APA Corporation (APA) Q4 2014 Earnings Report, Transcript and Summary

Good afternoon. My name is Kelly, and I will be your conference operator today. At this time, I would like to welcome everyone to the 2014 Fourth Quarter and Year-End 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. [Operator Instructions] Thank you. Gary Clark, Vice President of Investor Relations. You may begin your conference.

Great. Thank you, Kelly. Good afternoon, everyone and thank you for joining us for Apache Corporations fourth quarter 2014 earnings conference call. Speakers making prepared remarks on today’s call will be Apache CEO and President, John Christmann; and Interim CFO, Anthony Lannie. Also joining us in the room are Tom Voytovich, Executive Vice President and COO of International and Steve Riney, who will officially take over as Apache's new CFO later this month. We are delighted to have Steve on Board and look forward to hearing from him on next quarter’s conference call. In conjunction with this morning’s press release I hope you've had the opportunity to review our quarterly earnings supplement which summarizes our operational activities and well highlights across various Apache operating regions. The supplement also includes information on our capital expenditures for the quarter, as well as a chart that illustrates cash sources and uses and reconciles Apache's change in net debt during 2014. 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 everybody that today's discussion 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 discussed today. A full disclaimer is located with the supplemental data on our website. This morning we reported a fourth quarter 2014 loss of $4.8 billion or $12.78 per diluted share. These results contain several non-cash charges primarily related to the impact of declining oil and gas prices, acreage impairments, the announced disposition of our LNG assets and changes in foreign tax estimates and assumptions. Adjusted earnings, which excludes certain items that impact the comparability of results totaled $404 million or $1.07 per diluted share. Cash flow from operations before changes in working capital totaled $2.1 billion during the quarter. Worldwide reported net production averaged 673,000 barrels of oil equivalent per day, with liquids production constituting 62% of that total. On a pro forma basis, which excludes assets that have been divested, non-controlling interests, and tax barrels in Egypt, our fourth quarter worldwide production was 609,000 barrels of oil equivalent per day. This represents an 8% increase from the third quarter and a 12% increase from the same period a year ago. I would now like to turn the call over to John Christmann.

