Murphy Oil Corp (MUR) 2012 Q4 法說會逐字稿

Good afternoon, ladies and gentlemen. Welcome to the Murphy Oil Corporation fourth-quarter 2012 earnings conference call. Today's conference is being recorded. I would now like to turn the call over to Mr. Steven Cosse, President and Chief Executive Officer. Please go ahead, sir.

Thank you, operator. Good afternoon, everyone. Thank you for joining us on our call today. With me here are Roger Jenkins, our Executive Vice President and Chief Operating Officer; Kevin Fitzgerald, our Executive Vice President and Chief Financial Officer; John Eckart, Senior Vice President and Controller; Barry Jefferey, Director of Investor Relations; and Tammy Taylor, Assistant Manager of Investor Relations. Barry?

Thanks, Steve, and welcome everyone. Today's call will follow our usual format. Kevin will begin by providing a review of fourth-quarter 2012 results. Steve and Roger will then follow with an operational update, after which questions will be taken. Please keep in mind that some of the comments made during this call will be considered forward-looking statements, as defined in the Private Securities Litigation Reform Act of 1995. As such, no assurances can be given that these events will occur or that the projections will be attained.

A variety of factors exist that may cause actual results to differ. For further discussion of risk factors, see Murphy's 2011 annual report on Form 10-K and the September 30, 2012 quarterly report on Form 10-Q on file with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements. I will now turn the call over to Kevin.

Thanks, Barry. Net income for our fourth quarter of 2012 was $158.7 million, or $0.82 per diluted share. This compares to a net loss in the fourth quarter of 2011 of $113.9 million or $0.59 per diluted share.

For the entire year of 2012, we had net income of $970.9 million, or $4.99 per diluted share, compared to net income in 2011 for the full year of $872.7 million, or $4.49 per diluted share. From continuing operations, net income in the fourth quarter of 2012 was $162.4 million, or $0.84 per diluted share. This compares to a net loss in the fourth quarter of 2011 of $117.9 million, or $0.61 per diluted share. For the entire year's comparison from continuing operations, in 2012, we had net income of $964.1 million, or $4.95 per diluted share, compared to net income last year of $729.5 million, or $3.75 per diluted share.

The fourth-quarter and full-year results for 2012 included after-tax impairment charges of $239.6 million associated with both the Azurite field offshore of the Republic of the Congo, and our ethanol operation in Hereford, Texas. It also included US income tax benefits of $108.3 million associated with operations in the Republic of the Congo and Suriname. The fourth-quarter and full-year results for 2011 included a $368.6 million impairment charge for which there was no income tax effect for the aforementioned Azurite field.

Looking at income by segment. In the E&P segment, net income from continuing operations in the fourth quarter of 2012 was $145 million, compared to a net charge of $144.6 million last year. The higher earnings in the 2012 quarter were mostly attributable to the larger impairment at the Azurite field in 2011 and the previously mentioned tax benefits recognized in 2012. The fourth quarter of 2012 also included higher crude oil sales volumes and lower exploration expenses but these were mostly offset by lower realized prices for crude oil and natural gas and higher extraction and administrative expenses.

Crude oil and gas liquids production averaged just under 133,000 barrels per day in the '12 quarter compared to about 108,800 barrels per day in 2011. The increase is primarily the result of ongoing drilling in the Eagle Ford Shale and the purchase of additional interests earlier in the year in the Thunder Hawk and Front Runner fields in the Gulf of Mexico.

Natural gas lines were 473 million cubic feet per day in the 2012 quarter, compared to 488 million cubic feet per day in 2011, with the decrease primarily due to lower production from the Tupper area in Western Canada as we scale back operations there due to persistently low North American natural gas prices.

Looking at the downstream segment. In the fourth quarter 2012, we had net income from continuing operations of $38.5 million compared to net income from continuing ops of $61 million in the fourth quarter of 2011. The main driver of the income decrease for the current quarter was the previously mentioned impairment charge related to our ethanol plant in Hereford, Texas.

In the corporate segment. In the fourth quarter of 2012, we had a net charge of $21.1 million compared to a net charge in the fourth quarter of 2011 of $34.3 million. In 2012, we experienced more favorable results from transactions denominated in foreign currencies and lower net interest expense, partially offset by higher administrative costs.

Capital expenditures for 2012 totaled about $4.4 billion, approximately 97%, or a little over $4.2 billion was spent in the E&P segment; approximately $583 million in exploration; $311 million for approved property acquisitions; and the remainder for development projects. For 2013, our budgeted capital expenditures, which were approved by our Board in early December, totaled $4.3 billion, with approximately 95%, or about $4.1 billion slated for the E&P segment.

Of that, approximately $3.6 billion is for development projects and the remainder, or about $500 million, is to be spent on exploration activities. Our budget assumes WTI pricing of $85 per barrel and Henry Hub pricing of $3.50 per Mcf. At year end 2012, Murphy's long-term debt amounted to approximately $2.25 billion, or 20% of total capital employed, while cash, cash equivalents, and short-term investments in marketable securities totaled a little over $1 billion. With that, I'll turn it back over to Steve.

Thanks, Kevin. 2012 was a profitable year for us, with $971 million of net income and cash flow of $3.5 billion. In the upstream business, we drilled 10 exploration wells and had 7 discoveries. We increased production by 8% year-on-year, which puts us near our 14% compound annual growth rate over the last five years. We had an excellent year in reserve replacement, with Eagle Ford Shale leading the way. We continued portfolio rationalization last year and signed agreements to sell our UK business and those transactions I would expect to close them during the first quarter.

