Murphy Oil Corp (MUR) 2013 Q4 法說會逐字稿

Good afternoon, ladies and gentlemen, and welcome to the Murphy Oil Corporation fourth-quarter 2013 earnings conference call. Today's conference is being recorded.

I would now like to turn the call over to Mr. Roger Jenkins, President and Chief Executive Officer. Please go ahead, sir.

Thank you, operator, and good afternoon, everyone. Thank you for joining us on our call today. With me as usual is Kevin Fitzgerald, Executive Vice President and Chief Financial Officer; John Eckart, our Senior Vice President and Controller; and Barry Jeffery, Vice President of Investor Relations here at Murphy and will now make his customary comment.

Thanks, Roger, and welcome, everyone. Today's call will follow our usual format. Kevin will begin by providing a review of fourth-quarter 2013 results. Roger will then follow up with an operational update, after which questions will be taken.

Please keep in mind that some of the comments made during this call will (technical difficulty) that are 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 2012 annual report on Form 10-K filed 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. Beginning in the fourth quarter of 2013, our UK refining and marketing operations are presented as discontinued operations. So for the full year of 2013, discontinued operations include our UK E&P properties which were sold earlier in the year; our US retail and related operations that was spun off to shareholders at the end of August; and all of the UK downstream operations.

Net income from continuing operations, which is basically our remaining E&P properties, for the fourth quarter of 2013 as $180.5 million, or $0.96 per diluted share. This compares to net income from continuing ops in the fourth quarter of 2012 of $123.9 million, or $0.64 per diluted share.

For the full year of 2013, net income from continuing ops was $888.1 million, or $4.69 per diluted share, compared to net income from continuing ops in 2012 of $806.5 million, or $4.14 per diluted share.

The fourth-quarter and full-year results from continuing operations for 2013 included $133.5 million of income tax benefit related to foreign oil and gas investments, compared to $108.3 million of such benefits for the fourth quarter and full year of 2012. Fourth-quarter and full-year results from continuing operations for 2013 also included charges of $82.5 million associated with abandonment and exit activities at the Azurite Field in Republic of the Congo, while the 2012 fourth-quarter and full-year numbers included impairment charges of $200 million associated with the write-down of the carrying value of Azurite. There was no income tax effect related to these charges for either year.

Looking at total net income for the fourth quarter of 2013, it was $75.4 million or $0.40 per diluted share, compared to net income in the fourth quarter of 2012 of $158.7 million or $0.82 per diluted share. Net income for the entire year 2013 was $1,423.5 billion or $5.94 per diluted share, compared to total net income in 2012 of $970.9 million or $4.99 per diluted share.

Net income for the fourth quarter of 2013 included a loss from discontinued operations of $105.1 million or $0.56 per diluted share, compared to income of $34.8 million, $0.18 per diluted share, for the 2012 quarter. The 2013 quarter included an impairment charge of $73 million for the UK downstream business with no tax effect, while the 2012 quarter included a $25.7 million after-tax impairment charge related to an ethanol plant.

Looking at net income by segment, in the E&P segment, net income from continuing operations in the fourth quarter of 2013 was $242.5 million, compared to $145 million last year. The higher earnings in the 2013 quarter were primarily attributable to lower costs related to the Azurite Field and higher recognized tax benefits, as previously mentioned.

The fourth-quarter 2013 also included higher crude oil sales volumes, but this was mostly offset by lower realized prices for crude oil and higher extraction expenses. Crude oil and gas liquids production averaged just under 140,000 barrels a day in the 2013 quarter, compared to about 133,000 barrels per day in 2012. This increase was primarily a result of ongoing drilling in the Eagle Ford Shale and higher heavy oil production in Western Canada attributable to properties acquired in late 2012.

Natural gas volumes were 399 million cubic feet a day in the 2013 quarter, compared to 473 million cubic feet a day in 2012, with the decrease primarily due to lower production from the Tupper area in Western Canada and at Kikeh in Malaysia.

In the Corporate segment, the fourth quarter of 2013 had a net charge of $62 million, compared to a net charge in the fourth quarter of last year of $21.1 million. Increased cost in the current year mostly related to higher interest at administrative costs and lower income tax benefits, partially offset by favorable results from transactions denominated in foreign currencies.

During the fourth quarter of 2013 we entered our third $250 million accelerated stock repurchase program and received almost 3.7 million of our shares. That program was completed in mid-January of 2014, at which time we received an additional 284,000 shares.

To date we have completed $750 million of our Board authorized $1 billion program, which expires on April 15 of this year, repurchasing a little over 12 million shares at an average price of approximately $52.46 per share.

Capital expenditures for continuing operations for 2013 totaled just under $4 billion. For 2014, our budgeted capital expenditures, which were approved by our Board in early December, total $3.8 billion. Of that, approximately $3.2 billion is for development projects and the remainder, approximately $600 million, is to be spent on exploration activities.

Our budget assumes WTI pricing of $90 per barrel and Henry Hub pricing of $4 per Mcf.

At year-end 2013, Murphy's long-term debt amounted to approximately $2.94 billion. This includes approximately $340 million related to the Kakap FPSO lease. This adds up to 26.5% of total capital employed, while cash, cash equivalents, and short-term investments and marketable securities totaled a little over $1.4 billion, including about $300 million that is included in current assets held-for-sale on the balance sheet.