Thank you, Gary. Good afternoon and thank you for joining us today. I would like to start by saying a few words about our long-time Chairman, CEO and President, Steve Farris. Steve announced last month that he would be retiring from Apache following more than two decades of leadership. During his tenure he helped grow the Company to one of the largest and most successful independents in the world. I would like to personally thank Steve for his service and am honored to be his successor as the new CEO and President of Apache. In 2010, Steve initiated a strategic repositioning to bring Apache's primary focus back to North America. As we showed you at our November North American update, 2014 was a milestone year for this transformation. We streamlined and enhanced our North American portfolio and we added significant new unconventional capabilities. We now have a deeper and more predictable inventory of economic locations in North America than at any time in Apache's history. Our drilling production and inventory is oil prone and located in areas with multiple stack pay horizons, which we believe creates a significant long-term competitive advantage. We have the right teams, processes, and science in place to efficiently develop our existing Resource and to build future opportunities. In response to the rapid drop in oil price, we have purposely taken quick and decisive action to reduce our drilling activity, well costs, G&A and lease operating expenses. This will position us more favorably and make us a more efficient Operator in the future. A top strategic priority for Apache during 2014 was to sell our Wheatstone and Kitimat LNG assets. I am pleased to note that the sale of these assets, which we announced in December is on track to close by the end of the first quarter. Including capital cost reimbursement, estimated proceeds from this transaction will be approximately $3.7 billion, which we will use initially to pay down debt. Our operations in Egypt and the North Sea provide a very nice complement to our North American production and cash flow. Cash flow from Egypt and the North Sea has less than 50% of the downside sensitivity to oil prices as our North American operations. Importantly, both regions are still expected to generate free cash flow in 2015 at current strip pricing. Apache’s Egypt and North Sea operations offer steady, high rate of return projects, and the portfolio diversification benefits of these regions becomes evident during oil price downturns like the one we are currently experiencing. While we always leave open the option to adjust any part of our portfolio in response to changing conditions, we are not currently proceeding with a sale or spinoff of Egypt or the North Sea. With regard to Australia, we are taking a close look at the potential monetization of our remaining non-LNG assets. The value of these assets is generally underpinned by long-term fixed price natural gas contracts, which we believe increases the universe of buyers and the potential valuation, even in this depressed oil price environment. In summary, our portfolio is well positioned to weather the low oil price storm and I'm excited to have the opportunity set that lies before us today. Before we go to the fourth quarter results and outlook for 2015, I'll make a few comments about oil prices and the actions we have taken thus far in this fast moving price environment. We cannot predict nor control the length or depth of this oil price correction, or the timing and extent of the rebound. We have therefore acted quickly and decisively regarding the things we can control. Our activity levels and cost structure. During the third quarter of 2014, we operated 91 rigs onshore in North America. By the end of this month, we will have reduced our rig count to 27. On the pressure pumping side our frac crews are down more than 50% over the same time frame. In some instances we are choosing to lay down rigs that were under longer-term contract at day rates reflective of $100 oil price environment. As a result, we expect to pay some modest early termination penalties totaling approximately $50 million. We are also delaying the completion of some wells in backlog until pressure pumping costs reset to levels that better reflect the current commodity price environment. Corporate cash flow is the main constraint on our 2015 drilling plans. We would consider using our balance sheet only to capitalize on lower acreage costs and other potential opportunities that may occur, rather than to drill wells and chase production in a depressed and volatile oil price environment. Importantly, once we achieve the full benefit of lower well costs, our returns will be competitive at $50 per barrel of oil to those represented in our November North American update at $80 per barrel. The key difference is that we will simply have less cash flow to work with and will accordingly drill fewer wells. Additionally, we are diligently working through a dynamic scenario planning process that will allow us to quickly adapt our business and activity levels under a variety of potential commodity price case scenarios. During the robust and relatively stable oil price environment over the last four years Apache was one of the most active drillers in North America. We grew our Permian Basin production by more total barrels at a faster rate than any of our peers. I’m highly confident that when oil prices begin to recover and stabilize at higher levels we will efficiently ramp up our drilling programs in the Permian, Eagle Ford and Canyon Lime to deliver top-tier production and cash flow growth. The recent oil price decline has been dramatic and almost unprecedented, but we believe that it will create a once in a decade opportunity for those of us that have moved aggressively. For Apache the oil price drop and subsequent industry slowdown has several positive aspects that we believe enhanced our ability to generate strong long-term shareholder returns. The slowdown provides an opportunity for us to be come a more efficient company through focused initiatives such as realigning our North American incentive program to reward continuous improvement and cost discipline, creating medium and longer term field development plans and high grading and improving our drilling inventory, rationalizing and consolidating our acreage position, leveraging our surface operations infrastructure and scale, adding key acreage while there is less competition and at lower prices, and reducing our North American base production decline. Regardless of how long oil prices remain depressed we plan to emerge in this downturn as a top-tier resource company in terms of drilling inventory, operational efficiency, cost structure and balance sheet strength. Now let's talk about Apache’s full-year 2014 results. Worldwide production on a pro forma basis grew 6.5% in 2014 which was right in the middle of our 5% to 8% guidance range. Absent some timing delays on the startup of our two large offshore Australian oil projects worldwide production would have been at the high end of our guidance range for 2014. Onshore North American liquids production grew 18.6%which exceeded the high end of our 15% to 18% guidance range provided back in February of 2014. This strong performance was possible, because our high quality extensive drilling inventory in the Permian region enabled us to accelerate activity levels and production while at the same time we were seeing slower than expected growth and were recalibrating our capital program in the central region. As a result North American liquids growth was driven by the Permian where production increased 25% from the prior year or approximately double the midpoint of the guidance we provided back in February. In the central region growth was essentially flat for the year, but despite a difficult first half played by weather and operational problems we were able to reduce our drilling programs significantly in the second half of the year while maintaining steady to slightly increasing production. The North Sea and Egypt were ahead of plan, while Australia was a little behind plan due to timing delays Balnaves and Coniston oil projects. It was a good year for us internationally and we generated very strong free cash flow ex LNG spending. Turning to our 2015 capital budget and production outlook, based on the midpoint of our capital guidance range we anticipate spending a total of $3.8 billion in 2015, which excludes potential lease hold purchases or acquisitions. Compared to 2014, this represents a 60% decrease in our capital spending. We expect our pro forma onshore North American production to be roughly flat and our pro forma international and offshore production to be slightly up in 2015. Our Companywide 2015 pro forma production should be relatively unchanged from 2014. We believe this is a pretty good outcome given the extent we are reducing the capital program. Turning to the fourth quarter regional review and our planned activity levels for 2015. I was very pleased our drilling results across the entire company. We had success in every region during the fourth quarter. Onshore North America delivered liquids production growth of 5% sequentially and 20% year-over-year when adjusted for asset divestitures. The Permian was once again our biggest growth driver and we exited the year with record production. We ran 42 rigs during the fourth quarter and we expect to have this down approximately 15 by the end of the month. In 2015, we plan to average 10 to 12 rigs in the Permian approximately five of which will be in the Midland Basin, four in the Delaware Basin, and two rigs will be drilling high rate of return vertical and horizontal wells on the Central Basin platform in Northwest Shelf. In the Central Region net production grew 3% sequentially during the quarter as we completed 72 gross wells in various legacy Anadarko Basin formations. You can see the results from some of these wells in our quarterly supplement where we highlight a few key contributors from the Granite Wash, Cottage Grove and Cleveland and Lower Marmaton. As a result of taking a more measured approach in these legacy plays, we are seeing better-than-average well performance, better returns, and much better capital efficiency. During most of 2015, we plan to keep one rig running in the Anadarko Basin. In the Canyon Lime, no new wells were brought online during the fourth quarter; however we just started to flow back our first four well pad in the Canyon Lime and will have some flow rates to report there in the near future. In the Eagle Ford, our rig count peaked at 12 in December and by end of this month will be down to four. By mid-year we plan to have one to two rigs working in the Eagle Ford and are prepared to ramp back up quickly if oil prices allow. The Eagle Ford is an excellent example of our cost initiatives driving positive returns in this depressed price environment. Our initial wells in Area B of the play were running in excess of $8 million. If you'll recall back in our November North American update, we projected 2015 well costs would average around $7 million. With lower service costs and further design improvements, we think we'll have these wells down closer to $6 million within a few months, which depending on their oil cut, they can deliver solid economics and strip prices. In Area A, where we should generally have better economics, we have a backlog of 20 or so wells that we will be bringing on over the course of the year. Apache is progressing its understanding of the Eagle Ford petroleum system and will update you later this year as we gather more data. We plan to continue consolidating acreage around our core position. To sum it up, we're drilling better wells at lower cost and continue to expand our understanding of this compelling play. In Canada, we are finishing up a three-rig drilling program in the Duverney and Montney plays this spring and will release the rigs for the remainder of the year. We plan to complete a seven-well pad in the Duverney in the third quarter and in the Montney we continue to develop a long term solution to process future Montney gas production. We are making progress reducing drilling and completion costs in Canada. Canadian production averaged 72,300 BOEs a day during the fourth quarter, which is a decrease of 1% sequentially from the third quarter. Given minimal planned activity during 2015, we anticipate that production will decline from fourth quarter levels. Turning to our international operations, all three of our regions, the North Sea, Egypt and Australia, delivered profitable production growth and remain on track to generate significant free cash flow for the year. In Egypt, we made two oil discoveries during the quarter. While additional appraisal work is under way, the Ptah and Berenice field discoveries appear to be two of Apache's largest oil field discoveries in Egypt over the last 15 years. On a gross basis we expect Egypt will decline modestly in 2015, but our cost recovery mechanism there will result in a fairly significant increase in our net barrels. In the North Sea we delivered the strongest production numbers in the history of the region with a great rebound from the third quarter turnaround season. Coming off this high watermark and given the significant reduction in capital investments, we are starting to see natural declines kick in. With the program we have planned we do expect North see will decline slightly in 2015 beginning in the first quarter. Lastly in Australia, we continue to make progress towards first oil at Coniston, which is expected to be online mid year. I would now like to turn the call over to our interim CFO, Anthony Lannie, who will discuss in further detail our fourth-quarter non-cash earnings charges and provide guidance around first quarter 2015 North American production and CapEx.