In addition, we acquired bolt-on acreage at our Seal heavy oil property where we added production reserves that fit well with our long-term enhanced oil recovery plans. In the downstream, we approved the spin-off of the US retail business into a separate entity and solidified our relationship with Wal-Mart through an agreement to grow at the retail network with over 200 additional locations.

We moved forward with some key initiatives for shareholders, including increasing our regular dividend by 14%, declaring a special dividend to shareholders, and implementing the share repurchase program. Dated Brent is the benchmark for the majority of our crude oil production. It continued to outpace WTI for the quarter and the full year, with the spread averaging $21.80 and $17.70, respectively. After hitting lows near $2 per MMBtu earlier this year, in an oversupplied market, natural gas prices in North America showed some strength in the fourth quarter with Henry Hub averaging $3.55 per MMBtu.

Globally, continued strong demand for LNG provided support for our oil indexed Sarawak gas production. US retail margins started the fourth quarter strong overall as wholesale prices fell through October, but then eased off in December in a rising market and averaging $0.141 per gallon for the quarter. We continued to move forward with the spin-off of our US retail business and in December, we filed a ruling request with the Internal Revenue Service seeking confirmation of tax-free status of the spin. We expect to receive an answer by mid-year.

This month, we announced the appointment of Andrew Clyde to the position of President and CEO of our US retail marketing subsidiary. Andrew brings a strong background in gasoline and convenience retailing and will provide key leadership as we transition the business in the coming months. In the meantime, we're working on all aspects of establishing two separate companies to be prepared to move forward, pending confirmation of the tax-free status of the spin.

We're working to identify key members of the management team in preparing the strategic business plan. We anticipate completing the spin transaction in the second half of the year.

The UK downstream business, as we've announced before, will remain with the Murphy Oil Corporation until the sales process for those assets is complete. Roger, do you want to update on E&P?

Thanks, Steve. Sure. In exploration, starting off in Malaysia, we drilled a Block H [Ilum] well and made another gas discovery there, our seventh in a row in that play, encountering 280 feet of pay with a resource level near 150 Bcf.

We will drill another well later this year and continue to work with our partner, Petronas, towards sanctioning the upstream portion of our Floating LNG project for the Block in the late third quarter of this year. We've now established over 1.1 Tcf gross resource but the project can have a third-party certification process ongoing.

In Brunei, we are currently drilling the Kelidang Northeast-1 well in the CA-2 Block. The well is prospective for gas and is part of a larger cluster of gas-prone opportunities. A gas discovery here would fit well with Brunei's current LNG supply requirements. In the Congo we have relinquished our interests and operatorship in the MPN Block, effective at the end of last year. In addition, we've given notice of our intention to relinquish our interests in the MPS Block at the end of this quarter.

In our Atlantic Margin focus area, we signed a PSC for Block W in Equatorial Guinea. We hope to start seismic work there late this year on this new acreage area. Further in the play, we signed a farm-in agreement for the [Elombo] Block inboard of our current Ntem Block in Cameroon. We now have a significant list of prospects in Cameroon focused on the Cretaceous Span play.

The Elombo Block also contains shallow-water prospects and a spud of the first well is scheduled to take place later this quarter. We plan on spudding two deepwater wells, one in each of our license later this year. We'll operate at 50% working interest in the deepwater portion of these blocks and the prospects here are significant, at over 200 million barrels gross each.

In Australia, we drilled an unsuccessful commitment well at the Euphene-1 in Block WA-423P in the Browse Basin offshore Australia to test a three-way trap in the Permian section. The well reached TD in January and was plugged and abandoned. In November, we announced our farm-in to the WA-408-P Block at a 20% working interest with Total as operator and Santos as the other partner.

We're drilling the first well now at Bassett Deep West. The results of the well are expected near the end of this quarter. We will then partner in the Dufresne well, with results in late quarter two. These two large Jurassic-aged Plover four-way closures have a total gross resource combined of 7 to 14 Tcf.

In Business Development and New Ventures, we are continuing to progress land additions offshore Vietnam. In our portfolio, we've signed the purchase and sale agreements for all of our UK upstream assets at Schiehallion, Mungo/Monan, and Amethyst in the fourth quarter and expect to close those three transactions this quarter. As mentioned earlier, we have closed on the Seal acquisition at year end.

In Malaysia, our work at Kikeh continues on track. We've seen a very stable production rate of late on Kikeh and expect the same flow capability well into this year. We do have scheduled shut-ins planned in quarter two and quarter three to install production facilities associated with the Siakap North-Petai field which will be tied into the Kikeh FPSO.

The Kakap-Gumusut early production system came online as planned. We currently have two wells flowing into Kikeh. This production should remain stable through 2013. The main Kakap-Gumusut project, with its stand-alone floating production unit, comes on-stream late this year or early 2014.

In Sarawak, Malaysia, we continue to progress the development work on our four new oilfields to flow later this year at Patricia, Serendah, South Acis, and Permas. Prices for our Sarawak gas remain strong on this oil indexed production with prices at or near $7 now since mid-2011. We had a planned seven-day shut-in this month to install a new compressor system that will enable us to increase production to 300 million per day gross starting later this quarter.

We now have a third-party certified total proven EUR for SK gas of over 1.1 Tcf gross and a probable total recovery of 1.5 Tcf. To date, we have produced 276 Bcf gross of this total. Recently, our partner, Petronas, confirmed that we can extend our gas agreement for the total 1.1 Tcf proven amount.