With that, I will turn it over to Roger.

Thank you, Kevin. 2013 was a good year for our shareholders here. The spinoff of Murphy USA was completed in the third quarter and was a seamless transition for the two entities. We have made good progress on our $1 billion share repurchase program, which has slowed a bit due to the timing of the spin, with $750 million now completed, as Kevin mentioned.

We exceeded production targets for the year, even when adjusting for the delay in the Kikeh shut-in, our field development work, downtime at the non-operated Kikeh associated gas plant, and weather delays in Eagle Ford Shale. Our strategy of building a reliable, predictable, onshore business that complements our offshore business has greatly improved our ability to meet quarterly and yearly goals.

2013 represented our highest production level in our Company's history, breaking the 200,000 barrel of oil equivalent per day mark. We had our best year ever in reserve replacement, at over 240% on an organic basis.

We set the stage for 2014 production growth, the startup of four shallow-water oilfield developments, in Sarawak, Malaysia. And we are progressing startup on two deepwater fields there as well, and one in the Gulf of Mexico. We also restructured our exploration business under a new leadership team to position ourselves for future success.

From a financial perspective, 2013 was the second-most-profitable year ever for upstream operations, with only the high oil price year of 2008 taking precedence. We continue to progress our UK downstream sale effort; we have reported this business as a discontinued op, as Kevin mentioned in his remarks.

This will also allow our shareholders to view our E&P business as a whole for 2014 and take a look at our 2013 business as an E&P entity.

In the fourth quarter, as to prices in major fields, Malaysia oil netbacks remained strong, edging up slightly with realized prices for Block K averaging $95 per barrel, and $104 per barrel for Sarawak oil, post all supplemental payments despite a slight drop in Brent quarter on quarter. Our oil indexed SK gas averaged approximately $6.25 per Mcf.

And our realized oil prices in North America fell on quarter as major benchmarks WTI and LLS fell. The Eagle Ford shale and Golf of Mexico both averaged close to $90 per barrel, which includes the effects of approximately 4,000 barrels per day of NGLs, which pulled down our realized US liquids price by close to $4.75 per barrel. We do not at this time break out US NGL volumes or price in our statement.

Offshore, East Coast Canada we had a strong Brent-supported price of just under $110 per barrel.

In exploration, first in Southeast Asia, in the Brunei CA-2 Block, where we're a 30% working interest, the partnership group has opened up a new gas play with three discoveries. We successfully followed up Kelidang discovery in 2013 with two more gas discoveries, Keratau and Kempas, at the end of the year.

All of the discoveries are excellent quality Pliocene sandstone reservoirs around 800 meters below seabed and in close to 2,000 meters of water. We now see a potential resource site here of up to 2 Tcf gross, with additional prospects to drill. We will be evaluating a variety of development options with our partners.

In Vietnam, the 3D seismic program on our operated 11-2 Block is complete and the data is being interpreted to identify possible drilling locations early next year. We are preparing to drill the Block 13-03 exploration well later this year, a 20% working interest with our partner Santos, who is operating.

The 2D seismic program in deepwater Blocks 144 and 145 is scheduled in quarter 2 to 3 of this year.

We will be spudding our two remaining commitment wells in the Semai II Block in Indonesia in March.

In the Gulf of Mexico, the recently drilled non-operated Madagascar well was plugged and abandoned as a dry hole after testing the southern extent of the Norphlet Play. We are preparing to drill our operated Norphlet prospect Titan at 50% working interest, which is expected to spud in early March. The pre-drill gross mean resource estimate for the well remains 200 million barrel of oil equivalent. The Titan well is located in the northernmost portion of the play fairway, is in close proximity to other successful Norphlet wells.

In the Atlantic Margin, our Ntem Block offshore Cameroon, we expect to spud the Bamboo-1 well in February. The well is testing Cretaceous-age stacked fans with a pre-drill gross mean resource estimate in the range of 600 million barrels.

Offshore Equatorial Guinea in Block W, we have completed acquisition of our 3D seismic with our partners. In Australia, the Dufresne-1 well in the Browse Basin was plugged and abandoned as a dry hole after failing to find reservoir.

We have begun our evaluation of the Perth Basin in 3D which was acquired in 2013. We will be preparing to start our exploration drilling program here in late 2014, early 2015.

In our Block EPP 43 in the [Saduna] Basin offshore Southern Australia we are planning to acquire 3D seismic toward the end of 2014 and into 2015, and expect wells to be drilled in adjacent blocks starting in 2015, to test similar plays by other operators. This is a six-year permit with commitment for 2D and 3D seismic only.

As to global offshore operations, in shallow-water Malaysia execution on all four of our new oil developments at Serendah, South Acis, Patricia, and Permas went very well and all are producing above plan. Patricia and Permas were the last two fields to start up, and they came on in the fourth quarter, with first oil in November and December, respectively. We will continue drilling in these fields over the year as part of the overall field development plan.