Thank you, John, and good afternoon. I would like to begin by providing some detail around our fourth quarter non-cash charges. As noted in this morning's press release, we reported an after-tax loss of $4.8 billion or $12.78 per share for the fourth quarter of 2014 as a result of several key non-recurring items. We incurred $2 billion in after-tax non- cash property write-downs related to full-cost ceiling impairments in the U.S. and North Sea. Under full-cost accounting we are required to use trailing 12 month oil prices to calculate the PV-10 value of our reserves each quarter. Approximately half of the charges associated with the Company's full-cost ceiling test were driven by an impairment of acreage that we do not intend to drill. We recorded a $1.3 billion impairment of goodwill in the fourth quarter related to our U.S., North Sea and Canada reporting units. This is a function of prior-year acquisition values being valued under today's lower commodity price deck. If oil prices do not recover materially from the current futures market price indication, the Company expects further impairments of the carrying value of its oil and gas properties throughout the remainder of 2015. The Company does not, however anticipate significant additional acreage or goodwill impairments in 2015. In December 2014, we announced the sale of Apache's interest in the Kitimat and Wheatstone LNG projects along with associated upstream oil and gas assets, to Woodside Petroleum for $2.75 billion plus recovery of Apache's net expenditures made between June 30, 2014 and closing. Assets associated with the sale of our LNG facilities are classified as held-for-sale on the balance sheet. Accounting rules require us to evaluate assets held-for-sale for impairment. Accordingly an impairment analysis was performed on these assets and an after-tax loss of $753 million was recognized in earnings. The full-cost upstream assets associated with this sale are excluded from held-for-sale accounting and no impairment was recorded, however. We do expect a non-cash charge upon closing of the sale. Lastly, we incurred approximately $1 billion in non-cash deferred tax adjustments for the fourth quarter, primarily related to the U.S. GAAP rules pertaining to the measurement of income taxes on undistributed earnings in our international regions that we no longer consider to be permanently reinvested. The announced sale of our interest in the Kitimat and Wheatstone LNG projects and associated upstream assets was a key step in refocusing our portfolio and giving us more flexibility with capital allocation. Additionally, during 2014 we completed the sale of our Argentina region, our deepwater Gulf of Mexico interest and several non-core assets across North America. In total for the year, we completed or announced sales of approximately $7 billion of assets worldwide, we intend to use the proceeds of the remaining sales to pay down debt and strengthen our balance sheet in this low price environment. I would like to leave you with some guidance for our North American onshore operations in the 2015 first quarter. We currently project that quarter one North America onshore production will average between 300,000 and 305,000 barrels of oil equivalent per day which is down slightly from our record fourth quarter 2014 levels when adjusted for asset sales. This slight decrease is attributable to the plan deferral of completions which John spoke about earlier couple with the impact of severe weather conditions during January. In the Permian region alone we experienced abnormal weather related down time of approximately 14-days in the first half of January. The estimated impact of this down time when spread across the quarter is roughly 3700 barrels of oil per day. From a CapEx standpoint, we anticipate spending roughly $800 million in onshore North America during the first quarter which represent approximately 36% of our full year onshore North America budget. I should also note that our first quarter and full-year 2015 capital budget excludes approximately $300 million of estimated spending for LNG which we anticipate being reimbursed upon closing of the LNG sales this quarter. Our financial strategy for 2015 is to maintain a strong balance sheet and live within our cash flow in order to take advantage of opportunities quickly and efficiently once prices begin to recover. I will now turn the call back over to the operator for question-and-answers.

[Operator Instructions] Your first question comes from the line of David R. Tameron of Wells Fargo. Your line is open.

Hi, good morning. John, can you talk about – when we start thinking about the rig efficiency, obviously I know you’re going to say everything you drill is good but some has got to be better than the others. So when I start thinking about productivity per rig and those type of metrics, what type of up lift do you think you'll see on the scale back?

Well I mean it’s hard to put the percentage as an actual percentage, but clearly about slowing down on high grading, we will focus on our best wells, additionally we're going to be drilling wells, only wells that we really need to drill right now and the nice thing is a lot of our acreage is held, we don’t have lease obligations we're worried about. So it’s all about reducing the cost structure and improving the economics before we really speed up, but there is going to be efficiencies dialed in, I think that kind of goes into what the capital reduction that we've shown and where we are given guidance on the production levels.

