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Executives

Roger W. Jenkins - Chief Executive Officer, President, Director and Member of Executive Committee

Barry F.R. Jeffery - Vice President of Investor Relations

Kevin G. Fitzgerald - Chief Financial Officer and Executive Vice President

Analysts

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Guy A. Baber - Simmons & Company International, Research Division

Evan Calio - Morgan Stanley, Research Division

Roger D. Read - Wells Fargo Securities, LLC, Research Division

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

Edward Westlake - Crédit Suisse AG, Research Division

Murphy Oil (MUR) Q4 2013 Earnings Call January 30, 2014 1:00 PM ET

Operator

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.

Roger W. Jenkins

Thank you, operator, and good afternoon, everyone, and 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, Senior Vice President and Controller; and Barry Jeffery, Vice President of Investor Relations here at Murphy, and will now make his customary comments.

Barry F.R. Jeffery

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 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 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'll now turn the call over to Kevin.

Kevin G. Fitzgerald

Thanks, Barry. Beginning in the fourth quarter of 2013, our U.K. refining and marketing operations are presented as discontinued operations. So for the full year of 2013, discontinued operations include our U.K. E&P properties, which were sold earlier in the year; our U.S. retail and related operations that was spun off to shareholders at the end of August; and all of the U.K. downstream operations.

Net income from continuing operations, which is basically our remaining E&P property for the fourth quarter of '13 is $180.5 million or $0.96 per diluted share. This compares to net income from continuing ops in the fourth quarter of '12 of $123.9 million or $0.64 per diluted share.

For the full year of 2013, net income from continuing ops is $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 benefits 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 full year results from continuing operations for 2013 also included charges of $82.5 million associated with abandonment and exit activities with 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 the Azurite. There was no income tax effect related to these charges within the year.

Looking at total net income for the fourth quarter of '13, a $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 of 2013 was $1,423.5 million 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 or $0.18 per diluted share for the 2012 quarter. The 2013 quarter included an impairment charge of $73 million for the U.K. downstream business with no tax effects, while the 2012 quarter included a $25.7 million after-tax impairment charge related to an ethanol plant.

Looking at net income by segments. In the E&P segment, net income from continuing operations in the fourth quarter of 2013, $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 of 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 '13 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 per day in the '13 quarter compared to 473 million cubic feet a day in '12, 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 '13 had a net charge of $62 million compared to a net charge in the fourth quarter of last year of $21.1 million. Increased costs from the current year mostly relate to higher interest and administrative costs and lower income tax benefit, partially offset by favorable results from transactions denominated in foreign currency. 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 in 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, totaled $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 and this includes approximately $340 million related to the Kakap FPSO lease. And this adds up to 26.5% of total capital employed, while cash, cash equivalents and short-term investments in marketable securities totaled a little over $1.4 billion, including about $300 million that's included in current assets held for sale and on the balance sheet. And with that, I'll turn it over to Rog.

Roger W. Jenkins

Thank you, Kevin. 2013 was a good year for our shareholders here. Spin-off of Murphy USA was completed in the third quarter and was a seamless transition for the 2 entities. We've made good progress in 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 for 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 oil equivalent per day mark, with our best year ever in reserve replacement, with over 240% on an organic basis. We set the stage for 2014 production growth with the startup of 4 shallow water oilfield developments in Sarawak, Malaysia and we're progressing startup on 2 deepwater fields there as well and 1 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 prospective, 2013 was the second most profitable year ever for upstream operations, with only the high oil price year of 2008 taking precedence. We're continuing to progress our U.K. downstream sale effort. We have reported this business as discontinued ops, 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 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 Gulf 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 U.S. liquids price by close to $4.75 per barrel. We do not, at this time, break out U.S. NGL volumes or price in our statement.

In 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 a partnership group has opened up a new gas play with 3 discoveries. We've successfully followed up the Kelidang discovery in 2013, with 2 more gas discoveries at Keratau and Kempas at the end of the year. All of these 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 our possible drilling locations early next year. We're preparing to drill the Block 13-03 exploration well later this year at 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 2 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're preparing to drill our operated Norphlet prospect, Titan, at 50% working interest, which is expected to spud in early March. The pre-drilled gross mean resource estimate for the well remains at 200 million barrel of oil equivalent. The Titan well is located in the northernmost portion of the play fairway that's in close proximity to other successful Norphlet wells.