This will allow our current 250 million a day gross production level to be produced past 2022 under our current terms.

As mentioned in Kevin's remarks we had an impairment on the Azurite development taken at year-end 2012. During the course of the fourth quarter, we attempted to sidetrack an existing well to access a large portion of the remaining reserves for the field. The sidetrack suffered a mechanical failure, preventing us from performing the operation. We continue to produce the field while we evaluate options.

In the Eagle Ford Shale, development work is continuing at a steady pace with 10 rigs and three frac crews working continuously. We now have drilled 216 wells and have 163 on production. Production averaged over 15,000 BOE per day net in 2012 and we plan to average approximately 30,000 BOE per day net this year as per our current budget.

Field development optimization continues as we move to all pad drilling and progress downspacing to 80 acres across all three play areas. We continue to see improvements in drilling and completion costs, with the drill curves showing improvement of 35% to 40% across the entire play with the pace setter wells being drilled in each area in the fourth quarter. The total days to drill in case across our acreage now ranges from 11 to 13 days.

We see additional upside to the play with potential in the Pearsall Shale in the Buda line. We've drilled a vertical well through the Pearsall and logged and cored the zone to spud our first horizontal well in this play, and hope to have initial flow results later in quarter one. We see a follow-on well with flow results expected in quarter two. Both of these wells are in Atascosa County.

Up at Seal in Canada, as reported in the press this week, we had a fire in a heavy oil treater at our Seal 433 battery, causing us to shut in approximately 5,000 barrels of production per day. We're working on plans to restore close to 2,000 at this time and are assessing the full extent of the damage and timing to restore the remaining shut-in production.

We have planned for an active 2013 at Seal where we will integrate the shale acquisition to our operation and continue with both primary and EUR development projects. We currently have two rigs drilling production wells and one rig drilling strat wells to support our EUR plans. However, with recent poor net back prices, we're going to reevaluate primary production investments.

Our polymer injection in Phase 1 of our commercial polymer project began last August and continues on track. We expect to start steam injection in our first cyclic steam pilot in February. We submitted an application for vertical steam drive projects scheduled to start in the second half of 2014.

We spud our second well in Northern Alberta to test the Muskwa Shale. Our initial well produced at low rates and we have moved further west in the play where we anticipate liquids-rich gas. We've drilled the well through the Muskwa core and are evaluating and now drilling the horizontal section.

As to production, the fourth quarter averaged 211,833 barrel equivalent per day, exceeding our guidance of 207,000 BOE per day, which resulted in full-year production for 2012 of 194,278 barrel equivalent a day.

During the quarter, we had an entitlement change for our shallow-water oilfields in Malaysia. However, had this entitlement change not occurred, we would have still exceeded all external guidance levels in the fourth quarter, equaling 208,363 barrel equivalent per day and a full year at a level of 193,406 barrel equivalent per day.

Quarter-four ramp-up in production is primarily attributable to additional wells at Kikeh, already production systems start up from Kakap-Gumusut, continued wrap-up of Eagle Ford Shale, a new well at Thunder Hawk, and Hibernia returning to production following planned maintenance.

Production guidance for quarter one 2013 is set at 200,000 barrel equivalent per day. Reserve replacement for the year was 184%, with a major reserve booking at Eagle Ford Shale of some 80-plus million barrels equivalent at an 86% oils. Additional reserves were booked in Malaysia at our Sarawak oil and gas developments in the Gulf of Mexico with initial bookings for Dalmatian. We now have an average of 157% reserve replacement for the last five years. The [R/P] of our business now stands at 8.4 with a total resource base of 3.5 billion barrels at 56% oil. I'll now turn the call back over to Steve.

Thanks, Roger. The US downstream business operated well in the fourth quarter with solid margins in October giving way in December to rising wholesale gasoline prices. Overall, the US downstream had fourth-quarter net income of $22 million. Volumes continued to recover as our new measures implemented in the third quarter began to show results. We added 14 new stations in the US retail chain in the fourth quarter and ended the year with 1,165 outlets as planned.

The UK downstream business recorded net income of $16.5 million for the fourth quarter. In 2013, our exploration program will include drilling close to a dozen prospects. We plan to drill one well in Block H Malaysia, one well in Block CA-2 Brunei, which is currently underway, and, pending results, likely a second location there. Two wells offshore Cameroon, two Browse Basin wells in Australia with the first well currently drilling, two to three wells in the Gulf of Mexico and a possible well in Semai-II Block of Indonesia.

Our total capital budget for 2013 is $4.3 billion, with $4.1 billion for our upstream business. In the upstream business, $500 million is earmarked for the exploration program and $3.6 billion will be spent on development projects, of which $1.5 billion is slated for the United States, mainly at the Eagle Ford Shale, and a further $1.5 billion is budgeted for Malaysia, with $500 million slated for Canada.

The downstream budget is approximately $200 million, primarily for new station builds and upgrades. We plan to add 65 to 75 retail outlets this year and the future growth plans for US retail business will be rolled out in the coming months as we move towards the spin-off transaction.

Production guidance for the full year is 200,000 barrels of oil equivalent per day, which represents a 3% increase over 2012 volumes. Production increases will primarily come from growth in the Eagle Ford Shale, which is offset by lower average production from the Montney for the year. Key projects in Malaysia are scheduled to come on-stream later in the year which will provide growth heading into 2014.