Okay, one more for me and I'll let somebody else jump on. When I start thinking about the toggle and what you guys are looking for mid year, obviously you want service cost reductions. And you mentioned this, you alluded to this that your 2015 is more captive, your capital program is more constrained by your cash flow. What should we look for? What metrics should we be looking for on our end to try to guess when and if you decide to ramp?

Well, I mean the easy thing is we'll signal because we'll pick up rigs when we start to ramp, so but I mean there’s two things. There’s two parts that equation, one is a commodity price, but the bigger deal right now is cost structure and we made the decision to consciously and aggressively drop rigs, because the cost structure needs to come down for this price environment and we can always ramp back up, I mean you look at our depth of our portfolio in the Permian we showed we delivered 25% year-over-year growth, we got very, very deep high graded inventory. So it’s going to easy to scale up, but the big deal as we've got to drive the cost structure down to reflect this current price environment.

Okay, thank you. I'll let somebody else jump on. I appreciate it.

Thank you.

Your next question comes from the line of Pearce Hammond of Simmons & Company. Your line is open.

Good afternoon, guys.

Hello.

Hey, John, I was curious how you can reduce your North American rig count so sharply, yet keep production flat. Touching on the earlier question, is this due to greater efficiencies or well productivity? Or is it a backlog of drilled but not completed wells that you can work through this year? And then, if you stayed at an average of 17 rigs into 2016, do you think you'd keep production flat there? Or would it start to decline?

Well, I mean clearly we are able to drop quickly because we did not have a lot of committed contract or required location we had to drill. So we are able to scale back very quickly. We will come into 15 with a pretty deep backlog of wells and we have pushed a lot of those completions back, because quite honestly, we've got to get the completion cost to come in line as well. So we are going to very methodically push those back. If I can defer those, see the benefits of lower completion costs and then bring those back on and potential higher price environment and later there is a big win there. As for what 16 looks like a lot of that’s going to depend on where we are mid-year and what the program does. So we’ve got the benefit this year of having a backlog of completions and we can spread those out and it's kind of how we planned it.

And then, John, I know this question I'm about to ask is tied into what the cost structure is, but at what oil price would you be willing to accelerate the drill bit again?

Right now, the wells we're drilling are economic because we've been aggressively attacking the cost structure. As I mentioned in the script, our limitation is cash flow and we're wanting to put it, our cash flow to work in the best places, we don't feel right now that tapping the balance sheet to drill wells that we don't have to drill in this price environment or cost structure makes sense, so I think we've got a deep inventory and when the economics and more cash becomes available we will ramp back up.

Great, and one last quick one for me. What level of service cost concessions are you currently experiencing? And how much do you think you can capture this year on a percentage basis?

I mean I'd say in general, if you look at our Eagle Ford and I alluded to that in the script, we showed cost in our November update of around $7 million, we're early last year we were North of eight, I can tell you we’ve already reflective of old service costs, we just TD'd a well in the 6.5 range. We feel like we can get those well under six so we're already down 10% to 15%. We got now some things dialing in that's going to help our numbers go further, so with the drop in oil price being where it is I know a lot of our competitors are talking about just seeing 10% well cost reductions that's going to have to be more than that. We're seeing more than that.

Thank you, very much.

Your next question comes from the line of Arun Jayaram of Credit Suisse. Your line is open.

Good afternoon, John. I first wanted to ask you a little bit about the shape of the production profile in 2015. I guess you guided to 300,000 to 305,000 BOE. That suggests you'll stay relatively flat all year. Is that how we should think about it? Because what we don't know is how you plan to time the completions throughout the year?

Yes, Arun, with where Anthony alluded to first quarter being and where we’re going to exit where we average it's pretty good assumption on how we are got it dialed in right now. Obviously first quarter is being impacted by the significant down time we've had already. First two weeks of January were very rough in the Permian and central so that's part of why you see more of a flat look because we've had a lot of down time early but we do have a lot of completions that we'll be able to bring on and obviously drilling better wells with the rigs we’re going to be running too so I think that's probably a pretty reasonable view of how we’d look at right now.

Okay, the only thing that wasn't quite intuitive, you guys talked about spending $800 million in Q1 which is about 36% of your budget yet you're deferring completions, could you just maybe reconcile that a little bit, the timing of the spend?

Sure. It's just simply we're coming in hot, plus we've got the LNG spend too that when that closes so you've got a combination, but you don't go from running 90 rigs to down to levels we're going to be and not have a hot spend early.

Makes sense. Just a couple other quick ones. John, you alluded to $800 million of acreage acquisition costs in Q4. Can you give us some details on where you added the acreage?

We touched on that in November. I mean it was predominantly in our key areas. A lot of that was Eagle Ford and Canyon Lime and Permian and really within our core areas.

Okay, and then my final one is on the international. In the slides, when you do the pro forma adjustment, you talk about the Australia asset sales and North Sea. I believe Australia's Balnaves. Can you give us some numbers around the magnitude of the sales at Balnaves and in the North Sea?

Well, I let Gary answer that one, Arun.

Arun, we can say that the Scott, Telford and the Balnaves you are going to be in the 10,000 sort of type barrel range.

Okay, thanks a lot Gary.

Your next question comes from the line of Bob Brackett of Bernstein. Your line is open.

Hey, question on the status of the split of the international assets. Is that on ice in a low-price environment? Is that still something that's a strategic priority?

Right now in this price environment a lot changes a $100 price environment to $50, so right now as I stated in the prepared comments, we are not proceeding with anything on the spinoff of Egypt or North Sea. We are looking at possibly still monetizing or the non-LNG assets of Australia, but at this point in this price environment I think you're seeing strength of our international assets complement our North American portfolio.

And can you talk about where your hedges stand for 2015 now, and what your hedging strategy this year and next might be?