As previously announced, we experienced a fire on January 5 in the hull of a tender-assisted drilling barge called the [SKP-Munane], which is moored adjacent to the Kikeh production spar. We shut in production from the spar as a safety precaution, while the subsea wells continued to produce directly to our FPSO.

The spar wells were down for approximately two days, and the wells were then returned to production. The tender-assisted drilling barge was removed from the spar and has been towed to a shipyard in Singapore for repairs. While the rig inspection to assess the overall damage and extent of the repairs is in early days, we project that the rig will be back in operation in April.

Our deepwater products projects are continuing to progress towards startup of the Siakap North/Petai field, which has been delayed due to operational and weather delays. As we reported, the planned shut-in of the Kikeh FPSO to execute these tie-ins of the Siakap North/Petai risers was deferred from late in the fourth quarter to the first quarter of this year.

The shut-in and tie-in work is currently ongoing. The Kikeh field shutdown started on January 23, and we expect to be completed and bringing Kikeh back on line the second week of February. Two production risers are now installed to the Kikeh FPSO and work has started on the third and final line, which will be used for water injection.

We are moving forward with the final hookup and commissioning work on the facility. We will then commission the startup of Siakap North/Petai field, with first production planned at the end of February, with four subsea oil producers online. The Siakap North/Petai development plan consists of eight producers and five water injectors in total. Drilling to date indicates that the subsurface results are exceeding expectation.

The Kakap went through early production systems producing plans at the Murphy-operated Kikeh FPSO. The non-operated larger full-field development is going through the final stages of commissioning with indications of startup in the second quarter.

Sarawak gas production continues to be a steady contributor for us, with production averaging in the year 167 million cubic feet per day net in quarter 4.

The Block H Malaysia floating LNG project with our partner at PETRONAS is now fully sanctioned by both parties and the oil-linked gas terms agreed. This is a major milestone for both companies. We feel fortunate to be part of one of the three first floating LNG projects in the world and to monetize gas from a very successful exploration drilling program in the block taking place over the last seven years.

The project will be a phased development centered around the Rotan discovery and gas sources from three satellite fields. We are planning on first gas in 2018 with 10-year peak gas rate near 207 million a day gross, or 150 million per day net.

In the Gulf of Mexico the Transocean Discoverer Deep Seas is on-site at Dalmatian, with the first well of two now fully completed. Our pipeline contractor will be in the field soon to perform the subsea pipeline tieback work for Chevron Petronius Hub, with first production slated for later this quarter.

North America onshore in the Eagle Ford Shale went in the quarter with a new production record of 51,127 barrel of oil equivalent per day on December 23. We are currently running eight rigs and three frac units across the play with now 340 wells producing.

Production averaged 41,900 barrel of oil per day in quarter 4, with liquids weighting in at 92%. This was down from quarter 3 due to severe weather impacts, offset well shut-ins for fracking, and fewer new third-quarter wells coming online to contribute to the fourth quarter.

In quarter 4 we placed 46 new operated wells online, which will get us back on track for production growth in the first quarter of this year. Our total annual production in the Eagle Ford Shale averaged just over 39,000 barrel oil equivalent per day, 91% liquids in 2013, which is up from approximately 15,500 barrel of oil equivalent per day in 2012 with an additional 174 operated wells online.

Drilling and completion performance continues to improve, with the average drilling cost improving another 9% through 2013. We have reduced drilling and completion cost by a total of 40% since the start of the development in 2011.

Downspacing in the Eagle Ford Shale continues to show excellent results. Our downspacing project in Karnes and Tilden areas continue to show the wells are performing comparable to neighboring wells.

We are now downspaced and it's part of our field development going forward. We have 112 downspace wells below 80-acre spacing producing in this play. Our well optimization work continues to progress, with longer laterals and well [orientation] through [spec] to minimum regional stress direction in order to optimize frac results and improve overall EOR per well.

We continue to evaluate the potential in Pearsall Shales and the Buda Lime. To date we have drilled four wells in the Pearsall, two vertical, two horizontal; one horizontal well planned this year. We are targeting this well in a key part of the play fairway, and we're hopeful the results trigger a future development.

In the Buda Lime line play we have two wells planned in 2014 to test the zone. And additional resource potential here could add on nicely for us in the Eagle Ford.

We have hedged 20,000 barrel of oil per day in WTI for the first half of 2014 at an average price just under $97.50; and 7,000 barrel of oil per day at an average price just over $95 for quarter 3. This represents 32% of our US oil production and 13% of our total global oil production in the first half of the year.

Up in Canada in the Seal, we are continuing to focus on our EOR projects with recent work centered around steam. Our first cyclic steam stimulation pilot in the [Dodd] area continues to show promise.

We have two initial wells, and are most excited about the second well, as the first well had some mechanical issues in the completion.

The second well is currently producing in the third cycle and showing the best response to date, with production rates as high as 670 barrels of oil per day. The steam/oil ratio continued to improve in the previous cycle in this well, recording an impressive steam/oil ratio of 1.8.

We expect to receive regulatory approval for a third well sometime in quarter 2 and would then be ready to inject steam in the third quarter. We will average about one rig here all year and have increased activity in drilling strat wells in the winter season.

We have taken some strategic hedges here and have approximately 3,000 barrels a day of Seal heavy crude sold at an average netback price close to $49 per barrel in February and March.

