Gary T. Clark - Vice President-Investor Relations John J. Christmann - President, Chief Executive Officer & Director Stephen J. Riney - Chief Financial Officer & Executive Vice President Timothy J. Sullivan - Senior Vice President-Operations Support.

Pearce Wheless Hammond - Simmons & Company International Evan Calio - Morgan Stanley & Co. LLC Doug Leggate - Bank of America Merrill Lynch Brian A. Singer - Goldman Sachs & Co. Robert Scott Morris - Citigroup Global Markets, Inc. (Broker) John P.

Herrlin - SG Americas Securities LLC Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) John A. Freeman - Raymond James & Associates, Inc. Charles A. Meade - Johnson Rice & Co. LLC Leo Mariani - RBC Capital Markets LLC Michael A. Hall - Heikkinen Energy Advisors Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc. David R.

Tameron - Wells Fargo Securities LLC.

Good afternoon, my name is Jennifer and I will be your conference operator today. At this time, I would like to welcome everyone to the Apache's Third Quarter 2015 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. Thank you. And Mr.

Gary Clark, you may begin your conference..

Thank you and good afternoon. Welcome to Apache Corporation's third quarter 2015 earnings conference call. Speakers making prepared remarks on today's call will be Apache's CEO and President, John Christmann; and CFO, Steve Riney.

Also joining us in the room is Tom Voytovich, Executive Vice President of International and Offshore; and Tim Sullivan, Senior Vice President of Operations.

In conjunction with this morning's press, I hope you have had the opportunity to review our quarterly earnings supplement, which summarizes Apache's regional operating activities and well highlights.

The supplement also includes our revised full-year 2015 guidance, details of our capital expenditures in the quarter, as well as a chart that illustrates cash sources and uses and reconciles Apache's change in net debt during the third quarter of 2015.

Our earnings release, the accompanying financial tables and non-GAAP reconciliations and our quarterly earnings supplement can all be found on our website at www.apachecorp.com. I'd like to remind everyone that today's discussions will contain forward-looking estimates and assumptions based on our current views and most reasonable expectations.

However, a number of factors could cause actual results to differ materially from what we discuss today. A full disclaimer is located with the supplemental data on our website.

Also, please note that in this morning's press we have consolidated our production and pricing information for the Midcontinent and Gulf Coast regions, which is were reported separately. I would now like to turn the call over to John..

Thank you, Gary. Good afternoon and thank you for joining us today. Before I dive into our results for the quarter I would like to take a step back to highlight the progress we have made so far this year. We have significantly streamlined and high graded our portfolio.

The result is a focused North American onshore position with significant visibility and an international portfolio, which delivers tremendous free cash flow and very good exploration upside, as evidenced by our announcement last week regarding recent discoveries in the North Sea, along with our consistent exploration success in Egypt.

We have strengthened our balance sheet and liquidity. We used the proceeds from asset sales to pay down debt and to increase our cash position. During this time, we also refreshed and extended our credit facility. Apache's balance sheet is now a leader amongst our peers, which we have accomplished without issuing new equity.

Over the last third quarters, we reduced our drilling and completion program to a level that is appropriately aligned with the current commodity price environment. Notably, we generated a cash flow to CapEx surplus in the second quarter and would have maintained a surplus in the third quarter if commodity prices hadn't further eroded.

This need for spending discipline is something that many in the industry are just beginning to realize and pursue. We have now achieved a nearly 30% reduction in our average well cost compared to a year ago.

We have relentlessly pursued cost reductions both through supply chain efficiencies, as well as self-help through such things as improving wellbore and completion design. We made significant reductions in our run rate for both LOE and G&A costs, and we are taking steps to realize additional savings through the fourth quarter and into 2016 and beyond.

We have delivered production growth both domestically and internationally, despite a dramatically reduced activity level. This result has been supported by our low underlying base decline, and today, we are again increasing our 2015 production guidance.

And lastly, we continue to leverage our technical expertise and experience to seek out potentially high impact, new resource plays by consolidating acreage and expanding our footprint within our existing operational basins. We remain highly disciplined in this effort.

And it is important to note that we are not paying the high prices for acreage that are common in the high profile resource plays. Now let me turn to our third quarter results.

The third quarter was another good one for Apache as we delivered on our operational and financial guidance, made excellent progress on our cost reduction initiatives, and had tremendous success with the drill bit, most notably in the Permian Basin, Egypt and in the North Sea.

As a result, we are increasing our 2015 production guidance range for both North American onshore and our international and offshore regions. During the third quarter, WTI oil prices deteriorated to an average of $46 per barrel, which was a 20% decrease from the second quarter average.

However, the impact on our capital program for the quarter was relatively small as we had the foresight to pace our spending based on a $50 WTI plan price for 2015. As we indicated on our second quarter earnings call, our North American onshore production decreased sequentially in the third quarter, but the drop was less than anticipated.

The decrease was primarily driven by facility downtime in the Permian, natural decline rates and the timing of well completions. We continue to expect North American onshore production volumes to increase for the fourth quarter, and we should exit the year with solid production momentum.

Currently expect to finish the year at the high end of our upwardly-revised North American onshore production guidance range of 307,000 boe to 309,000 barrels of oil equivalent per day, which reflects normal fourth quarter weather-related downtime.

Should we experience unusually severe or extended weather disruptions, production may potentially move to the middle or low end of our new guidance range. As I mentioned earlier, both Egypt and the North Sea have been performing very well this year.

Production from our international and offshore regions averaged 180,000 boes per day during the third quarter.

The key factors contributing to this strong performance were excellent production efficiency or uptime, strong sustained production from existing wells and significantly better-than-expected contributions from new wells completed during the quarter.

As a result, we have increased our 2015 international and offshore guidance range, which Steve Riney will discuss along with other updated guidance items shortly. Our CapEx in the third quarter, before leasehold, capitalized interest and non-controlling interest, was $762 million.