Right now, we’ve got very little hedges 415 and that is one of the things we're going to be looking at is was what type we've gone through a major transformation as we started thinking about 15 the world changed and that's something we'll be looking at early part of this year is what type of hedging strategy we would use in the future.

Your next question comes from the line of Michael Rowe from TPH. Your line is open.

Hi, good afternoon. I was wondering if you could maybe provide a little bit of context around your backlog at the end of the year, of your $2.2 billion mid-point budget for North America onshore. How much of that is actually just blowing through and completing drilled but uncompleted wells versus actually going and drilling new wells to add to the production base?

Well I’ll say we haven’t provided a lot of color there, we are coming into the year with a couple of harder wells, so it is a portion of that budget, but we are going spread it out over the year.

Okay, that's fine. And then, switching to one specific region, the Eagle Ford, that has a pretty sharp rig count drop down to about one maybe two rigs in 2015. You mentioned getting the cost structure down to $6 million per well, so what exactly needs to happen to get there to make that asset more competitive? And if we see a rebound in crude oil prices, do you expect that cost structure to come back up? How should we think about that specific asset and the drilling economics there?

Well the answer there is when you look at our cash flow, still the lion share of our capital is going to go into our bread and butter Permian which has been driving our performance. So we're going to be down to one rig - one to two rigs in Eagle Ford, one to two rigs in the Canyon Lime, those are both areas where we are advancing deep inventory of economic wells, but in terms of how they stack out right now, the Delaware Basin and so our step in the Permian is going to little bit slightly higher, but I do not see some of the efficiencies we are driving into those well costs, a lot of those are utilizing 3D avoiding drilling hazards or efficiency, there is more to this than just service cost. So I don’t envision any of those coming back in even if prices rebound. So that’s the nice thing about slowing down is this is going to really give us a chance to when we speed back up to do it a lot more efficiently in a lot better later, because a lot of the changes are not just come out of service side, they are out of our end and designs and other efficiencies.

Your next question comes from the line of Leo Mariani of RBC. Your line is open.

Hey guys, I was hoping you could speak a little bit about the improvement you saw in results in the Central Basin, particularly some of these Lower Marmaton wells looked really massive. Could you speak a little about to some of the well costs you're seeing in Central? I know it's a bit different by some of these formations and where you're going to be targeting most of the capital in 2015 there?

Well we are really going to have one rig around it, so what we’ve shown though is by taking a very measured and disciplined approach which we made a lot of operational changes you know management changes last summer in Tulsa, and you're seeing fruit of that really start to come through. It's more conventional reservoirs. We've got to do more homework up front. It shows the depth and quality of the acreage up there but really when you look at this year it will be a very small program just based on the commodity mix and so forth.

Okay, so is there any particular zone that you guys focus on? Or is it still multiple horizons in terms of how you tackle this?

It will high graded list of all wells there, so we do have a couple hundred acres in the Woodford that will be active there, about 50,000 net in the ops report, there will be lower Marmaton and then we got some nice Cottage Grove and Cleveland and big kind of small assortment of all the best projects we have from all those formations.

Okay, that's helpful. And in terms of your guidance here for the first quarter in North America, your 300,000 to 305,000 BOE, does that exclude production that you're selling as part of the LNG divestiture? Some of the Kitimat properties? Or is that included in those numbers? And are those going to be discontinued or how does that work?

There is actually with what’s being sold with Kitimat there's not any production would be dialed into those numbers. So that is an adjusted number that you would expect to see from us post sales.

Your next question come from the line of Harry Mateer of Barclays. Your line is open.

Hi, good afternoon. The first question, so you've mentioned that you plan to initially use asset sale proceeds to pay down debt. First, can you just tell us how much CP and/or credit facility borrowings you had at the end of the year? And then can you talk about how you plan to pay down the debt? Are you considering more liability management actions like you did in late 2013 to take out long term debt? Or are you just looking to take down short-term borrowings?

I'll have Anthony answer that question.

Just short-term borrowing, but we had $11.2 billion of debt at the end of the year with $800,000 million of cash on the balance sheet for net debt position of 10.4. We’ve increased our CP line of credit and $3 billion to $5 billion in December. So we have about almost $4 billion of available credit line.

Okay, and then second, can you just update us on your balance sheet and credit rating priorities in general? So any sense for what credit ratings you're trying to target for Apache, given the current commodity price environment and your view that you're no longer looking to spin Egypt or North Sea? And are there any targeted leverage metrics we can be thinking about or what is the right debt balance for the company?

We are still working with the credit rating agencies on what our credit rating will be but we intend to pay down debt and have a very strong balance sheet.

Your next question comes from the line of John Freeman of Raymond James. Your line is open.

Afternoon. I was looking at the rig count kind of break down if I wrote it down correctly, John, when you were going over the rigs in the Permian. And it looks like the Delaware Basin is about the only place in your whole portfolio where the rig count's not really changing from the November update. And obviously it makes sense, given at that time you all said that was the highest net present value per well. I'm just trying to get a sense of how you all think about the capital allocation, the Permian where trying to balance the fact the Delaware Basin is your highest NPV, but you're still running rigs in some of these other areas of the Permian.

The issue there is you correctly picked up that rig count did not change and our governors in the Delaware right now are more driven by infrastructure, take away capacity in those things. So you are exactly right. That is not a piece, it is at the top of the food chain. And it didn’t change. The others had to compete with the Permian and that's why when you look at we’ve got the lion share of our capital there, so Permian still will be getting 60% of our total North American capital and which is about in line with what we showed at the November update.

Okay and then last one for me, just thinking about these delayed completions, can you give just kind of a rough number on where your backlog of uncompleted wells stands in the Permian?

We’re kind of couple hundred total. Where the rig count's been, a lion's share of those would be in the Permian.