In the Montney, we continue to focus on managing costs, improving netbacks. We've signed third-party processing agreements totaling 60 million a day through our two facilities.

We will run rigs here this year and focus on liquids-rich areas and well completion optimization, to keep the plant rates maintained and cost down. We have 110 million cubic feet per day of gas forwards sold in 2014 at approximately CAD4.00 per Mcf AECO.

Looking at production in the fourth quarter, quarter 4 production averaged 206,255 barrels oil equivalent per day, exceeding our recently updated guidance level of 205,000 per day. This gave us full-year production for 2013 of 205,719 barrels of oil equivalent to date.

Looking ahead to 2014, first-quarter production guidance is 205,000 per day. The first quarter takes into account the following.

The shift in the planned downtime for Kikeh field was associated with Siakap North/Petai, as I discussed earlier, from quarter 4 last year to quarter 1 this year. Downtime associated with the fire in the tender-assisted drilling rig which resulted in some production downtime and rig repairs that will delay field development work there. Lower Kikeh gas production due to further downtime at the third-party methanol plant this year.

For the full 2014 we will guide to a range of 235,000 to 240,000 barrel of oil equivalent per day as announced earlier this month. This represents strong growth, near 15% from 2013. Key areas of production growth come from Eagle Ford Shale, both shallow- and deep-water Malaysia oil projects, and the startup of Dalmatian in the Gulf of Mexico.

Kevin mentioned this early; I will repeat it. The capital expenditures for 2014 are budgeted at approximately $3.8 billion: $2.1 billion for development drilling; $1.1 billion for field development expenses; and $595 million for exploration, with $295 million of this total for exploration drilling. Our budget [deck] is $90 WTI, $97.50 Brent, $4 Henry Hub. And we expect to be close to cash-flow/CapEx parity for the year, excluding corporate charges.

To summarize, reserve replacement, there were 240%, which has us replacing reserves now for eight years in a row, with the current oil-weighted [over P-11] in excess of nine years. All systems are go for another year of oil-weighted production growth with our new shallow- and deep-water fields in Malaysia and Gulf of Mexico, as well as continued Eagle Ford Shale growth.

We had a successful year of gas exploration offshore Brunei. This success fits well with our recent sanction of our Block H floating LNG project of a similar size. A revamped exploration team will have two impactful wells drilled later this quarter, as we continue to add acreage to our global portfolio.

We are back to CapEx/cash-flow parity as a goal for our Company, with our assumed oil prices just below the forward curve. In conclusion, while the quarter had a number of one-off items, I am encouraged with the trend we are seeing in our E&P operating metrics on a yearly basis, as we continue our transition to a pure-play E&P company. I will now to be glad to open it up for your questions.

(Operator Instructions) Leo Mariani, RBC.

Hey, guys. Just a quick question here, in terms of your Montney gas. You guys talked about a couple rigs. Would you expect Canada gas to grow in 2014?

I will let Barry give you the guidance here, Leo. Good to hear from you. We are going to be drilling a couple rigs there. We think we are on to a new completion technique where we are moving some Eagle Ford completion techniques up there, and as we work that team as to under one management system.

We are probably pretty close to cash-flow/CapEx parity for that individual business, about $180 million to spend and about near that in cash coming the other way, with the $4.00 Hub that we have organized back to AECO. So Barry, why don't you give the guidance?

Yes. Leo, in 2013 Montney gas was in the 170 million cubic feet a day range, and in 2014 it's probably going to be just below 145, in that kind of range.

So we are growing production, Leo, in our business. It is oil-weighted, so we are declining in the Montney.

Got you. Okay, that's helpful. I guess on your downstream business you guys decided to put it in discontinued ops this quarter. You talked about being able to view 2013 more as a standalone E&P.

Is there anything else we should be reading into that in terms of -- I am not an accountant, but in terms of accounting rules? Does this mean that a sale is more certain or anything like that at this point, given the discontinued ops treatment? Can you give us any more color on that?

No, I mean it's been a long time and we do want two things. We want to be out of that business. Like I said in my remarks, we're progressing the sale of it.

There are numerous accounting things you can read into that, Leo if you'd like. There is one thing for sure is I am impatient and want to sell it, and I can tell you that. We are working hard to do that, and I think it is equally important to be able to explain our Company as a standalone, because that is our ultimate goal.

All right. I guess a question on OpEx here, looking at your US OpEx I think it was up about $3.50 this quarter from the third quarter. Also just seeing your Malaysia OpEx climb as well the past couple quarters, can you give us some more color on that and how we should be thinking about OpEx for 2014?

Yes, we had a pretty rough -- one of our first rough quarters in the Eagle Ford. Our production didn't grow for the first time, I guess ever. Severe flooding and cold temperatures. I think other peers were affected by that as well.

So naturally with our volumes down, our OpEx has to go up. We did add a good bit of production, but very much --the wells we added were very close to the ye.

We had a true-up of some ad valorem and severance taxes there; that is about half of that, as we would have had normal ad valorem and severance too. We still may need to look at how we report things, Leo. Our old historic Company were breaking out LOE. We have those taxes in there and have to true that up.