This is down 16% from the second quarter and 38% from the first quarter and puts us well within our full-year guidance for 2015. Across all of our regions, we are continuing to pursue and deliver substantial capital cost improvements.

For example, in the third quarter, our North American onshore well costs were down approximately 30% from a year ago, which represents an improvement from the 25% decrease we cited last quarter. Now I'd like to turn to some of our key regional highlights for the quarter.

During the quarter, we operated an average of 28 rigs companywide, 12 in North America, 10 in Egypt and six in the North Sea, which represents a decrease of six rigs from the second quarter.

For the last two quarters, we have essentially been running our business at an activity level where cash flow was roughly equal to CapEx under a $50 WTI oil price deck. Given the decrease in oil price during the third quarter, we elected to defer the addition of two rigs in the Permian and one of our two planned rig additions in the Eagle Ford.

As a result, we are decreasing the high end of our 2015 capital spending guidance range by $100 million to $3.8 billion. The deferral of these three rigs will not materially impact our 2015 production, but will result in a lower drilled-but-uncompleted well count at the end of 2015 than we previously expected.

In the Permian Basin, our production was 170,000 boes per day, down 2,100 boes per day from the second quarter. This was driven by a combination of facilities downtime and the timing of well completions. Despite these factors, our Permian production remained strong. This underscores the importance of our relatively low base decline rate of 22%.

Some notable activity during the third quarter came from new completions on our Condor lease at Pecos Bend in the Delaware Basin. We completed four wells that materially exceeded our type curve on a per lateral foot basis in their first 30 days.

Returns in the Delaware remain very strong, as we have achieved average well cost reductions of approximately 40% since 2014. In the Midland Basin, we brought our first well pad online at Azalea in Western Glasscock County and are seeing encouraging early results.

This area has the potential for multiple landing zones, including upper and middle Wolfcamp and lower Spraberry targets. We also brought online four good wells in our Powell-Miller area, three with an average 30-day IP of more than 800 boes per day, and another with a 24-hour test rate in excess of 1,600 boes per day.

In the Central Basin Platform and Northwest Shelf, we are continuing to see excellent results from our horizontal Yeso play at Cedar Lake, which is delivering very attractive returns at these low oil prices. We have also dedicated resources to our water flood effort and other low-decline EOR opportunities.

We have a significant low decline base in the Central Basin Platform, which helps underpin our lower underlying decline rate that I referenced earlier.

While our overall Permian activity levels are down substantially from 2014, we remain committed to testing the resource potential of several new areas across our significant acreage position and to identifying and unlocking additional resource for the long term. Turning to the Eagle Ford.

We brought eight wells online during the quarter in our Ferguson Crossing area with an average 30-day IP of 1,545 boes per day. We have made great progress in optimizing the completion design and increasing the productive capacity of these wells, while at the same time, continuing to drive down costs.

We have one rig working in the Eagle Ford for the remainder of 2015. In the Woodford/SCOOP, we are in the early stages of delineating our approximately 200,000 acres gross and 50,000 net acres. During the third quarter, we brought online the Truman 28-6-6 #1H, which recorded a strong average 30-day IP rate of 1,949 barrels of oil equivalent per day.

We have two rigs running in the Woodford/SCOOP for the remainder of 2015 to continue delineation and to advance our understanding of this attractive acreage position. In Canada, we put our seven-well Duvernay pad online in late October.

Completion and connection of the pad came in under budget and the flow results we have seen to-date are very encouraging. The team is doing an excellent job with costs in Canada and we plan to drill another Duvernay pad during the upcoming winter season.

On our Montney acreage in the Wapiti area, we have received substantial interest from third parties regarding a potential joint venture with Apache and we are advancing these discussions. Our objective for the JV is to fund early-stage drilling and infrastructure.

This will enable us to jump-start the investment program and begin to generate cash flow without having to divert our capital dollars from other areas of the portfolio. Turning to our international operations; during the third quarter, Apache became the largest oil and gas producer in Egypt on a gross operated basis.

We are very proud of this achievement and the fact that our gross production has returned to peak levels established back in 2011 and 2012. The key here is that while production is at peak levels, our percentage of oil and our margins are now considerably higher when normalized for commodity prices.

It should be noted that these production levels have been achieved despite a 35% reduction in capital spending year-to-date compared to 2014. This highlights the operational success for our teams and our ability to do more even in a reduced capital environment.

Our strategy in Egypt is to target primarily oil and liquids reservoirs and to keep our production profiles as stable as possible. Our late 2014 discoveries of the Ptah and Berenice fields have helped advance this goal in 2015. During the third quarter, gross production from these two fields peaked at over 26,000 barrels of oil per day.

Our objective is to sustain production from Ptah and Berenice at a high rate for as long as possible through the drilling of additional development wells. In addition to Ptah and Berenice, we have seen new discoveries across multiple concessions this year, which will continue to support our production and free cash flow generation in Egypt.

In the North Sea, we had a strong third quarter as our sequential production grew more than 4,200 barrels of oil equivalent per day from the second quarter. We set a new production efficiency record of 92% uptime in the third quarter as we experienced minimal platform maintenance downtime.

We also benefited from better-than-expected performance from new wells drilled in both the Forties and Beryl fields. As we look ahead to the fourth quarter, I should point out that we are likely to experience more weather-related downtime, some of which has already occurred in late October and early November.

On October 30, we issued a press release, which announced three significant discoveries at our K, Corona and Seagull prospects, along with two high-rate development wells in the North Sea.

While still early in the development phase, the ultimate reserve potential of the three discoveries combined could be greater than 70 million barrels of oil equivalent net to Apache. This represents a potential 50% increase over the 145 million barrels of total booked proved reserves for the North Sea at the end of 2014.