At our call in October, we indicated we'd hired an advisor to review alternatives for our Montney and Syncrude assets, along with certain other upstream assets. Syncrude and Montney are really great assets. One is a huge large-life gas resource. The other is a huge long-life oil resource. These kinds of assets are difficult to obtain and they're harder to replace. Currently they fit well into our strategy of growing our oil-rated production profile and maintaining an upside on North American gas prices, with the emerging Canadian LNG development.

That said, if we have a need to fund development of our other projects or if we were to receive a compelling offer, we would seriously consider a sale. We don't plan to have a formal process at this time. We'll continue to review our overall portfolio, including these two assets and we'll rationalize our asset base, as we think appropriate, going forward.

Now to summarize, in exploration, we drilled another successful well in [Ilum] in Block H, Malaysia, our seventh in a row there. We have a very active 2013 ahead. Development work is moving forward on our offshore Malaysian projects and our Eagle Ford Shale continues to show predictable growth. We continue to add acreage in acreage positions in Cameroon and Equatorial Guinea.

We've signed agreements to sell our UK upstream business and we expect to close on those transactions in this quarter, the first quarter. In addition, we closed our acquisition at Seal in Canada. We continue the sales process of our UK downstream business; and lastly, we are executing on our plan to spin off our downstream business later this year. Now with that, we'll open it up for questions.

Thank you.

(Operator Instructions)

Leo Mariani with RBC Capital.

Just a question here on Congo. Do you guys expect to get some production on that asset? In the first quarter, you mentioned writing it off a couple of your Blocks. I previously thought that you guys were planning on getting some sales in the first quarter. Is that still accurate?

Yes, it is, Leo. This is Roger. We're going to continue to produce the asset at this time. We have a long-term lease obligation there and while we did impair the book value, et cetera, we are going to continue to operate and probably will do so on through this year.

All right. I think you guys incurred a decent chunk of costs in the fourth quarter in the Congo. Do you expect to continue to see significant costs there? I think maybe you guys are trying to do some workovers to boost that production. Any color you had around that would be helpful.

That workover was unsuccessful and I see very little spend in Congo going forward outside of normal OpEx at this time.

Okay. Just looking at your LOE, your lease operating expenses, it looks like to me that it came down pretty significantly in the US in the fourth quarter versus the prior quarter. Just any color you had around what was driving that and how we should expect that to behave in 2013?

well, we rolled that all into one US -- Leo, this is Roger, again. Our Thunder Hawk had a very nice well come on in the third quarter and that's a leased FPSO facility. Also we continue to improve in the Eagle Ford Shale as we build up production and production more in four-well pads allowing us to accumulate more facilities there and lower our OpEx. So yes, our OpEx is trending down, led by those two.

All right. That's helpful. In terms of your overall production guidance, you guys are saying about 200,000 in the first quarter, you guided about 211,000 in the fourth quarter. Then, you talked about getting some sales volumes out of Congo. Can you just help us out with what the other moving parts to get from 211,000 and 200,000?

When you said 211,000, you mean 211,000 in the fourth quarter down to where we are now? Is that what you're talking about?

Yes. 211,000 the fourth quarter down to 200,000 or so in the first quarter (multiple speakers) trying to bridge that gap.

We have 4,300 coming down from West Patricia, as I mentioned in my remarks. The SK Oil entitlement change, that's a reduction in pay per barrel, I suppose, primarily. SK Gas had a seven-day shut-in of almost 2,900 equivalent to install the compression as I mentioned. We sell in the UK about 2,800.

We then have the Tupper area continues to decline around 1,600. Then Syncrude has not been operating that well, about 800 down from the other quarter. Then we have some builds going the other way with the Kakap well on for the full quarter, Terra Nova about the same, and Eagle Ford adding to that other quarter and that marches you back in that range of where we are.

All right. Thanks. That was helpful.

We had -- I forgot to mention, Leo, we -- of course, I had it in my remarks, but we had that fire at Seal that we just had to rush to add to the last variance before we went out.

Roger Read with Wells Fargo.

A quick question. As I look at the performance here in the fourth quarter from strictly from an earnings standpoint. Then I look at both the production guidance for the first quarter in the earnings guidance, is there another charge out there we're expecting to see in the first quarter? If not, what else is it that's occurring on the cost side that's affecting the bottom line so much?

Roger, it's Barry here. Let me -- why don't I walk you through and get you from Q4 to Q1. It might help you see a little bit there. So let's -- if we -- when you normalize Q4, you're in that $1.50 a share range for Q4 and we've come out with guidance here in the $0.55 to $0.90 range. So let's just walk through some of the moving parts. Corporate costs, as we've said before, in the fourth quarter were $21 million. We're showing $52 million here in the first quarter, so that's $0.16 a share right there.

Higher Forex expenses, higher interest expenses, and higher G&A expenses in that corporate number for Q1. If we go to the downstream, when you normalize it, and bring back in the Hereford impairment, you're moving from about a $78 million a quarter to a $10 million loss, you've got a change there of $88 million. That's $0.46 a share and that's all driven by Q1 lower margins in our US retail as well as lower margins projected in our UK downstream business.

Then we get back to the upstream piece when you normalize it and bring back in the Congo impairment and then those tax benefits we talked about. That was roughly $1.22 a share quarter in Q4. We're showing about $0.86 of our Q1 as being attributed to the upstream here. US is pretty flat from Q4 to Q1. You've got growing Eagle Ford volumes offset by some G&G and OpEx expenses that are offsetting that.