I think it doesn't truly reflect the team's work there on the LOE. So those are the issues around that, lower production and some catch-up of some taxes.

Over in Malaysia, while we are still trying -- we want to be an onshore complementary business with an offshore business. But we are still plagued. If we have one of the Kikeh [spend] on a well that is classified as operating expenses, that is still real money for us and it swings our OpEx. So that was a single well.

We have a lot of capital in Kikeh to finish the field development and work on the field.

And on occasion we have a well that we have to work on that is classified as OpEx. In this particular well we changed some tubing out, erosion, problems with the completion. We took the extra time, and that becomes an expensive well for us. It drives up our OpEx on kind of a one-off quarterly basis.

Okay, that's helpful. I guess just looking at your oil prices, you talked a little about this. But I guess your Syncrude price was down quite a bit this quarter relative to Brent in 4Q, and also just noticing that your US gas pricing kind of also weakened a little bit relative to Henry Hub. Can you give us any color around that and what we should expect going forward?

You're right. Syncrude was very low in the fourth quarter. We have it around $86. We think it will be higher than that this quarter.

It's just more of this Enbridge pullback of prices there, pullback of available pipeline and infrastructure issues around Canada. We saw that.

It is really tied more to the WTI differential lower than it is Brent. Our East Coast Canada would be more Brent-based.

On the gas side we are continuing to grow our gas in Eagle Ford Shale. Our Eagle Ford Shale gas, though, is tied back to a Port of Houston type price. So we always have a slight dip below Henry Hub there anyway, because most of our gas probably is in Eagle Ford, a very similar amount to the Gulf.

The Eagle Ford is growing. And I think that would be the answer to those couple of questions.

All right. I guess with respect to the Eagle Ford, do you guys produce significant condensate there? Can you give us any kind of breakdown on oil versus condensate production out of the Eagle Ford?

I'll let Barry, he's the one that gives me my standard [grade]. Now something, and the reason I'm making these comments, I think I've made them a couple of quarters in a row. We continue to struggle with writeups on US oil price realizations.

We just to this point, like I say, we still have some further work or consideration to do as we become a pure E&P company, on things like LOE. Just haven't ever broke out the NGL. I don't want say they're material, but they're growing in the Eagle Ford Share, and they're much below, much below oil prices.

So that's what changes our US price realization, because we do not create a line for NGL and then -- but we are very proud of our API crudes we have in Eagle Ford. We're not a condensate player. We just -- I didn't say I was smart enough to lease oil acreage or anything like that.

But we are an oil player in the Eagle Ford with very little condensate, quite prideful of our API average. And I'll let Barry give you the exact split out.

Leo, we're about 92% liquids, I'd say roughly 7% NGLs. And as Roger said, condensate is really not an issue; we actually have fairly decent [ACAP] quality. So, yes, we're getting good oil prices.

Okay. Thanks a lot, guys, for all the help.

Guy Baber, Simmons & Company.

I wanted to start off back at -- on the production cost front; and thanks for the color on 4Q. As you are setting expectations for 1Q and you have some of the guidance out there, is there anything that should be one-time, or is there anything that you're looking at that could influence the cost as we think about 1Q?

I know you had the fire in Malaysia; I am not sure if that would have an impact or not. You have some other activity going on in Malaysia. So just trying to get a sense of if there is any near-term risk to OpEx and just how we should think about that.

I am hopeful that OpEx will be down in the first quarter, and I do not know if any of those one-off -- we don't have a workover at Kikeh, which is a big deal. And we are growing production in the Eagle Ford in lieu of [Inleps] and I do not see that as -- I just don't see that as an ongoing change in operating policy [there]. (inaudible) Guy.

Okay, all right. That's helpful. Then I was hoping you could just talk a little bit more about the 2014 capital budget of $3.8 billion. Just maybe talk about some of the moving parts. I know you have some major projects seeming winding down.

Are you offsetting some of that with more capital getting allocated to the Eagle Ford? Can you just talk about some of the moving parts, and then how you are thinking about capital allocation in the Eagle Ford specifically, how that has changed, and how should we think about that going through 2014?

I don't think it has changed a whole lot. I really think in the Eagle Ford for me you have to be a first-class player and we are still a Company with both an onshore and an offshore business, and we want to maintain our deepwater deal set and our deepwater development ability. We think that's a competitive advantage for us.

So we are really picking these levels of rigs and all, what we think we can operate very, very well, and we're doing a very good job of that. If you look at total Eagle Ford Shale this year, about $1.5 billion to $1.6 billion; and all of US last year, it was $1.6 billion. Eagle Ford Shale this year probably a little bit less, $1.3 billion versus $1.4 billion as we have built a good many facilities this year. So that really probably not changing.

We want to -- we have a strategy of being an exploration-driven Company. We are going to remain that.

We're going to have a $500 million plus spend every year on exploration. It is not all for wells; it is seismic and acreage, etc.

So when you take the exploration material enough to make a difference, and you take the Eagle Ford Shale, and you take your other projects that you have sanctioned, we're trying to be pretty close to CapEx/cash-flow parity in the Montney and in Seal because those are not high net income provided to the companies, but have long-term aspirations there. You end up, what is left is what is needed in Malaysia and our overall look at cash-flow/CapEx parities, letting that be the driver of our capital allocation.