In the Atlantic Margin, our NTEM block, offshore of Cameroon, we expect to spud the Bamboo-1 well in February. The well is testing Cretaceous-age, stock bands, with a pre-drilled gross mean resource estimate in the range of 600 million barrels. Offshore Equatorial Guinea in Block W, we've completed acquisition of our 3D seismic for 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, and we'll be preparing to start our exploration drilling program during late '14, early '15. In our Block EPP43 in the Ceduna Basin, offshore Southern Australia, we're planning to acquire 3D seismic toward the end of 2014 and into '15, and expect wells to be drilled in the adjacent blocks starting in 2015 to test similar plays by other operators. This is a 6-year permit with commitment for 2D and 3D seismic only.

As to global offshore operations in shallow water Malaysia, execution on all 4 of our new oil developments at Serendah, South Acis, Patricia and Permas went very well and all were producing above plan. Patricia and Permas were the last 2 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 years as part of the overall field development plan.

As previously announced, we experienced a fire on January 5 in the hole of a tender assisted drilling barge called the SKD Menang, which is more adjacent to the Kikeh production spar. We're shutting production from the spar as a safety precaution, while the subsea wells continue to produce directly to our FPSO. The spar wells were down for approximately 2 days and the wells are being 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.

In our deepwater projects, we continue 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 at Kikeh FPSO to execute these tie-ins at the Siakap North-Petai risers have deferred from late in the fourth quarter to the first quarter of this year with shut-in and tie-in work that's currently ongoing. The Kikeh field shutdown started in January 23 and we expect to be completed and bringing the Kikeh back on line near the second week of February. Two production risers are now installed for the Kikeh FPSO, and work has started on the third and final one, which will be used for water injection. We're 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 4 subsea oil producers online. The Siakap North-Petai development plan consists of 8 producers and 5 water injectors in total. Drilling, to date, indicates subsurface results are exceeding expectations.

The Kakap had gone through early production systems, producing the plan through 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 near 167 million cubic feet per day, net in quarter 4.

The Block H Malaysia's floating LNG project with our partner Petronas, is now fully sanctioned by both parties and the oil-linked gas terms agree. This is a major milestone for both companies. We feel fortunate to be part of the -- 1 of the 3 first floating LNG projects in the world and to monetize gas from a very successful exploration drilling program in a block taking place over the last 7 years. The project will be a phased development centered around the Rotan discovery and gas resources from 3 satellite fields. We are planning on first gas in 2018 with a 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 2 now fully completed. Our pipeline contract will be in the field soon to perform the subsea pipeline tieback work for Chevron and Petronas hub, with first production slated for later this quarter.

North American onshore and Eagle Ford Shale ended the quarter with a new production record of 51,127 barrel oil equivalent per day on December 23. We're currently running 8 rigs and 3 frac units across the play, with now 340 wells producing. Production averaged 41,900 barrel oil equivalent 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 frac-ing 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 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 oil equivalent per day in 2012 with an additional 174 operated wells online. Drilling and completion performance continues to improve with an average drilling cost improvement another 9% through 2013. We've reduced drilling and completion costs by a total of 40% as to start up of development in 2011. Downspacing in the Eagle Ford Shale continues to show excellent results. Our down-spacing projects in Karnes and Tilden areas continue to show the wells are performing comparable to neighboring wells. We are now down spacing as part of our field development going forward. We have 112 down-spaced wells below 80-acre of spacing producing in this play. Our well optimization work continues to progress with longer laterals and well orientation for spec to minimum regional stress direction in order to optimize frac results and improve overall EUR per well.

We continue to evaluate potential in Pearsall Shales and the Buda Lime. To date, we have drilled 4 wells in the Pearsall: 2 vertical; 2 horizontal; and 1 horizontal well planned this year. We're targeting this well in the key part of the play fairway and we're hopeful the results trigger a future development. In the Buda Lime play, we have 2 wells planned in 2014 to test the zone, an additional resource potential here that add on nicely for us in the Eagle Ford. We have hedged 20,000 barrel oil per day of WTI for the first type of 2014 at an average price just under $97.50. The 7,000 barrel oil per day at an average price just over $95 for quarter 3. This represents 32% of our U.S. oil production and 13% of our total global oil production in the first type of the year.

In Canada and the Seal, we continue to focus on our EOR projects with recent works centered around steam. Our first cyclic steam stimulation pilot in the Cadotte area continues to show promise. We have 2 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 the third cycle and showing the best response to date with production rates of size 670,000 barrels of oil per day. Steam-to-oil ratio continue to improve in the previous cycle on this well, reporting an impressive steam-to-oil ratio of 1.8. We expect to receive regulatory approval for our third well some time in quarter 2, and we'll then be ready to inject steam in the third quarter. We will average about 1 a rig here all year and have increased activity in drilling strat wells in the winter season.