Canada, you're down quite a bit. You're down about $35 million, $36 million in Canada. You've got some higher costs at Syncrude. We've got some -- we've got lower volumes for both Seal and Montney Gas and lower prices for gas and heavy oil in Canada as well as we have the well we're drilling at Muskwa in that Canadian number. So that's down about $36 million from Q4 to Q1.

Then the other big one is Malaysia. We're showing oil sales in Q4 were significantly higher than oil sales projected here in Q1 on lifting. So we're down about 1.2 million barrels of oil sales from Q4 to Q1, offset obviously by the OpEx you're not going to show against those barrels, till you lift them. So those are the big ones. Then I would say the Congo and our other foreign offset each other.

Congo will have less in Q4. In Q4 we had the Opale Marine and the Titane wells that we had to take. We won't have those repeat but on the foreign side, we have a drilling program going with Australia, Brunei, and Cameroon as well as higher G&G costs. So those offset. All that E&P stuff is about another $0.38 a share. So those are the moving parts that bridge the $1.50 back down to our $0.55 range.

Okay. So it sounds, if I interpret that correctly, the cash impact in the fourth quarter was less so because you had mostly a charge, whereas we're looking at the first quarter, most of this is either production that's not going to occur, the liftings, or it's actually higher costs. So we are talking a less free cash flow availability, or less free cash flow generation in Q1 than we had in Q4?

That's fair.

Okay. The other question I had, can you walk us through what's going on on the exploration side during 2013, just what we should be looking for in other wells that you'll be drilling on that front?

Yes, Roger. Great name there, by the way. (laughter) Steve walked through some of this so I'll go through another little bit of detail. In Block H, on a nice run there and we're going to drill a well there sometime this year. These wells are very inexpensive to drill and we can come in and out of our development plans there and do them as we need to. So we probably have a Block H continuation well in the third quarter. We're drilling a well now in Brunei with the same type of a gas play, same type of size or source as we have in Block H. We'll more than likely have a follow-on well there around mid-year.

The Elombo Block that I mentioned earlier is something we've worked on for a long time. It has a shallow-water well to be drilled here real soon and then a well of a Cretaceous span, a pretty big 200-million barrel plus prospect to be drilled at mid-year. We would drill a very large 700 million barrel type gross prospect right at year-end and we'll spud that well. We have the ongoing program in Australia where we drilled a very large gas projects there, one called Bassett West, one called Dufresne. We just started the Bassett West well and set surface casing and we'll be drilling there almost continually to the -- through mid-year.

We have possibly 2 wells to drill in Indonesia for a continuation of our commitments there. We're waiting on a jack-up rig from BP there. We'll get back to drilling in the Gulf of Mexico where we're bringing in our own deepwater rig. We will first complete our Dalmatian development wells and do some exploration work there at two of our prospects. We have a good many to choose from. But we'll be getting being back to work in the Gulf in the second half of the year. That would pretty much wrap up a 10 to 11, 12 well kind of program, which is where we want to be.

Okay. So the 2 Gulf of Mexico wells that you may drill, those have not been identified yet?

I have them here but I'm not identifying them yet. So, yes, I have many options there and partners and things I'm working on at this time, but there will be an oil amplitude well to drill and a north foot well to drill for sure in that two to three pocket.

Blake Fernandez with Howard Weil.

Roger, while we're on that exploration, I just want to make sure and clarify. When you said you relinquished the Congo MPN and MPS, is it fair to say that the pre-sold exploration well is no longer on the books?

Well, when we drilled our MPN well, we announced that well as dry sometime back as when we had our debt offering. It -- we actually penetrated and went ahead and drilled ahead into the sub-salt, didn't see good reservoir there. It's been a long run of poor success in Congo for me, Blake, and it's time to move on. We're letting those Blocks go.

Understood, okay. Then, Roger, while I have you, if -- you talked about moving down to 80 acres in the Eagle Ford. I know some of your peers are testing below that. Are you at a position where you're ready to start running pilots on below 80-acre or are you just going to wait and see what industry has to offer and then move from there?

Well, I think I said we have 160-something wells produced today. 40 of them are downspaced to 80 already and we have about 13 months of history on our 80, it would be the longest we've had. We've seen no interference and good -- and any problem with it. We'll probably, with the way my rigs are shaking out and the way my land is shaped, I may have some 40-acre downspacing later in the year, not promising to have results on this year but I'm sure all my good friends around me will have plenty of data to talk about.

Right. Kevin, if you don't mind, could you give us an update of where you guys stand with regard to the buyback status?

Yes. We ended the accelerated share repurchase back in, I guess it was mid-December, 250 million. Now we had -- and as a cap to that. We had a little over 3.8 million shares that were delivered to us. The counterparty that we entered in today I saw it with is currently buying back that position in the market. We had set a timeframe of two to five months to complete that.

So depending on what price is ultimately achieved, we could get an upward adjustment. It wouldn't be more than another couple hundred thousand shares, but we could get an upward adjustment to the shares we received. Now that 3.8 million-plus shares that we've gotten back have been taken out of the share count as of the end of the year and removed from --the 250 million was removed from equity. We'll just make the other adjustment when the program is completed.

Got it, okay. The final one I have for you, Steve, if you don't mind. I know you addressed Syncrude and Montney. I was just trying to help to clarify, is it fair to characterize this as a situation where you hired a consultant, you marketed the assets, and at this point, that process is over, and now it's like Montney and Syncrude are similar to everything else in the portfolio? That at the right price, you're a willing seller, but basically we've finalized that process? Is that a fair characterization?