Got to get back to not exceeding cash flow and taking that discipline and not getting our debt any higher, continuing with our repurchase if we can afford to do so without raising debt, etc. And that is kind of my thoughts around the budget. Does that answer your question?

Yes, definitely does. Then I just had one more modeling one, probably for Barry. But you guys had an underlift, a pretty sizable underlift scheduled or planned for 1Q, I guess, within the guidance.

Is that in Malaysia or anywhere else? Can you just tell us where that might be?

(multiple speakers) Malaysia(inaudible).

Okay. All right. Thank you.

Evan Calio, Morgan Stanley.

Hey, good afternoon, guys. You guys have a lot of projects coming online in 2014. To get to your full-year 2014 average guidance, following the first-quarter guided number, should we expect all three of those offshore projects, both Malaysia, Dalmatian, online at full production levels in 2Q? Can you help me with the ramp there on the offshore side?

I will just talk to the color and Barry will do better with the ramp her. With Dalmatian we have the wells previously drilled, and we completed one; and we are going to have gas come on in March. For March gas will flow, and the oil will flow later, probably in early May.

We are very, very happy about how Kikeh is going. Of course that's been very delayed and not what we wanted it to be, because we have to shut in Kikeh and explain that as to our guidance over and over.

So we are doing that now, and so we're in the middle of it as we speak. And it is no small feat to install these big risers in that Kikeh turret.

So we have that behind us. We feel very good about that starting. That is in control.

So Siakap North should start as we said in the remarks. Dalmation, we are operating that, in the middle of it; should start, as we said. The four fields in Malaysia are doing very well in shallow water, ahead of plan, covering some of these other issues we have had at Kikeh, etc.

So that is all in pretty good shape. Then you left big Kakap, which is nonoperated, a big field. Not super-material for us but important. We have that starting in March, and we believe we've risked the startup of that as to how we would like to do that in our system.

But it could go from March a couple months late; that could happen. I believe -- I am certain we will be able to stay in the guidance levels that we provided with that lateness, and we have modeled that.

That is a rundown of those projects. If you want any more specifics, I will let Barry get into that for you.

Evan, without getting very specific into other quarters that we are not ready to do, second quarter we are showing a pretty big jump, in that 30 to 40 range if this stuff comes back on and we start to come on.

Then for second half of the year, you get another jump by roughly 10, maybe another 5-ish getting into the fourth quarter. So you see how it keeps ramping up through the year.

Great. Do you have an exit rate on 2014? This assumes that the average comes in(multiple speakers)

I don't, but that is going to get you awfully close, in that 255 range, 250-plus range.

Okay. On the Block H FLNG, on the sanction, where is the project in FEED? And when do you expect it to -- when would you need FID, I guess, in order to hit that 2018 startup time frame?

We have all that. We have full FID. We had that at Murphy here this week; PETRONAS had a special Board meeting they have. PETRONAS is building the ship with a group out of Korea; that is their CapEx.

We are tying into their ship. All systems go there, fully on to flow in 2018.

Okay. So you will just pay a toll on that? Is that how that will work? With the --

We're going to sell them gas. We sell gas to PETRONAS today. PETRONAS, one of the leading LNG players in the world, we sell them gas every day at SK and a factor of the full linked Japanese crude cocktail price. We have made that agreement with them, and we sell to them, that and [we're full].

Great. A follow-up on the downstream. If there wasn't a buyer for Milford Haven, what is the mark on the release of working capital in a closure? And are there any charges, or how would I think about that scenario?

I will let Kevin answer that. I don't believe anything has changed in the [bring on] scenario there. Let's let Kevin talk about (multiple speakers).

What we have talked about all along is we could have, once a sale gets completed, in the neighborhood of $600 million to bring back. That is what we are still modeling.

And when we bring back that money from the UK, naturally that's a potential tax implication. So we will look at what our foreign tax credits are and the like, and try to maximize the [pat] positions for us, moving some money around from other parts of the world.

Hopefully this impairment charge that we took in the fourth quarter, hopefully that's it or certainly the majority of it. But until a deal gets closed and you get final numbers, and final inventory item, all of that nature, there always could be some movement from that. But hopefully that will be the bulk of it.

Great. Just lastly for me, on Cameroon, you mentioned a February spud. Days to drill, when should we expect results on that one? It was a bigger well for you.

It's going to be about a 50-, 70-day well because it's in our control; we operate it. We are picking up the rig from Diamond Offshore, in the shipyard with them. We're coming to another operator [rather], I'm sorry.

When is the next call? I think we're going to be closer to the next call, early May. It's so pleasurable for me, I can't wait until the next one. (laughter) It's so great.

I got it. Appreciate it. Thanks, guys.

Roger Read, Wells Fargo.

Well, I guess the question I would love to ask is your quarterly production numbers; but I understand you don't want to give those just yet. Maybe another thing to focus on here.

As we walk through what needs to happen as you exit Q1 and then enter Q2, what are the particular projects again, if you could, just where you're the operator, where you're not the operator? So we can know what to look at over the next say four to six months more closely.