Your next question comes from the line of James Sullivan of Alembic Global Advisors. Your line is open.

Hey good afternoon, guys. I wonder if you could just - we've been dancing around this a little bit - but just give us a Q4 fully-adjusted volume number. You guys gave the full-year number which is helpful for both international and North America. But just net of the LNG upstream, net of the North American packages, net of Australia and net of North Sea, that whole thing.

Yes, hey. This is Gary. We are looking at about 319,000 a day as your pro forma Q4 number in North America. And about 225 international and offshore.

Perfect, thank you very much for that. The other thing I had was, you guys gave some color which was a little bit distinct in your release, about completion costs. And it sounds like - you're the only guys that I've really heard saying that you're thinking about delaying completions, not just overall activity, into the second half of the year. With the thought, perhaps, that you'd capture a little bit more savings on the completion side, maybe. Could you speak to what you've seen in the market in terms of differential deflation rates on the drilling side, say the rig side and drilling versus fracking and completing the wells and whether that's driving your thinking? Or am I reading too much into your comments there?

Well, I mean I think the simple answer is we need to get the costs down in line with the oil price environment and when you look at 60% to 65% of your total well cost is in the completions, a lot of folks were assuming you'd just move through the backlog and keep completing the wells, but I mean that's some of the best things we can do right now to push those back because up front, significant savings there lets us drill other wells, so we're seeing substantial numbers on both the rig rates and then with what we've done basically by setting down most of the rigs, we're able to come in now and contract what prices should be in a $50 price environment and the same thing applies on the frac crews.

Your next question comes from the line of John Herrlin of Societe Generale. Your line is open.

Yes, thank you. John, since you've taken the helm, have you had any other leadership team changes other than the addition of Mr. Riney?

At this point given where we are John, we are taking a hard look at everything. I’ve taken a pretty measured approach of stepping in and had a lot of things to get knocked out off in early. I really want to think about what we have North America look like. I've got Tom in place on the international side and I'm going to take a very measured approach and think through what this thing ought to look like for the long-term and come out with something at a later day.

Okay, thanks. On a pro forma basis for the U.S., what's your average decline rate now?

Right now if you look at our just in the U.S. our PDP decline is across all products. Oil is about 26%, our total streams around 24% in North America and that's just on a PDP basis.

Your next question comes from the line of Joe Allman from JPMorgan. Your line is open.

Thank you, operator. Hi, everybody. So just to recount in North America, what's that rig count in the fourth quarter of 2015? And then, I know you answered this a little bit earlier, but if it's as low as I think it is, I would assume that going into 2016 it's going to be hard to keep production flat. And do you exhaust the wells waiting on completion? Do you exhaust those by the end of 2015?

All right. What I would say about that Joe is it will just depend on where we are and where prices are. I mean clearly if we are under $50 it will be lower than the average for the year considerably come in hot, but we are going to kind of let things dictate what we say going into the third and fourth quarter kind of based on where the market conditions are and also where the cost structure is. I mean that’s the other piece, we get cost down we would be able to pick up too so.

Okay, so second question, again, following up from the first. Do you exhaust the inventory of wells waiting on completion by year-end? And separate question, the $2 billion ceiling test write-down that you described, North Sea. You described US. You talked about some acreage that you're not going to drill. Could you give us more details on that please?

Well in terms of completion backlog we’ve got – that’s kind of at our disposal as to when we would complete those wells and obviously if we're an under 50 and prices have come on down and we will probably get some of those on and may choose to wait and see an increase in price when we go ahead and complete some of those wells. For the write down of the charges, I’m going to let Anthony handle that question.

Yes, we haven’t provided any details in terms of split out between North America and North Sea at this point, but the total is $2 billion for the ceiling test and another $1.3 for the balance, for the impairment.

And your next question comes from the line of Doug Leggate of Bank of America Merrill Lynch. Your line is open.

Thanks, good afternoon, John, and congratulations on your appointment. John, I wonder if I could ask you about the organizational capability from going from 80-plus rigs to 17 rigs. What does that do to you? If you were to look into being able to ramp that up again in the event of an oil price recovery, do you intend on keeping the organization static? Will you see some headcount reduction and cost reduction at the corporate level? Can you walk us through how you think about that and how patient you're prepared to be until the oil price recovers if you choose to do nothing?

Well Doug we have been looking at G&A, looking at it pretty hard in terms of ways to reduce it, we did announce we had some reductions in January about 5% worldwide when you look at the numbers, clearly we had an organization in place its capable of running 90 plus rigs in North America which at this point its less than that. So we will continue to look at things, one thing we are doing is we're taking some of our young engineers and we are putting them in the field which is allowing us to replace some contract folks so we’re being pretty smart about how to leverage folks, get some good experience and also puts us in a better position, in fact I have got a lot of good reports on the savings and some of the benefits that we’re having about putting those guys out in the field. So we are going be pretty prudent, in terms of what we do we will continue to look at what is the best organization for North America in terms of where things are going and do not worry about being over ramp up, I mean its easy to ramp up after you’ve been there before, I mean we’ve got great capabilities in the Permian and our other regions and it will not be hard to ramp up. And in fact I’ve got a lot of ways thankful because its gives us a chance to really look at our processes, our efficiencies, our inventory and really spend some time, high grading that and I will promise you will do it when we ramp up differently then would have been do it right now.

I know it's not an easy question to answer, so I appreciate the answer. I wonder if for my follow-up if I can go back to Bob's question earlier about the international strategy. I really just want to get clarification on this because for the past year, I guess there's been an expectation that the international business would be spun off completely. Is this a temporary situation? Is it now strategic? Can you help us understand what has flipped the Board's view on this? Because clearly it's a massive turnaround to decide to keep it. And will it compete for capital? I'm just trying to understand is this now – does the new Apache this time include Egypt and North Sea as go-forward assets? Or is this a stay of execution? I'll leave it there.