I think so, only we didn't solicit offers or anything. We went out and tested the market from an inquiry standpoint but yes, that process is over. The conclusion we come to is, these assets fit nicely in our portfolio for now, but again, as we said, having said that, if we need more cash, for the Eagle Ford Shale and other projects, developments and that thing, we'll look at asset rationalizations. Syncrude and Montney could be part of that rationalization process, but for the time being, we're not going to —have a formal process or anything.

Okay. If I could just risk maybe asking, is it fair to say your interaction with Third Point has been finalized or are you still interacting with them?

Well, they're shareholders, just like a lot of your clients are, so no, I guess we're not finished interacting with them as long as they're shareholders.

Paul Cheng with Barclays.

Several quick questions. Roger, I think -- or maybe it's for Kevin, I think in your press release you're saying that you have a higher working interest in Thunder Hawk and Frontrunner? Can you tell us that what's the current work interest and then what's the production and earning contribution in the fourth quarter because of that higher interest?

We announced last year that we bought out our partner Statoil in the Gulf, Paul, and we are now 62.5% at both Frontrunner and Thunder Hawk.

Yes, Frontrunner, I think Statoil, you originally stated 37%.

Yes, yes, that would be right. Now we're 62.5% at both and if you look at what we made in the fourth quarter, we're at -- I don't have the earnings income of an individual field, but as I look at the Gulf of Mexico, Thunder Hawk net, fourth quarter, we made [$64.95 oil] and 5 million a day gas, BOE 7.3 -- 7,300 a day.

And that's Thunder Hawk.

Thunder Hawk. Yes, sir.

How about Frontrunner?

Frontrunner, we've been delayed in putting a new well on. It's been fairly stable for a long time. The well should be on today probably, but in the fourth quarter, we made oil there [$44.79] net oil and 3.2 million a day gas for a BOE of around a little over 5,000 a day.

By the way, Roger, are those numbers net to year or just gross?

That's net to me, Paul.

So that means that since that -- you essentially doubled your working interest. So that means in the fourth quarter, the higher work interesting have contributed roughly about 6,000-barrel per day for you?

Not really. Well, we all -- if you go back from third quarter to fourth quarter, we bought it back in June. So --

Okay.

I could -- there is some attributable to that, sure, but I don't believe that my success at making the quarter was due to buying out Statoil. I can tell you that. It's too much sweat to get it besides that. It wasn't by the pen.

Okay. Fair enough. On Eagle Ford, Roger, can you tell us what is the current unit operating cost, cash cost?

John, can you help me with that? Let me get Eckart here to give you exactly what it is, Paul, if you don't mind.

12 months ended December, Paul, the Eagle Ford Shale OpEx was right around $23.

How much?

$23 for the --

$23. Do you have a fourth quarter number?

I'm sorry?

Do you have a fourth quarter number?

Fourth quarter number was -- I got it right here -- $18.28.

(multiple speakers) I assume that we should continue to see that trending down, right?

Yes. We hope to. We probably have -- probably be end of '14 before we make an enormous improvement below that, but our goal is to get that into $13, $14 range, as soon as --

So long-term that you are targeting $13, $14.

That's right.

Do you think, Roger, that you can get there by the end of this year or sometime next year?

I think a year from now, yes.

And the well costs right now, is it still about $8 million or that has changed?

We've been doing really well on that, Paul. If you look at Karnes, where we've set some pacesetter wells, like I said, around 13 days drilling case, which would be equal to any of the other players nearby. We probably lowered our budget costs from $7.9 million to $7.2 million total in Karnes, Tilden, where we're a heavy driller, Tilden there, if you looked in our slide decks, we're drilling those wells now in 11 days. We're drilling them now and completing for $6.7 million in lieu of $7.7 million previously. Over at Catarina, which the Eagle Ford Shale is shallower, they're around 8 days and we're costing those wells with fracs at 5 -- a little over $5 million and we used to think that would be $6 million. So a real good situation That has proven for us there.

What's your -- are you now trucking all the oil out or are you actually using a more effective means to get the oil out?

Well, what I think that's happened there if you look at the end of the year, we'll still be 75% trucking. We're about 86% trucking today. We -- but what's changed in the Eagle Ford Shale is a series of truck depots across the play. It used to be a lot of long-term mileage and backups and issues around the trucking. We very rarely have a trucking problem today and it's -- we're talking less than 20 miles instead of 80 miles.

There's many places to unload the trucks, many depots, many options. We're doing very well with our crude. Murphy's land situation is not a condensate one. We're a black oil, 41-, 42-degree API. We've been getting a $13 positive margin at WTI there for some time. People want our crude in that area. We're doing very well with the marketing and the quality of crude because we have very little condensate in our business.

Should we assume that, at this point, your production has not been curtailed because of transportation issues, so you've been able to produce whatever that you could?

During the holidays, some of these truck drivers don't come to work. (laughter) We'll end up losing about 500-barrel a day, in top-of-tank type issues. Corpus Christi area is becoming more just in time with barges. There are some crude being barged out of here. So on occasion, you'd get a tank-top issue and as you do in an FPSO and other things we have in our business, but we're talking 500-, 700-barrel a day curtailment for two or three days, we're making (multiple speakers). I think it's far, far better than it was a 1.5 year ago.

Okay. I have two final questions. One, do you have a F&D cost for 2012?

Yes. It's probably going to be around $30, Paul. We spent a lot of money and we booked a good many reserves, but our three-year average on that's probably about $27, but if you look at the F&D in our Eagle Ford we're pretty proud of that around $14. So, that -- you can take out CapEx and divide into our barrels that we just announced so that's that number, around $30 (multiple speakers) -- it's not too bad.

