just looking at the Niobrara, and I know that you probably don't have much you can say about the anti-fracking measures on the ballot and so on in terms of handicapping that.

But has that affected your activity levels there?

Or are you guys thinking about ratcheting back whatever your plan was in the second half of 2014, as you think about risking the likelihood of some type of negative outcome over there?

No, that hasn't affected our execution or our plans, James.

We'll just have to see if those ballots actually make it to the electorate or not, and then we'll adjust the plans if we need to based on what those results are.

But no kind of proactive stuff.

I'll just, if I could, sneak one more in.

I know you guys are doing a stratigraphic well on the La Luna in Colombia onshore this year.

I wonder if your guys or a couple of other operators have picked up bigger offshore pieces in the license around that they've run out there that are also -- and they've talked about targeting the La Luna offshore.

Have you guys looked at that or would you consider that?

Right now, we're focused on the onshore position that we've built.

We've got a good position we believe in the La Luna, and you're absolutely right.

The first well out there later this year will be a stratigraphic test to calibrate the geology, the thermal maturity, and so on.

So at least as far as I'm aware of, we're not looking at offshore for the unconventionals around Colombia.

Great.

Thanks guys.

Thanks, James.

Our next question is from Pavel Molchanov of Raymond James.

Thanks for taking the question.

I realize this is less than 1% of your portfolio, but can't help asking about the Polar Lights with Rosneft in the context of the new sanctions.

Any color on how that might affect the business?

Yes, Pavel, as you know, we've pretty much exited Russia with some of the moves that we've made as a company over the last two to three years.

And right now, we're in a process where we're actually marketing our Polar Lights interests.

So that's hopefully coming to some sense of conclusion over the course of this year.

Okay, fair enough.

Do you think the sanctions will influence the marketing process, or any side of that?

Well, it hasn't to date, but we watch it.

We obviously watch it pretty closely, as the latest round of sanctions got ratcheted up a little bit more significantly, both on the European and the US side.

To date it hasn't impacted it.

But again, we're watching it closely.

But as you indicate, it's a pretty small portion of the portfolio.

It's not a lot of proceeds, it's what I put in the portfolio clean up category right now that not leveraging but something we just need to clean up in our portfolio.

Understood, and then on APLNG, I realize it's still about a year before start up.

But do you have a sense of how long it's likely to take before it reaches full utilization, full name plate?

Yes, as you know, we have two trains there, Pavel, the first one will come up in around the middle of next year.

The second train will be 6 or 9 months later than that, and we should get to full throughput capacity relatively quickly.

We have the resource base that we need.

We have the wells and facilities being developed that we need to do that.

So we should get to full capacity hopefully by the middle of 2016.

Okay, both trains?

Yes.

Got it.

Thanks very much guys.

Thank you.

Our last question is from Scott Hanold of RBC Capital Markets.

Thanks, just a couple quick ones here.

You obviously discussed a little bit about the midstream monetization opportunity.

Can you discuss a little bit on like mineral interest ownership you all may have?

Anadarko, obviously, came out and discussed some stuff they had.

It looked like there was potentially some value there.

Do you guys have something similar?

We've got a big Lower 48, western Canadian gas portfolio, so we do have assets where we have royalty interest and overriding royalty positions.

And these are positions which provide us with revenue and really high margin production without any kind of corresponding operating expense or capital requirements.

And we think of these like we really think of other assets in our portfolio, is we are always thinking about whether -- what we could sell them for and get on an after-tax basis is more or less than our hold value.

One of the things that you've got to think about in interests like this, is we have pretty low tax basis in these types of assets and that's going to be a real consideration.

So we'll just continue to monitor the asset market for something like this, and evaluate it and see if it's got any applicability for us in the future.

Okay, could you give us a sense of how big that ownership is, and what the revenues are roughly on an annual basis?

We really think it's probably more appropriate that we'd do something like that if we get serious about doing a transaction like this.

Okay, understood.

And my second question is, on Jasmine, I guess one of your partners discussed some compartmentalization and some performance not to expectations.

Can you give us a little bit of color on that, and what you all think you can do here?

Yes, the Jasmine production performance has been a bit below what we anticipated it would be, because of a bit more reservoir complexity.

It's within the range of our expectations, but at the lower end of the range.

And in fact, as we were drilling the Jasmine development wells, we actually now believe that there's more gas and condensate in place in Jasmine than we thought.

But it's a bit more stratigraphically complex.

So we're evaluating that just now.

And because we knew that there was some uncertainty here, we actually installed a platform at Jasmine that has 24 slots on it.

And our initial plans were only to drill eight wells from it.

So there's a lot of flexibility for us to add production and overcome this reservoir heterogeneity issue as time goes on.

Could you give us a sense in what an incremental CapEx spend it would take to get it back to say the mid-point of that range of expectations?

No, it's really too early to say, Scott.

We're digesting the results from our production performance to date, and we'll build out any of our plans as we get as we get a better understanding of the reservoir dynamics.

Okay, understood, thanks.

Thank you.

I will now turn the call back over to Ellen DeSanctis, Vice President Investor Relations and Communications.

Thanks, Christine.

Thanks, everybody.

Feel free to call us if you have any future questions or follow-up questions, we appreciate again your time and interest.

Thank you.

Thank you, and thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.

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