For more information on these discoveries and a review of our extensive North Sea exploration and development inventory, please join us for our North Sea Region Update webcast on November 17 at 9 a.m. Central Time.

Similar to my comments on Egypt, it's important to note that the outperformance in the North Sea has been accomplished despite an approximate 25% reduction in capital spend year-to-date compared to 2014.

In closing, as we look to 2016 and beyond, our organization and our balance sheet are well prepared for the possibility of lower for longer oil and gas prices. We have in place the planning, capital allocation and operational structure and focus that will enhance shareholder value, despite the challenging commodity price environment.

Our singular focus is to optimize the growth of our enterprise, while improving returns. We have made great progress so far; recognize that we have more to do. We are now working from a position of strength. We have a premium acreage position in North America and we have the people and the technology to grow it.

We have best-in-class businesses running in the North Sea and in Egypt. These are prolific hydrocarbon basins with many years of exploration and development ahead of them. We have invested heavily in infrastructure in these regions over the last decade, and keeping this infrastructure full by its nature leads to very high rate of return projects.

We have right-sized our activity level and we have driven efficiency improvements relentlessly on both capital and expense. We have a strong balance sheet and good long-term liquidity. And most importantly, all of these improvements are starting to show up with strong results for 2015 and good momentum as we look forward to 2016.

We will remain focused on driving the expansion of our North American portfolio, as it is our primary growth engine for the future.

However, our international businesses have a demonstrated track record of delivering very high rates of return, along with the ability to sustain production volumes through time and provide significant free cash flow back to the corporation. These are franchises that we will continue to invest in for the long term.

I will now turn the call over to Steve Riney..

Thank you, John, and good afternoon. As John indicated, Apache had a very good third quarter. We have made excellent progress on both operational and financial fronts. We also still have much more to do.

Today, I will highlight Apache's financial progress, which will include our financial results for the quarter, the results so far from our relentless focus on costs, a review of our balance sheet strength and liquidity position, our outlook for the remainder of 2015, and an update on our strategic planning process along with some very preliminary thoughts on 2016.

So let's begin with the third quarter financial results. As noted in our press release, Apache reported a GAAP loss of $5.7 billion or $14.95 per common share. Our results for the quarter include a number of items outside of our core earnings that are typically excluded by the investment community in published estimates.

The most significant of those items is a ceiling test write-down of our oil and gas properties totaling $3.7 billion after tax. As in prior periods, the write-down in the third quarter resulted from the continued low commodity price environment. Under full cost accounting, our upstream assets are carried at historical costs.

Each quarter, we compare this cost basis to discounted after-tax future net cash flows, which are calculated using trailing 12-month average oil and gas prices with those prices and period-end costs held flat into perpetuity. To the extent the net book value of the assets exceeds this amount the result is a ceiling test write down.

Based on strip prices as of September 30, we anticipate a further ceiling test write-down in the fourth quarter. This expectation is detailed in our 10-Q.

In addition to the ceiling test write-down, other unusual charges during third quarter included a $1.5 billion charge for an increase in the valuation allowance on deferred tax assets, primarily due to a price environment which is unlikely to allow the realization of those tax assets for the next several years.

And $446 million of other items, consisting primarily of $148 million for the impairment of our investment in the Australian fertilizer plant, $146 million for mostly price-induced impairments for gathering transportation and processing facilities, and $95 million of trailing tax effects associated with our previously-discontinued operations.

Our earnings for the quarter adjusted for these items totaled a loss of $21 million, or $0.05 per share.

Offsetting the low-price environment were positive results on the operational side, including strong delivery of production volumes across all regions, continued improvement in costs as our extensive efforts to reduce G&A and operating costs are showing through to actual results, and great progress in capital efficiency, as we are getting more from every dollar invested.

Let me now turn to costs. The low oil price environment and reduced activity across the industry are continuing to result in downward pressure on costs. As oil and gas prices began to soften late last year, Apache moved decisively to ensure a leading-edge position to capitalize on cost deflation in the oil service industry.

Since that time, we have made continual progress reducing both capital and operating costs. Capital spending year-to-date continues to track in line with our expectations. We have invested $3.8 billion through the first nine months of the year.

As we have stated in the past, our guidance on capital spending excludes capital attributable to our one-third partner then Egypt, capitalized interest, leasehold purchases and capital associated with divested LNG and associated operations. Excluding these items, we have spent $2.9 billion through the first nine months of 2015.

This level of spending is tracking in line with our prior guidance. On the lease operating expense side, our third quarter LOE was $9.03 per boe, which is 18% lower than the third quarter of 2014. On a year-to-date basis, we are averaging $9.33 per boe, which is 12% lower than the same period last year.

So we continue to make significant progress on bringing down operating costs. On our second quarter conference call, we reported a 25% decline in our run rate of gross G&A costs.

At that time, we stated our goal was to enter 2016 with a gross G&A run rate of approximately $700 million, representing a decrease of over 30% from our run rate of more than $1 billion in the fourth quarter of 2014.

As we further refine our 2016 budget, we continue to find additional G&A reduction opportunities and are now tracking slightly ahead of our goal. We will discuss this in more detail when we announce our formal 2016 budget in February. Next, I would like to make a few comments regarding our balance sheet and liquidity position.

Over the past year, we implemented a number of measures, which has significantly improved our overall financial strength. Today our balance sheet and liquidity are amongst the strongest in the industry and we have accomplished this without issuing additional equity.

We have made tremendous progress in a very short period of time and I believe this will serve us well as we continue through a difficult and unpredictable industry environment. So far in 2015, we have paid down $2.5 billion of debt. Currently our net debt is less than two times annualized 2015 adjusted EBITDA.

We have extended our nearest long-term debt maturity to 2018, with only $700 million maturing prior to 2021. We have restructured and refreshed our current credit facility at $3.5 billion, which now matures in June 2020. And we have retained $1.7 billion of cash liquidity.