Well, Roger, I mean, it's no -- we are always into this. When you're the leading growing oil provider in the space, you always have to grow oil all the time. That is what we have been doing for a long time and very, very proud of it.

I think first step is we always got to be growing Eagle Ford, because we are a big Eagle Ford player and we're -- had a little pullback in the fourth quarter. We think we're in good shape for guidance in this quarter.

So to me, one of the things you look at there is how much we're increasing production there. So how much we are increasing production versus how many wells we're adding. When you look at that ratio, we feel we're in good shape and we are in control of that destiny there. So that is a big part of it.

Let me get my production sheet here. Then so we have always the Eagle Ford Shale, our growth piece.

We then have the projects in Sarawak, oil, and that would be almost a full year of those projects producing well. And they are all online, which is no small feat. This is four platforms we set; we have drilled wells; we have had very good results.

So the Eagle Ford Shale. We have the Sarawak oil project starting. We have the Kikeh shut-in now ongoing and not have to be concerned with that anymore.

We have the risers picked up for Siakap North/Petai, and we operate that. That is the third piece of the growth.

The only part we are not operating, would be the Kakap piece which I spoke of a few minutes ago. We have it in March; we feel we have risked that appropriately in what we have in our guidance and the lateness of that by two months, we should be able to handle in the range we have today.

And the full on year of Sarawak and the continued predictable growth year-on-year of Eagle Ford with the number of wells we plan to drill, and the CapEx we have for the rigs, should get us where we need to go.

And plus -- they've motioned to me here -- I forgot about Dalmatian. That is a project that is drilled and we have the Technip held up for weather in the Gulf and headed over there very quickly where we are completing the well. So there is a lot of new production coming online, Roger.

Oh, no. We are well aware it is a lot. Just want to make sure it actually gets here.

Roger, I can assure you, I am worried about it more than you.

I don't doubt that. Then as you look for growth beyond 2014, obviously some of the exploration wells in 2013 didn't turn out as good as hoped. There has been talk in the last couple of months, last couple of quarters, you might be a little more interested in acquisitions. You mentioned earlier cash flow measuring or matching up fairly well with CapEx.

If you were to start looking at acquisitions, what should we think about maybe in terms of size, scale you would be comfortable with at this particular point, given the balance sheet and assuming a reasonable resolution to the UK downstream?

Well, it's just kind of a misnomer about Murphy that we just fell off the face of the earth after a couple years because of exploration. I mentioned earlier today, we have a very, very high reserve replacement. We have a big running room left in the Eagle Ford, all these Pearsalls and Budas and steam up in Canada, these are all 20, 30 million barrels apiece.

And while we have been very unhappy with the deepwater exploration, we made a lot of changes to personnel. We still are a Company that is growing production and you know well out into 2016.

And I am not going to ever guide, because people would beat me up if I am still alive in 2018 [we're] in a flat barrel here. But when I look at this with just maintaining production in a very tight band all the way through 2018, 2019, even if we don't have any exploration success at all in the ocean, and that is without any of these projects that I just mentioned.

So with that said, we do look at M&A more than we probably ever have. We have a full set of people looking in the Permian today. I don't ever see us doing a stock deal or a big supermajor approach us or anything like that. We do have to get our cash-flow/CapEx parity always maintained.

We have to get this Milford Haven, UK, issue behind us before we look at doing that. We have been focusing in North American onshore.

But I am looking at things that could help R-over-P, not getting me way out of kilter on cash-flow/CapEx, meaning it would have some level of proven reserves and production. And those things are expensive.

And regardless of all that, Roger, we need to make return for our shareholders. And if we can do things to help our Company, help our metrics, and have return, we will be looking to do with them. We are looking at it now.

It is not that simple to [improve] yourself and have -- I am not interested in NPV 9.5 purchase, to be quite honest. So in fact looking a little bit in offshore globally, in the Gulf at the end of 2012, and those are really not what I originally wanted because they have a higher decline than the onshore.

But that is the story on that, if that answers your question.

It does. Thank you.

Pavel Molchanov, Raymond James.

Hey, guys. Similar question to the last one, but more on the exploration side. Appreciate the color on Bamboo and Titan. Then beyond those two prospects, can you help us with the sequencing on maybe what is spudding in Q2 and second half?

What is going to happen there is we have a rig at Dalmatian today; we have completed one well and have another to go. These are not long, significant completions. We are going to take that rig to Titan and operate and drill that well ourselves.

We have finished our work in Brunei for the year. We have two pretty high-risk but properly partnered big gas prospects to drill in Indonesia; those start in March. The rig is lined up to go there in March. We will drill the two wells back to back in Indonesia, finish in Brunei.

We would like to drill in Perth Basin very late this year. The rig is probably not going to make it.

A nice well to drill in Vietnam with our partner Santos in midyear. We definitely have the rig lined up and [tracking] in tow to the Ntem well Bamboo-1 now.

And back in the Gulf as I originally started to [refer], Dalmatian, Titan. Then we are looking at about three different Gulf of Mexico opportunities now; I would not like to name those specifically at this point. But probably finishing off the year in the Gulf.

I am a little short on wells. I always say I like to drill 10. But I really want to drill (technical difficulty). Things happen with rig delivery around the world; we're probably looking at seven now.