There’s a couple things. One of our key strategic objectives was to sell the LNG and that will close in the end of the first quarter. Secondly, we are looking at our conventional business in Australia, Egypt in the North Sea are different businesses then what we are doing in North America, but the thing you are going to look as generate free cash flow they always have had higher rate of return projects which complement our portfolio and clearly in this price environment it would not make sense to monetize them and they complete things very nicely. So at this point, there is no plans to sell or spin and they fit nicely with the portfolio when we ramp back up we will grow North America at faster rate.

Your next question comes from the line of Brian Singer from Goldman Sachs. Your line is open.

Thank you, good afternoon. Apache has a number of different opportunities within North America onshore to ramp up investment when the time is right. Based on what you're seeing now, what is the best way to do that? Do you see concentrating more in specific areas among the Delaware Basin versus Midland Basin versus East Texas, Eagle Ford to gain greater scale when you do want to ramp up and efficiencies? Or should we expect a gradual ramp up everywhere when the time is right?

A lot of that's going to depend on a lot of the strategic testing and the things we're doing in these plays right now. We're learning things each day. We've got the rig we're running in the Eagle Ford will be telling us very critical things as well as the Canyon Lime as well as the Permian so the good news is we've got a deep inventory and I'm confident we're going to have plenty of economic projects. We've got more right now than cash flow to spend at these levels so a lot of that Brian will just depend on how we see each of those plays at that time. One place is one of the questions earlier we have not slowed down in the Delaware and we will continue to try to expand that and then I think we're going to be in a position to we've gone from 12 rigs down to, we will be at four and down to one to two in the Eagle Ford. We can ramp that back up very quickly. The Canyon Lime we can put up at five or six in there and the neat thing is we're high grading a lot of prospects and a lot of acreage and we'll have a lot of choices to choose from.

Thanks, and as my follow-up, and it actually follows up on a couple of questions earlier, and as well as your response here just now. You say you want your costs to come down, you want prices to go up. Your returns are strong from the portfolio today. But is what you're saying that every well that the 64 rigs you have dropped, or are planning to drop, achieve attractive returns at today's oil prices. But simply you've dropped them to stay within cash flow? Or are there areas where you need costs to come down to meet your return threshold? And if so, can you provide specifics?

It's a combination. There are a lot of those projects on the lower end that need prices down to where we want to drill them right now. But I can tell you where we made the cut based on our current cash flow I have more capabilities right now of economic projects we were electing to defer because we don't have to drill them. I mean the point is why drill them in this price environment when things are going to improve? So it's a combination.

Your next question comes from the line of Richard Tullis from Capital One Securities. Your line is open.

Thanks, good afternoon, everyone. John, following with the rate of return line there, so we saw the rates of return associated with your portfolio at the November meeting based on $80 oil, $4 gas. What do you think the impact is on the portfolio in general, using current commodities and the reductions you've seen in well costs to date?

Well there's no doubt that they drop. You go from 80 and 4 and you go to 50, and call it 50 and 290, apples-to-apples they have dropped. Now we are working on the cost side and we still have very attractive returns in the place where we are active, so but there's no doubt right now, the returns are costs haven't come down to put the returns in line with what we showed you and $80 a barrel in November.

Okay. And looking at the Eagle Ford A area, back in November it looked like you were going to be quite active there in 2015, running as many as 10 rigs with a fairly high rate of return. Why the significant change down to one rig now? And I'm not sure if that's going to be in the A or the B area? Has your thinking on that play changed any? Or is it more just a rate of return thing right now?

It’s neither its cash flow in the portfolio of what the dollar amount is so it's simply cash flow. We got more - there is lot’s of wells we could drill in the Eagle Ford right now, but it’s purely just a function of we aren't going to tap our balance sheet to develop production.

Your next question comes from the line of Jeffrey Campbell from Tuohy Brothers Investment Research. Your line is open.

Hi, John. I'd like to second the congratulations on your new CEO role. First, I want to ask about Canada. I noticed you're going to stop drilling in March 2015. I just wondering will the completions be delayed there as you were talking about doing elsewhere? Because in November you made it clear this is an emergent play, so was just wondering if maybe the desire to see results would be a part of the calculus.

Well, Jeff, thank you. Two things. Number one, we do have excellent results and high hopes for Canada, and but there's two things. Montney wells we are going to be completing. There are little more dashing than the Duverney, and the Duverney wells have great economics, we will be completing the - we got a seven well pad there it’s testing two different spacings. We will be completing those in the third quarter of this year. It’s simply a function of cash flow in Canada is limiting how much we're spending in Canada so that's why and obviously with the winter drilling season we've come in very hot in Canada and actually Canada is going to be a slight out spend versus cash flow. So it’s purely same answer again. It’s cash flow driven is what's causing us to do that and the good news is after these two wells we had to hold acreage in the Montney we don't have any acreage problems in Canada this fall. And obviously if prices change going in third or fourth quarter you could see us decide to step back up. But we will right now, the plan would be not to do anything.

Okay thanks and to ask a little bit different question. In Egypt we're reading a lot about the government trying to procure pipeline nat gas Israel as well as floating LNG. Is there any financial incentive to try to increase the natural gas production into the Egyptian market, because I notice your highlight wells are very high oil cuts.

Yes, I’m going to have Tom handle this one.