Sure. Final one then on Congo, if we look back in hindsight, is there anything that you may have learned now that will have changed the way how the project was originally being interpreted or analyzed or that being developed, what we may have learned?

Well, everything in life, when you have a mistake, you learn from it, Paul, of course. I've been around. It's my 30th year. It's the only impairment I ever worked on. I don't think this is something happens very often. I'd say, looking back, in general, a couple of things. It was a small project and any time you go to develop 70 million barrels where you have no infrastructure, you have to be careful.

I would characterize it as how you delineate more aggressively early on. Then also, we went to some one-off equipment that worked and we got it in the field on time and on budget but some of that one-off equipment led to difficulties in performing the workover that we needed. As you know, in Kikeh, we are able to work on wells easier because the wells are set up differently are and more uniform to industry. So those factors, I suppose, but this is something quite rare and I don't anticipate it happening very often. (multiple speakers) -- you'll have it.

Sure. Have you, that subsequently, though, have you instituted any changes in the way how your team, the process have worked or that you think that this is a -- somewhat of a obscure situation and so correspondingly, you don't have to change your process?

No. I would say we always are changing our process. We do a lot of business with Petronas, which has a very rigid, five-step gate approval process. We have to do so much business there that we put our business in that way. We have a formal review of resources now that's probably much more rigor than it was in those days. So, of course, there are always improvements in sanctioning. The projects are very expensive and I'm certain now that the lessons have been learned and the processes are in place to prevent it again.

Pavel Molchanov with Raymond James.

On the UK assets, obviously it's a tough market to sell anything refining related in Europe. At what point, would you just say -- you know what? Let's just shut it down or convert it into a terminal?

Good question. I think we got pretty close to that decision probably a year ago, but the UK operation started -- it didn't become a drag on earnings. It didn't become a drag on cash flow, so we deferred that. Now it's a good question, but I really can't answer it right now. I think for now, we're engaging different parties and we are hopeful, remain hopeful that we'll be able to conclude something in the near future, but we're not there yet.

Okay. Then once you presumably sell the UK and spin-off US downstream, have you done the math on what would be the cash savings on your income tax based on the different treatment of independents versus integrated companies under the US tax code?

Well, it will be 100% in the US because I'll operate at a net operating loss as long as they allow IDCs to be deductible as they currently are. My issue will be, and we've talked about it several times on these calls, and a lot of one-on-ones, biggest issue I'll have will be tax efficiently moving money around the world because of that potential net operating loss position in the US that will be driven by the intangible drilling costs [deductions].

Okay. But any sense of, in dollar terms, what the savings might be? For example, in last year, had you been treated as an independent, what would it have been?

Well, I don't have those particular numbers. I could tell you for 2012, we're going to have a big net operating loss to the tune of $500 million that we're going to carry back to prior years where we had a lot of taxable income. Now a lot of the taxable income, say, in 2011 was driven by the sale of the refineries. Then I've had taxable income driven by the downstream, but when the retail gets spun off, a large portion of both my US cash flow and taxable income goes away. I won't have taxable income in the US as long as they keep IDC deductions, I won't have taxable income in the US for some time.

Guy Baber with Simmons & Company.

You guys added to your exposure at Seal during the quarter, but Roger, you also mentioned the poor netbacks you were seeing in your prepared remarks. I was just hoping you could discuss your outlook for heavy Canadian oil differentials, how they could impact the way you allocate capital there? Are there any initiatives to really improve those realizations in light of what could be a pretty challenging price environment over the next couple of years?

Yes, our marketing folks, and we believe it, will show some improvement in the second half with this [lighting] refinery, Detroit refinery and certain Enbridge improvements. The Enbridge thing has come quite a surprise to the industry. We'll only need our netbacks in the 50s here to have the rate of return that we need. Of course, it's much below that now. We are working on many initiatives on rail. I think rail will be attractive there. I know of -- we're working at some items we'll have to do to change our -- the way we treat the crude in order to get it rail-ready. We're working on that a good bit.

I'd say off the top of my head right now -- I'm fairly close on this couple hundred million of drilling, probably $100 million on the conventional old-fashioned horizontal drilling. We can move that to Eagle Ford quite easily because our Eagle Ford's drilling so fast, we're in that with 40-something wells parked there today, more than we've ever had. So we have that flexibility to organize with one onshore North American team. That won't be difficult to do, but we have to be careful pulling back on the EOR. The prize here is the EOR. I do believe the refiners in the United States still will want heavy.

There will be a market for heavy. There is enormous business for heavy. There is a long-term enormous pipeline expansion for heavy. So we're going to stay -- we've got to be careful not to -- one of the problems in Seal in the past is being able to pull back the capital and move it to somewhere else. Now, of course, we have a very lucrative Eagle Ford to move it into but we have to be careful with that on the strat side, the steam side. But I think we can move some capital on the conventional, and are looking to do so and planning to get the work done in the next couple months.

Okay. Very helpful. Then my follow-up is, you all are forecasting downstream losses during 1Q. So can you just speak to expected US retail performance? I know early last year, you all talked about volume and margin underperformance there relative to peers, but you've since identified some initiatives to improve performance and have been encouraged. So I was just looking for any update there just with respect to how those initiatives might be progressing?