But we have the CapEx and the ability to drill 10, so might look at some other opportunities and [stuff] in the Gulf and globally (inaudible).

Okay. Any activity in Kurdistan this year?

No, we have exited those blocks and no longer play in Kurdistan.

No more Kurdistan? Okay. I was asking because it is still on the website. So, okay, understood. What percentage --

I will miss it, though.

There you go.

We still have our name on the door there, and we are in the process of exiting, and that is probably why it is still on.

Yes, clear enough. What percentage of the total $3.8 billion is allocated to exploration this year?

I think I had it in my remarks. It is $595 million of exploration. $295 million of the $595 million is for wells. The rest would be leases to stay on the Gulf and seismic.

Okay. Clear enough.

Exploration expense is around $12 million.

Thank you very much.

(Operator Instructions) Rakesh Advani, Credit Suisse.

Hi. It's Ed Westlake. Good afternoon, everyone. Looking forward to seeing you in a few weeks. I guess just keeping on the exploration theme, in terms of getting access to acreage, obviously you are drilling at a substantial chunk of the CapEx this year, which is good. But can you talk through the general thought process about increasing the pipeline of acreage that you can then drill down the road, so that you can get hit those 8 to 10 wells a year every year, that you would like to be doing?

Well, I don't think it is really insignificant to drill 7, if it is 7 good ones. I think if you take Murphy and benchmark Murphy on an acreage basis per BOE for reserves, for production, almost any metric, we would be the leader in an acreage basis.

So enormous acreage position in the Perth Basin, just new 3D seismic in; very excited about being able to drill there. Nice position in Vietnam; I mentioned earlier that we have many multiple wells to drill. And a very, very nice acreage position in Southern Australia where we are surrounded by BP and Statoil and Chevron now, and it puts us in a very good situation.

Gulf of Mexico we have 7 to 8 of these prospects in the Norphlet left to go, plus all of our Miocene older acreage there. We feel we have a nice set of prospects there.

In Cameroon, have many prospects there but really depending on success here. And building a nice position in Equatorial Guinea with seismic.

So we are probably in pretty good shape for 2014/2015, but it is an ever-running business to keep that going. That is why you have the $500-million-plus in CapEx and over half of it for drilling. The other half has to be for seismic and continuation of that effort.

And if you are inconsistent on that spend, and end up with a year where you have 3 or 4 wells, which is a lot different than 7 to 10, then that is where the problems arise. And that is what we are trying to avoid.

Yes. In the Australian acreage, obviously a frontier but potentially interesting as you say with the majors there. when do you reckon you will have done enough -- or how long, probably two years of seismic and --?

In the Perth Basin we are definitely going to drill the wells. We are going to drill three wells there, and we have a rig contract and signed one to do so; and it is going to be right at the end of 2014.

So we are going to do that, and we're very pleased with what we are seeing in the seismic there. And this is not super-expensive frontier from a weather perspective. The Southern Great Bight or the offshore Southern Australia, severe weather would be very similar to West Shetlands in the UK.

That will be something where we are fortunate and happy about. Our commitment to the block is seismic only, and we have other people that will be drilling, as it says in my remarks. They will be drilling ahead of us, and we will be able to have the seismic; follow up their drilling; and be derisked there. And I think it puts us in a really good position for a Company of our size.

We also have a partner there. So that is the comments on the Australian side.

Thanks for bringing me back to the UK with the West Shetlands weather.

Oh, yes.

Final question just switching back to the North America shale, the Eagle Ford. Just run through, if you had to look at the year, what were the major excitements? Was it, as you pointed out, Pearsall, Buda, down-space tests? Obviously you have down-spaced in some fairly low acreages. Was it just improvements in recoveries or costs or --? (multiple speakers)

All of those things are great. Everything you said. I see when I look back at our team this year in the Eagle Ford, you look at Eagle Ford Shale OpEx. It started off quarter 1 at $22.52, and everybody was screaming about it; but we ended up the fourth quarter at $17 and actually had a $13 in the third quarter. So increasing OpEx there and improving OpEx metrics with big -- putting in the facilities there, being a real fine-tuned machine at drilling with these 8 rigs. And it is going very, very well for us.

A very large reserve booking there, about 85 million barrels, which took care of our entire Company. We have 2P there probably in the 275 million range, and we think that could go to 600 million now.

This is becoming our real go-to legacy field. It's the biggest field in the Company history. Proving, drilling, significant reserve booking, improving the OpEx, costs improving continues there. Like other players.

I am proud of the fact that while we are not a shale-scale big player, some would say we are able to drill, produce, and improve like our peers around us. And just overall pleased with that whole effort.

Just then a final reminder on that 600 million barrels, what spacing would you assume for that?

There is a slide in our decks that talks about walking your way up from the different spacings. I think I would rather refer you to that.

Okay. Well, thanks very much.

Okay. Thank you.

At this time it appears we have no further questions in queue. I would like to turn the conference back over to our speakers for any additional or closing comments.

That's all we have today. We appreciate everyone's time dialing in for our call, and we will look forward to seeing you next time. Thanks.

With that, ladies and gentlemen, that does conclude today's conference call. We would like to thank you again for your participation.