And to ensure that we sustain this strong position, we have reduced our activity to a level where we can attain cash neutrality in the current price environment. I would like to remind everyone that as previously discussed, the repatriation of proceeds from some of our foreign asset sales has triggered a U.S.

income tax payable of approximately $560 million. Actual cash payment of this liability will occur in the fourth quarter of this year, thus some might consider our net debt of $7.1 billion at the end of the third quarter as closer to $7.7 billion.

However, so far in fourth quarter, we have signed agreements for the sale of non-upstream assets, which will bring in approximately $500 million in cash proceeds. $391 million of this is for our interest in the Australian fertilizer plant, which we have already closed and proceeds have been received.

The remainder is associated with various non-core assets with no associated reserves or production. We expect to close those transactions in the fourth quarter or early 2016. In total, the proceeds from non-core asset sales largely offset the impact of the previously-mentioned tax payment on our net debt the end of the third quarter.

Apache's strong balance sheet and liquidity position provide both security for the near-term, as well as tremendous flexibility for the long-term. We can comfortably fund the highest-quality projects across the portfolio, as well as our exploration, strategic tests and new play programs.

We can do this within our continued cash flow from operations, while retaining significant flexibility for any strategic opportunities, which may arise in the future. We anticipate a successful finish to 2015, as Apache continues to deliver strong operational results.

Therefore today, we are increasing our production guidance and decreasing our capital guidance for 2015. We are increasing our full-year guidance for 2015 North American onshore production to a range of 307,000 boe to 309,000 barrels of oil equivalent per day.

On a pro forma basis, this represents more than 2% year-over-year growth, despite significantly-reduced capital spending. John highlighted the extensive drilling and operating success we are enjoying internationally as well.

Accordingly, we are raising our full-year 2015 international and offshore production guidance to 172,000 boe to 174,000 barrels of oil equivalent per day, up 6,000 boe from our previous guidance of 164,000 boe to 168,000 barrels of oil equivalent per day.

On a pro forma basis, this represents year-over-year growth of 10% to 12%, despite significantly reduced capital spending and demonstrates the quality of our international portfolio. With regard to our 2015 capital spending, we are lowering the top end of our guidance range to $3.8 billion from $3.9 billion.

This reflects our decision not to pick up three rigs in the onshore U.S. during the back half of the year, which John spoke about in his prepared remarks. In the planning front, Apache has taken significant steps towards achieving our objectives of enhancing returns, while living within our mean on a cash flow basis.

As we refine our plan for 2016 and beyond, we will continue to make further progress. Our plan includes a rigorous process for capital allocation to our highest-quality opportunities, while achieving an appropriate balance between short, medium and long-term capital investment horizons.

This is particularly important considering the price environment we are in today and the outlook for the future. As we look specifically at 2016, we are actively evaluating multiple scenarios with respect to commodity pricing and capital allocation. We are not in a position to provide guidance ranges for 2016 as our review is still underway.

I will share, though, that the plan will be based on a few key things, which we have established this year. Notably, we will plan a capital program, which we believe will keep us cash flow neutral for the year. We will not attempt to balance cash flow within each quarter, but instead to level-load activity for the year.

We will fund the capital program from operating cash flows; we will not use asset sales. We have not yet finalized the capital allocation plan for 2016 and are not prepared to provide a view on production volumes.

However, we are prioritizing capital to projects providing the best combination of highest rates of returns, greatest value for the future, and a bias toward near-term production and earnings. We will provide more specific guidance, including our production outlook in February, when we discuss the 2016 plan in more detail.

Finally, I would like to address one of our accounting methodologies, which we are examining for a possible change. In order to more closely align our financial reporting and to create more comparability with our large cap E&P peers, we are evaluating a conversion from full-cost accounting to the successful efforts accounting method.

The primary reasons we are contemplating the change is because successful efforts is more commonly used by our comparable peers, creates less long-term price-related volatility on the balance sheet, and more accurately reflects the matching of expenses within the period in which they are incurred, especially as it relates to exploration expense.

We'll have more to say about this in coming quarters. In closing, as we plan for the future, we are not idly waiting for commodity prices to recover. We have already taken calculated steps consistent with today's environment.

As a result, we are well positioned to continue to profitably grow Apache, through an actively managed investment program in a potentially lower-for-longer commodity cycle. I look forward to a successful conclusion to 2015 and would now like to turn the call over to the operator for questions and answers..

Our first question comes from Pearce Hammond with Simmons & Company..

Good afternoon, guys. Thanks for taking my questions.

Just to follow-up on the commentary just now about matching cash flow with CapEx, would that include the dividend or would the dividend be upside of that?.

Yes. For 2016, our goal would be to match that including the dividend. So it would be cash flow neutral..

Including the dividend. Okay, great.

And then I know you're working through this still, but could you provide any color on what you think maintenance CapEx might be to hold exit rate 2015 production flat through 2016?.

Hi, Pearce, this is John. What I would say is the best thing to do is look at 2015 right now. I mean, we've guided to $3.6 billion to $3.8 billion of CapEx spend. As you will recall in February, we guided to relatively flat North American production and slight growth internationally.

When you look at the CapEx levels, we had $1 billion outspend in the first quarter alone for this year.

When you look at the capital numbers, clearly now, with the updated ranges today, at 307,000 boe to 309,000 boe on North America and 172,000 boe to 174,000 boe on international, we're showing 2% plus growth in North America and 10% to 12% growth on the international side on that type of capital program.

I think the best thing we can do given this price environment; the commodity price is going be a big driver. As Steve mentioned, we're going to live within cash flow. And so as we start to pour that plan, that's a big key.

And I'd say, looking into 2016 with the reductions we've had on the cost structure side, specifically on the costs we have in the house at this point at 30% down, capital's going to continue to go further. I can also tell you that a lot of that CapEx this year was spent early in the year when we had higher costs.