The answer is that the Egyption government has kept the gas price artificially low for 12 to 13 years now, 14 years and there is no indication that they have the willingness or desire to increase the domestic production gas price and as such, we continue to focus on oil and drill sufficient gas wells to keep our infrastructure full primarily by focusing on higher condensate yield reservoirs so that we could also increase liquids productions at the same time.

Your next question comes from the line of Michael Hall from Heikkinen Energy Advisors. Your line is open.

Thanks, appreciate the questions. I guess you provided the rig counts going forward for 2015. Maybe circling around this weighted uncompletion question in a little different way. How many wells do you anticipate to put on production regionally in 2015? And then how much of the, you said 200 or so in backlog, so I'm just trying to think through the organic program underlying that is...

Yes I would – we have not disclosed the well counts in terms of lay that much detail out in terms of the plan. We kind of hit on rigs and we have a couple hundred wells in addition to those and I mean, if we want to get back with them later Gary or something on details.

Yes Michael, we can follow-up with you there, but we really haven’t kind of put anything out there on the specific well counts you know I just...

Okay, but if -- relative to the Analyst Day in November, you cut the rigs probably 50% or more, or not quite. But is it fair to say then you're only taking the well count down by a quarter or so or is that simple math?

You can do it, you can probably do the math on the rigs, but the other factor is there costs are coming down, so it’s not straight linear math.

Fair enough. And then you provided the PDP declines, that's helpful. How did that vary regionally?

That’s another things, I don’t have that detail for you. I’m just giving you a general on North America.

That's fair and that's helpful. And then final one of mine, just housekeeping, on the budget for 2015, does that include capitalized interest? And if not, roughly do you all know what that might look like?

It does.

Your next question comes from the line of John Wolff from Jefferies. Your line is open.

Afternoon, guys. I'm just looking at the numbers and intuitively spending about 36% of your budget in the first quarter and looking for exit rate that's similar. It just feels like there's a contemplated CapEx increase in here in the second half of the year, based on being able to achieve that type of momentum with the base decline rates that you've laid out. I'm just trying to get to the math. Is there a contemplated CapEx increase coming in May-June timeframe?

Not in this budget at all.

Can you give a little intuition on how you only have two-thirds of the budget left to spend in the last three quarters? It should be down dramatically in terms of the spending versus 2014. Is it a assumption that oil service costs are down 20%, 25%? Is it the expectation that oil prices are up $10? We're just having a hard time getting anywhere near the math on the domestic production.

Well it works fine on our end. I mean basically it's a function of how we spread the completions out. We've come in hot. We've got with Canada having completed it, you're not going to be completing those Duvernay wells until the third quarter. The math works. It's just a function of we pushed a lot of completions back and we'll bring them on at the appropriate time. But there's nothing baked in beyond, there's no capital increase. There's no oil price increase, you know we wouldn't be very smart to do that.

Your next question comes from the line of Leo Mariani from RBC. Your line is open.

Hey guys, I just wanted to ask you a little about the M&A landscape. It sounds like in your prepared comments you spoke about rather buying acreage and maybe securing more assets as opposed to drilling. Can you talk about what you see out there that might be available? And what type of size of purchases are we talking about?

I mean I think the point is we would be opportunistic. I mean we see a potentially if things stay where they are there's a lot of folks that are significantly out spending. There is a lot of clocks on acreage. We're seeing things pop-up right now and for drilling a well we can earn pretty big acreage blocks. I think there's just a lot of opportunity that could surface and we would expect to surface.

All right. And moving over to your international guidance for 2015, you guys talked about 207,000 barrels a day, which I guess is after subtracting out final tax, working interest barrels and some tax barrels. Do you guys have that guidance numbers kind of prior to those subtractions? Because I know you guys reported that way in your financial just to keep it apples-to-apples for the financials?

I’ll let Gary.

I’ll tell you what. Why don't we do this and follow-up because we've gone over the top of the hour. Why don’t we follow-up with offline on those, on that reconciliation.

Your next question comes from the line of John Herrlin from Societe Generale. Your line is open.

Yes, hi, just one quick follow-up. Obviously there's been a lot of questions regarding oil field services costs, completion costs, et cetera. On a going-forward basis, do you think the services providers will be more willing to index so you avoid kind of this boom-bust type pricing? Or will it just be business as always?

John I mean that’s one of the things we’ve looked very heavily at and we think it makes a lot of sands and quite frankly we should have done it a while back. So we would like to think that you can do that.

Okay, great. Thank you.

And your last question comes from the line of James Sullivan from Alembic Global Advisors. Your line is open.

Hey guys, thanks for running this call real quick, do a little follow-up. Can you guys talk a little bit about what you're doing in Central Oklahoma? You guys did put the Woodford wells up on the ops report, but are you guys targeting some of the multi-lateral areas there with the Springer and the Merrimac and other stuff? Just get a little detail on that.

Yes, I mean as I mentioned we are going to have one rig pretty much dedicated. We will be drilling some Woodford wells. We've got about 200,000 acres gross 50,000 net so we will be active there with that and we’ve also got some really look in economic prospects in some of our other plays. So its juts simply budgeting our capital there, but you will see some more Woodford wells from us.

Great, and just a quick follow-up to that. Is that one of the areas you guys talked in the leasehold work you've been doing. I think East Eagle Ford probably got some of that money and some of the other areas, but are you working there as well with the leasehold?

We have been working to fill in and bolter on our position, but that’s relevant for all of our key areas where we would be active drilling. End of Q&A

This concludes today's Q&A session. I now turn the call back over the Mr. Clark.

Well thank you everybody for joining us and please follow-up with myself or my team in IR if we can handle any of the other details that we didn’t get to on the call today and we look forward to speaking to you all next quarter. Thank you very much.

This concludes today’s conference call. You may now disconnect.