Guy, it's Barry here. Yes, Q1, of course, is typically a shoulder season for that business and always difficult. It has been in the past. We talked about these initiatives we had. I think we saw some nice results of volume recovery, balanced with margins and showed a pretty good fourth quarter as a result of those initiatives. I think this year, we're just anticipating that moving along but the normal seasonal trends holding true as well as part of that business. So I think we anticipate obviously coming out of it in Q2 and through the summer with the usual strong seasonal results.

Stephen Simko with Morningstar Equity Research.

My question is just to -- it's just on your exploration program and looking at the results over, maybe the last couple years, they haven't been -- they've been mixed. You guys have spoken to that in the past, but looking at your 2013 drilling plans, I don't personally identify any major changes in strategy. I'm just wondering are you guys looking at your -- at exploration at all in terms of spending levels or just even in any ways how you approach it, day to day operationally in terms of possibly changing it in the future? Or are you pretty content and feel that you're on a good spot as you are?

No, I think we've made a good many changes in the rigor of the decision-making we've put forth, the work that we make commitment wells on, definitely made a change in that. We just happen to -- we have had pockets of success in Block H, Malaysia. Seven in a row means that you can analyze seismic and find and drill wells successfully. We have that ability. We are involved in the Western Australia offshore that has a very high success rate and glad to get into that at ground floor basis.

we've been working a long time on the Atlantic margin with the Cretaceous Sand play, which is a new play for us. We've established a very nice position in Cameroon, in two Blocks that have been sought after and had competition by others. We had just added a Block in G along that same margin, that steep margin where the Cretaceous Sand plays exists. I think another difference for us at Murphy is we're getting back to work in the Gulf of Mexico, a place we had -- due to Macondo, we didn't work for awhile, a place we focused on less. If you look back at our history over a 10-year period, we're a top quartile exploration Company.

A Company of our size only takes one significant exploration hit to be needle moving. We believe we're an exploration first Company and are using our very strong North American onshore business to be complementary to our exploration program. I believe that sets us up unique. I do believe we've improved the rigor and the work. I'm happy with the way we're doing it and I'm glad to get back in the Gulf. I'm glad for the new acreage that we have and I do see it to be different. I do see it to be better in the future.

Very helpful. then a real quick follow-up is, does what's happening on the ground in Australia right now change your opinion of how much capital you want to put there going forward? Or is that to you just possibly a short-term issue that really doesn't affect with how you're going to be thinking about your long-term (multiple speakers) --

I really have a strong -- We've been very successful in Malaysia, selling a small volume of gas to Petronas for a long time. We're actively involved with Petronas on Floating LNG. I believe Petronas to be the leader in gas, total value-chain LNG in the world. so when they're interested in building two Floating LNG I think Floating LNG will become the way forward away from the super-large, onshore, multi-Tcf projects and the 5 Tcf project with the Floating LNG may end up being better than the larger Tcf on land.

I think the execution may end up being easier. I just have a feeling that Floating LNG in that part of the world is going to be successful. That's the reason I'm in West Australia now. That's the difference in the play that I see is the emergence of Floating LNG. We are hearing of a good bit of Floating LNG work in Australia today due to the CapEx, the timing, and the stakeholders and increased time to gain those approvals on the big onshore plants. That's my view of it.

Ladies and gentlemen, in the interest of time, we have time for one more question. Ray Deacon with Brean Capital.

I had a question about reserve replacement. What -- if -- have you broken down the sources of reserve adds?

Well, in many, many fields. We start off in year in 11 and make the changes, subtract the production. If you look at the changes this year -- is that what you're looking at? Some color on some of the --

Yes. Just largest sources of reserve adds. It sounds like Eagle Ford was --

Eagle Ford Shale is around 87 million barrels. These are all around BOE, Ray. But it's around 86% oil for us, Dalmatian around 9 million barrels. In our Sarawak gas projects, which we continue to add reserves there, probably around 11 million BOE and SK Oil that will be flowing later this year and after we have those sanctions, around 10 million barrels there. And then at West Pat, which is a project we've had for a long time and a really super performing project, around 4 million barrels. Those are some of the bigger ones; the rest are in the 1 to 2 million range, numbers to that effect, Ray.

Okay, got it. Great. The well that you're going to drill at Dalmatian mid-year, is that -- that would add new reserves or is that a --

Yes. How -- when you initially book it to sanction, we don't book all of the -- we're probably not even halfway there. So we have some -- when you drill these Gulf of Mexico wells and tie them back, we'll be completing the original discovery wells; that's what makes it so economic and so robust. So we have not drilled the exact water level. We have not fully given yet but these wells are flowing to another facility, do not have the infrastructure to build out as in a Congo example. So a long way to go in the booking, probably not even halfway at Dalmatian.

Okay. Got it. Just one more quick follow-up. In Australia, would you -- how does the risk profile of the two remaining wells compared to what you've done so far? Is it the same kind of geology and traps you're going to be drilling there?

No. This will be totally different. We drilled a stratigraphic trap early on in this AC/P 36 Block. These are large four-way Plover closures. We had this on our Block all along, it was deeper. The Conoco Poseidon discovery nearby opened this up from a reservoir ability perspective because they're deeper than we are and that opened up the play.

There's been several discoveries in a row. The four-way closure Plover in this area is over 50% chance of success and the real risk is volcanics bleeding into the reservoir section in lieu of charge or Seal. So we see it to be a very prospective place, and once it was derisked by the Conoco discovery, it opened up a nice place to drill, in my view.

That does conclude our question-and-answer session for today.

Well, thanks everyone for participating in our call. Have a good day.

That does conclude today's conference. We thank you for your participation.