And we see things even now that are going to point to lower costs going forward. So, the best thing to do is look at what we've done this year and kind of translate off of that..

Your next question comes from Evan Calio with Morgan Stanley..

Good afternoon, guys. Maybe just a follow-up on that, the 2016 budget parameters. I mean you say that living within cash flow excludes asset sales and includes the dividends.

So, do asset sales then just create a buffer on your balance sheet? How do you contemplate the redeployment of those proceeds such as the $500 million announced in the quarter? I mean it's been a relatively sizable program and just curious how you think about that capital coming back into the business..

Yeah. I'll let John comment on this as well. But I think at this point in time, the right answer to that question is the fact that we're not contemplating any material asset sales in 2016. And therefore, we're not planning to spend the proceeds on any of those. And therefore, cash flow neutrality needs to be on an operating basis.

Now, that's – I'd just caution all of that with the fact that we're not going to get dogmatic about being cash flow neutral. And we reserve the right to not be cash flow neutral. But it's going to be – it's a prudent assumption going into the year at this point in time. And then 2016, I have no doubt, will be just as exciting as 2015 has been.

And we'll, no doubt, adjust plans as we go through the year. But I think the prudent thing to do at this point in time is to go into the year planning on being cash flow neutral..

Got it, I would agree. Maybe my second, if I could, following up on the comments on the JV process, the positive progress there and then the plans to run three rigs in Canada next year versus zero today.

Can you discuss the cost environment in Canada and how you kind of see those returns stacking up against the rest of your portfolio? I presume that the JV details could also augment those returns for you. If you could..

In general, Evan, we want to remain cash flow neutral in Canada. I mean what I don't want to do is take cash flow from our Lower 48 properties and spend that in Canada. So that's the main reason why we are looking at and are making progress on a JV in the Montney.

And the way that would be structured is we would be using other capital to get that program kicked off. In terms of how the Montney and the Duvernay compete in terms of – they compete very nicely with the portfolio. And I'm going ask Tim Sullivan to dig in a little bit on the cost structure we're seeing on the Duvernay at this point..

Yes. As John mentioned, we just put on the first Duvernay pad that we drilled. This was a seven well pad. It was a spacing test. Half of the section was designed to test eight wells per section; the other half to test six wells per section. We're going through a third party facility. So, we're a little bit curtailed, we only have four of the wells online.

But those four wells are doing just under 13 million boe (34:50) a day and 3,350 barrels of condensate per day. Again those are curtailed with the flowing tubing pressure of over 3,300 pounds. Next week we hope to have that facility up and running and we'll be able to bring the other three wells online.

And we should have everything flowing at capacity on December 1. Now to the cost structure question, last year we spent about $18.1 million drilling one-off wells out there. We went to pad operations. This year where we had two walking rigs and we batch drilled each section of the well.

We were able to reduce our well cost by 36%, 8% of that savings was due to foreign exchange, but the rest of it was primarily due to cost savings and operational efficiencies. And most of those operational efficiencies were made up on the completion side. In those seven laterals we did 124 different frac stages and we pumped that in just six days.

We averaged 7.9 fracs per day, with only 34 minutes between stages. And we got down to as low as 6 minutes between two of the stages. So we were pumping 82% of the time when we had the equipment on location. And really the Canadian team there, we're really leveraging the learnings that we had from the Horn River drilling that we've done in the past.

And we see future costs there as we get our water facility in place even going down further and we think we can get these costs down to $8.5 million to $9 million per well..

Your next question comes from Doug Leggate with Bank of America Merrill Lynch..

Hi, good afternoon, everybody. John, I appreciate the disclosure I guess on the pursuit of a joint venture. If I could just have a quick follow-up. If we look at your position up there, it seems that, if I'm not mistaken, the bulk of your locations is in the area where you have the lowest working interest.

And the highest working interest I guess you've got about half the number of locations, so I'm thinking Duvernay being the one with the small working interest.

So when you think about structuring a joint venture and I guess getting someone to fund you or carry you, is that the kind of structure we should think about? In which case, what kind of working interest would you anticipate getting to and how would you think about that? I've got a follow-up, please..

Well, Doug, I got to be a little bit careful. We're talking about the Montney and it's an area we have 100%. So we do not have partners. We're not at this point looking at the Duvernay. The area you're talking about, the current wells we've got about 37.5%. We're in there with Chevron and, of course, their joint venture partner.

So, we're really talking about an area in the Montney where we have 100%. And that is the area we're looking at and I don't want to get into too much color because we're in the heat of battle of negotiations.

But it would be structured where we would obviously be able to keep the majority and would get significant carry upfront, and which would unease our infrastructure and costs going, over the next couple years..

I appreciate that. I don't know if I missed that earlier. That would make perfect sense given your working interest there. Thank you for that.

My follow-up is really about – I realize you don't want to give production guidance, but if you look at the spend level in the third quarter – and obviously there's a lot of moving parts on production declines and so on.

But if you continue to spend at the third-quarter level, based on what we saw in Q3, what would you say your underlying decline rate would look like?.

Well, I mean in terms of our decline rate, if I take North America, we're still running about a 25% overall decline, our Permian's about 22%. I do anticipate those numbers coming down as we start to look at the pace because we just haven't drilled as many new wells this year as we have historically.

So I think those numbers will be dropping slightly, but it's early. We're still working through those planned numbers. The one thing I would say about the back half of the year, as we alluded to on the call, with the drop in prices we held off picking up three rigs, two in the Permian and one in the Eagle Ford.

And it's going to have very minimal impact; we're still in a position to raise guidance on our North American position. So, we feel good about our properties, we feel good about how we're executing and we're really starting to see efficiencies drive into the numbers..

Great stuff. I will jump back in queue. Thanks, John..

And your next question comes from Brian Singer with Goldman Sachs..

Good afternoon..

Hi, Brian..

How are you thinking about the role of the international assets here, particularly in light of some of the positives you reported on in Egypt and the North Sea? Are there any changes in, A, how these areas are competing for capital relative to the rest of the portfolio, and B, the strategic thoughts on retaining versus divesting?.

No, Brian, I think at this point, when we look into the future, our primary growth is going to come from North America. I think you have to recognize the benefit of the portfolio.

And we came out with that early in the year with the drop in prices, and the international both are less sensitive to the drop in oil price and you've seen that come through in cash flow from both those operations.

Secondly, if you take Egypt and take Ptah and Berenice, tell me how many places in the world you can have a discovery and within seven, eight months you're producing from two handfuls of wells to 26,000 barrels of oil a day? So we've got quick tie-in, quick infrastructure to those things, so very high rates of return.

In the North Sea, there's a couple of things there. Number one, we've invested in the infrastructure. We spent $1.3 billion over the last decade at Forties and that infrastructure is in really good shape. That's why we can operate at 92%. In our Beryl area we spent over $300 million on the infrastructure there.

So, I don't want to steal the thunder from our November 17 update on the North Sea, but with those three discoveries, one of them is a little longer cycle time, Seagull, but the other two, I think you'll be surprised at how quickly we can bring those projects on through tie-backs to the infrastructure that's already in place.

So, we look at it as a portfolio. Our long-term growth is going to come from North America clearly, but in this price environment right now I've got a lot of optionality in the international and a lot of very high rate of return projects that bring immediate volumes that compete extremely well that we can tie in and complement.

I think we've also proven through the exploration success that both of the international assets, those franchises have a lot of running room. And we'll get into more color on the North Sea here in just less than two weeks..

Great, thanks. And my follow-up shifts to the Permian Basin. I believe you said in the ops update here there are no rigs currently in the Barnhart area, which had been a source of your development.

As you've shifted more towards the other parts of the Permian, can you talk about how we should look at execution and growth relative to when you were a bit more Barnhart-focused, and what you see as differentiating or we should expect as differentiating Apache's Permian position relative to others who are in the region?.

Well, I mean I think the first and foremost thing, Brian, is we've got a very strong position across all the basins and that gives us lots of flexibility and optionality. Right now in the Permian we're really not in development mode, we are still doing a lot of strategic tests.

We're in the process right now of drilling our three Spraberry shale wells that we're very excited about. So I think as we moved into the deeper parts of the basin, we've seen better results in the Midland Basin and I think the Delaware, we've got strong results in the area we've been active there, Pecos Bend and our Waha.

So I think what you'll see is we know how to execute, we've been in position where we've done a lot of pad drilling, and so we know what that means and our asset quality is just as good as anybody's. We just happen to be spread out across the multiple basins.

So as we look at 2016, we won't be, and it depends on the price environment we're in as to how much development dollars we shift into Permian, but the big thing we're going be focused on right now is trying to mirror our cost structure to that price environment. And we're making headway there.

And I think the one thing that you can look to is just our results on some of the plays. And I think we stand up well with anybody..

Your next question comes from Bob Morris with Citi..

Thank you.

John, in the Permian and pulling back two rigs you originally intended to add, does that mean you're going to ramp up now to only 16 rigs by year-end? And where are you right now?.

Right now, we're at 14 rigs, Bob. I think we really just deferred. And all that's really done for us is we will end the year with fewer drilled-but-uncompleted wells. But we felt like that's the prudent thing to do right now based on where oil prices are and trying to feather our programs going into 2016, living within cash flow..

And so the two rigs you won't add, where had you intended to add those rigs in the Permian?.

They were going to be predominantly Midland Basin, Central Basin Platform..

Okay.

And then the drilled-but-uncompleted inventory you ran, where is that? And is that steady-state or is that an inventory that you can draw down further in 2016?.

Well, I mean first and foremost, we had guided to on the last quarter a range in the 80 to 100 range of drilled-but-uncompleted horizontals in North America. We now see that number ending the year around 60 plus. And it's not that during the quarter we consumed a lot of drill – picked up our completion pace. We just elected to wait.

And the main reason is we've got visibility on costs coming down further. We've got a few drilling rigs that some term is rolling off in the next 30 days. And we're going to see those rig rates drop 37%, 38%. So we made a decision over this last quarter not to, in fact, we lowered the top end of our capital guidance range by $100 million.

We decided not to spend that $100 million now, and we can wait and spend those in the future..

And your next question comes from John Herrlin with Société Generale..

Yes. Hi.

Not trying to preempt the North Sea discussion that you will have in two weeks, but is it fair to say that you may dedicate a little bit more CapEx in 2016 to the North Sea?.

John, I wouldn't see, mix is changing too much. I mean, we've had, if you look at our capital this year, North Sea actually is down 25% over last year. So I don't see a major shift. You're not going to see us shift a ton of money by any means. But I think you're going to see we've got a lot more running room.

And we've got some very material things that could come on that can be very impactful..

Okay. Thanks, John.

Regarding the switch to successful efforts, any kind of a ballpark sense about what kind of a balance sheet hit it would be?.

I'll let Steve jump in on that one..

I was hoping you'd answer that, John. No, I think it's too early to say. We've got in the 10-Q what we believe the fourth quarter hit to the balance sheet will be because of staying on full cost accounting and further softness in the commodity prices.

But it's too early to say at this point in time what will happen if and when we switch to successful efforts to the balance sheet..

And your next question comes from Ed Westlake with Credit Suisse..

Thanks for taking the question. Just coming back to the Midland. Obviously the industry has had success delineating various different zones in the Delaware. I mean you've got some very good wells out at the Pecos Bend. You've got a lot of wells or you've got some acreage, Wildfire, Azalea, Powell-Miller, over on the Midland.

I'm just wondering if you are able to give us, having had more time working with the acreage, some kind of, as others do, inventory that works at say $50 in terms of well locations and then $60, $70. So some un-risked sense of the inventories in those two particular areas..

What I would say, Ed, is we have not done a – I mean, obviously we're working those areas. We continue to test lots of zones. You look in the Midland Basin, we've got multiple zones in there we're testing. As I mentioned, we're about to drill or in the process of drilling Spraberry shale wells.

You look at our Pecos Bend area; we've gone in now and added a second landing zone within the 3rd Bone Springs. So, we continue to make progress.

We continue to test zones and really scope opportunities and work on the cost structure so that when we get to a position where we feel like it makes sense to put more rigs and more capital to work, we're ready to do that. In terms of counts, we have not come out with a bunch of updated numbers.

Really, the best look would be going back to what we did a year ago where we did a very deep look at North America on November 20, 2014. And obviously, we've got areas where things have, you know, we've drilled some things and things have expanded, but we haven't really come out with any major announcements or counts at this point..

I guess the issue was the oil price was a lot higher and the cost structure is very different today, so I was just trying to get an update on that.

But maybe switching to break-evens, I mean the Seagull discovery, I mean have you – I don't want to – again steal thunder from what's coming in a few weeks, but what sort of oil price do you think it would take to get that hooked back into infrastructure?.

Not going to really get into that right now, but I can tell you the nice thing about the North Sea is the deliverabilities and the high rates those rocks bring. They're very forgiving; tremendous rock. We announced in the press release a very substantial test rate on a very, very low drawdown.

So the deliverability is going be fantastic there, but I'm not in a position today to disclose F&D. That will be a longer – a little longer-range project. It's four miles kind of south of our Forties area, but we will have some color on November 17..

And your next question comes from John Freeman with Raymond James..

So nice well results in the Delaware Basin, but what really jumped out at me in particular was you completed 22 wells in the area versus 12 last quarter, despite still using just the one frac crew. And so I'm trying to get an idea of – you completing nearly twice as many wells with the same number of frac crews.

Is that all huge efficiency gains or is there some other moving parts that doesn't make the quarters comparable?.

No, I think, number one, is just the pace at which we had them, but number two, we are making tremendous headway on efficiencies everywhere. We also are getting wells drilled significantly faster as well as getting more wells fracked. Tim gave you some color on the Duvernay pad, how quickly those went off.

We're seeing tremendous success operationally everywhere, and that's just a function of it doesn't take as much equipment to go as far as it did a year ago..

Okay, great. And then on Egypt you disclosed that you've initiated this large seismic reprocessing project that you hope to have done by the end of the year. I guess I'm just curious sort of what kind of took place in the field that kind of drove the decision to have it; what you hope to kind of get out of that shoot or reprocessing? Excuse me..

Reprocessing?.

In Egypt..

Yeah..

In Egypt..

And where is it, or?.

He asked the scope and what we thought we could get from it with the large reprocessing in Egypt..

Well, as you're well aware, the whole basis of our success in Egypt is that 3D seismic, and with continued technological advances, improved processing and basically combining previous shoots, adding new data, we just get a more clear picture of the same areas we've been working for years.

So, all this is going to do is help us identify previously unseen prospects and continue to deliver inventory in future years..

And two perfect examples are Ptah and Berenice. I mean they're right there at our Khalda Offset area, right near our existing stuff. So, it's just a function of taking the technology up that can quantify and get really solid ties and – to the – some of the plays out there..

Our next question comes from Charles Meade with Johnson Rice..

Good afternoon, guys. John, last quarter you and Steve spent some time laying out your new planning process where you guys were running scenarios at three different price points for WTI, or for oil I should say. I was wondering if you could give us an update if you've moved where those prices are in your scenarios.

And perhaps more broadly, as you've been working that process over the last several months, if you're finding any areas that are surprising to you either in terms of their rigidity or new areas of flexibility you've discovered..

Charles, we did move those. I mean we started the year with a – kind of a $50, $65 and $80, and we planned on $50 at the start, and then in April, May timeframe when things ran up into the mid-$60s we were using those decks. Clearly, we've moved those down. In the last call we talked kind of $45, $55, $65.

We're not too far off of those cases as we think about things today. The one thing I would say is the resiliency of the projects moves a little bit.

The bigger tie is what are you doing with gas prices and how does that link in with some of these plays that we've got that have a little higher GOR and gas rates? But in general, we're seeing projects and wells in every play that works very well and it's really a function of the cash flow that comes off of those scenarios and the cost structure assumptions are the biggest variables we're trying to get pinned down right now..

Got it, that's helpful. And that's also kind of a good lead in to my next question where I wanted to ask about the Eagle Ford, where you guys have turned in really some really good-looking rates there.

But one of the things that I attuned to there is that you have 80% liquids and a lot of times that can include NGLs, which are kind of actually the lowest molecule on the totem pole right now.

So can you – and I know the oil, gas, and maybe the NGL mix varies a bit as you go up and down dip in this play, but these most recent wells you've had in your Area A – the Eagle Ford, the Lambert and (54:58) where do those fall on the percentage of black oil?.

I'll have Tim give you that exact number. I still think we're in the 55% range roughly in terms of black oil. The Area A wells, those are still within our Ferguson Crossing area.

So if you go back to our November 20 update a year ago and you look at that type curve Area A, Charles, they're going to layer right in on those – on that type curve, which I think we gave those numbers specifically there. I'm looking over here if we've got the percentages from that type curve, but I know we disclosed those..

Yes, we can get back with you on those, Charles. We've got those numbers for that area..

Your next question is from Leo Mariani with RBC..

Hey, guys. Just a question around the acreage acquisitions that you all were talking about. Looks like you did a healthy portion. You guys commented that you're sort of paying prices which were a lot less than some of these hot high-profile deals we've seen recently.

Can you guys just let us know where are you concentrating the acreage acquisitions? Is it sort of Delaware, Midland, or Midcon? Can you just help us with where you're looking to buy?.

Yeah. Number one, we're within our core areas. Number two, we are looking at some things that would be significantly lower than what I'd call the retail prices that are being paid. And it's where we're applying technology and science and we think we've got some things that could be material.

It is new ventures acreage, so there's always risk with that and that's why we wouldn't want to talk about it now. But we're talking significant multiples lower in terms of what that acreage might be viewed as and what it potentially could be worth.

And I think that's the zip-code that we feel like makes the most sense in this price environment because we can pick it up and we can work the science and you can have something that could be material..

Okay. I guess jumping over to Egypt; you obviously had good performance in terms of your increases in gross production in the third quarter. I noticed that the net production, though, went down a fair bit in 3Q versus 2Q, despite lower commodity prices.

What's driving that and how should we think about that going forward?.

It's the tax barrels. I'm going let Steve Riney give you the exact color on that..

Yeah, Leo. As you said, rightfully, so gross production in the third quarter was about 3.5% above second quarter. And actually net entitlement to the venture owners, us and Sinopec, was also up about a little over 3%, about 3.5%.

The issue is around tax barrels and tax barrels on a three-thirds basis for the PSC owners, tax barrels were down 20,000 barrels a day between oil and gas. And the reason for that, there's no economic effect of that. It's the in-quarter reimbursement of taxes associated with income taxable in Egypt.

And the bottom line issue is in the third quarter, prices had declined to a point where there was practically no taxable income. As a matter of fact, in one month I think we had a negative tax barrel effect. And so therefore both the tax, income tax expense and the barrels associated with reimbursing that income tax expense were much lower..

Your next question comes from Mike Hall with Heikkinen Energy Advisors..

A lot of mine have been answered, but I guess just curious on the longer-range outlook. You guys have talked about providing that in the past.

Should we expect to hear about that in February as well, or what sort of I guess timeframe in your current thinking; when we will hear about that?.

Well, Michael, we obviously will give you a full-year 2016 update in February, and we'll see how things look at that point. So, clearly we're working multi-year plans. But obviously with the volatility and the uncertainty around the prices right now, we're going to continue working that..

Okay. And then just looking at the mix of production in North America; got a bit more NGL relative to our expectations in gas.

Is there anything driving that from an infrastructure standpoint or is that more the focus of the capital program from a reservoir perspective?.

No, I mean actually I think when you look at our numbers, and you look at 2014 and 2015, and our percent oil in 2014 averaged about 52.7% for the year, we'll be 52.5%. We're right in line. In fact if you add our NGLs in 2014 and 2015, 65%. So you step back, big picture there's virtually no change in our mix.

And we have the luxury of being more liquids rich and heavy than a lot of others. I will say you see some small swings when we've ramped our programs down to some of the GORs and some of the programs. For example, last quarter we brought on some gas here, Area A, Eagle Ford wells.

If you look at our North Sea production, we've shifted more to the Beryl area where we've got a little higher GOR than we do at Forties, but I should say we get a very premium gas price up there, over $7. When you look at the Permian right now, we've had as a percentage more in the Delaware.

Those wells had the luxury of having very flat GORs, but they come on at higher levels. So it's just a function of the portfolio, but in general, if you step back and take a big picture look, it's virtually where it's been historically..

Your next question comes from Jeff Campbell with Tuohy Brothers..

The first question I wanted to ask is if we could talk about the Canyon Lime upper interval. You highlighted shallower declines.

I was wondering, are you doing anything to influence the decline? And while we're at it, how pervasive do you think the upper interval is throughout your acreage?.

Yes, I'm going to – I'll let Tim Sullivan comment on the Quanah well on the Canyon Lime..

The Quanah well is a new landing zone. It's the only well that we've got in that landing zone. It's been producing about 2.5 months. The IP 30 on that was about 1,662 barrels of oil equivalent per day. In that 2.5 months it's cumed already 91,000 barrels of oil equivalent per day and is still doing just under a 1,000 barrels of oil equivalent per day.

So, it is a standalone well, but it's just a function of getting the spacing right. We have not been curtailing production or anything. It's just a shallower decline and we're excited about that zone..

Okay, thank you. And I wanted to just ask another broader question. Not too long ago there was talk about revived industry interest in vertical Permian drilling based on returns.

I was just wondering have you increased your vertical drilling any on that basis?.

Jeff, we haven't. But I think, one thing I'll say we've got the luxury of having about 60 water floods and seven CO2 floods in the Permian. And we have a ton of vertical locations; infill locations that do make economic sense. And right now we do not have any vertical rigs running. That's an option that we could have for next year.

But we have not made any decision at this point yet..

Our final question for today comes from David Tameron with Wells Fargo..

Hi, glad I got in.

John, can you – if I think about the Permian and just obviously the slowdown in the rig count and look at production quarter-over-quarter down-ticking a little bit, gas up, oil down, when should we anticipate that inflection point as far as when we see stabilization and then move higher?.

Well, I mean I think that really comes down to when we feel like it's time to go back to work with more rigs. And so I mean that's just a function of how much capital we want to spend and we made a decision not to add two more rigs here within the last quarter.

We'll go and do 16 and see, but I mean that's all going to hinge off of cash flow and investable projects.

I mean we've got a ton of inventory that they're chomping at the bit to drill, but it's just a function of trying to go back to our guiding principles of living within cash flow, focusing on our returns, focusing on the cost structure and growing value for our shareholders..

All right, everything else has been asked. Thanks, appreciate it..

Thank you..

Jennifer, thanks. We're going to wrap it up there. We're well past the top of the hour. We had a long queue today, so if we didn't get to your call please give the IR team a call. Otherwise, we look forward to speaking with you in February. Thank you very much..

Thank you for your participation. This does conclude today's conference call and you may now disconnect..