We're taking 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 and improving netbacks so it's on third-party processing agreements, totaling 60 million a day through our 2 facilities, where we won 2 rigs here this year and focused on liquids-rich areas and well completion optimization to keep the plant rates maintained and costs down. We have 110 million cubic feet per day of gas forward-sold in 2014 in approximately CAD 4 per Mcf AECO.

Looking at production in the fourth quarter. Quarter 4 production averaged 206,255 barrels of 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 oil equivalent per day. 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 associated with Siakap North-Petai, which I've discussed earlier, from quarter 4 last year to quarter 1 this year; downtime associated with burrowing the tender-assisted [ph] drilling rigs, 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 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, which represents strong growth near 15% in 2013. Key areas of production growth come from Eagle Ford Shale, both shallow and deepwater Malaysia oil projects and the startup of Dalmatian in the Gulf of Mexico. Kevin mentioned this early, I'll repeat it. The capital expenditures for 2014 are budgeted at approximate $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 -- cash flow CapEx parity for the year excluding corporate charges.

To summarize, our reserve replacement was over 240%, which has us replacing reserves now for 8 years in a row with the current oil-weighted off of delevering [indiscernible] of 9 years. All systems are go for another year of oil-weighted production growth at our new shallow and deepwater fields in Malaysia and Gulf of Mexico, as well as continued Eagle Ford Shale growth. We have a successful year of gas exploration offshore Brunei, and this success sits well with our recent sanction of our Block H floating LNG project of a similar size. Our revamped exploration team will have 2 impactful wells drilled later this quarter as we continue to add acreage to our global portfolio.

We're back to CapEx cash flow parity as a goal for our company with our assumed oil prices just below the full curve. In conclusion, while the quarter had a number of one-off items, I'm encouraged with the trend we're seeing in our E&P operating metrics on a yearly basis as we continue our transition to a pure play E&P company.

I'll now be glad to open it up for your questions.

Question-and-Answer Session

Operator

[Operator Instructions] And we'll go first to Leo Mariani of RBC.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

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

Roger W. Jenkins

I'll let Barry give you the guidance here, Leo. Good to hear from you. We're going to be drilling a couple of rigs there. We think we're on to a new completion technique, but we're kind of moving some Eagle Ford completion techniques up there, and as we work that team as to -- under one management system. We're pretty close to cash flow CapEx parity for that individual business, about $180 million spend and about a -- near that in cash coming the other way with the $4 Hub that we have organized back to AECO. So, Barry, why don't you give the guidance?

Barry F.R. Jeffery

Yes. So, Leo in '13, Montney gas was within the 170 million cubic feet a day range. And in '14, it's probably going to be just below 145, in that kind of area.

Roger W. Jenkins

So regarding our production, Leo, in our business, it is oil-weighted, so we are declining in Montney.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Got you. Okay, and that's helpful. I guess on your downstream business, you guys decided to put it in discontinued ops. This quarter you talked about sort of 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'm not an accountant but in terms of accounting rules, does this mean that sales are more certain or anything like that? At this point, given the discontinued ops treatment, can you give us any more color on that?

Roger W. Jenkins

No, I mean it's been a long time and we do want 2 things. We want to be out of that business, like I said in my remarks, are addressing the sale of it. There are numerous accounting things you could read into that, Leo, if you'd like. But one thing for sure is I'm impatient and want to sell it, I can tell you that. And we're working hard to do that. And I think it's equally important to be able to explain our company as a standalone because that's our ultimate goal.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

I guess question on OpEx here. Within your U.S. OpEx, I think it was up about $3.50 this quarter from the third quarter. And also just seeing your Malaysia OpEx, climbed as well the past couple of quarters. Can you kind of give us some more color on that and kind of how we should be thinking about OpEx for 2014?

Roger W. Jenkins

We had a pretty rough -- one of our first rough quarters in Eagle Ford. Our production didn't grow for the first time, I guess, ever. Had some severe flooding and cold temperatures happening, but other peers were affected by that as well. So naturally with our volumes down, our OpEx have to go up. We did have a good bit of production but very much coming out of the wells, we had very close to the year end. We had a true-up of some ad valorem and severance taxes there, that's about high for that because they would have had normal ad valorem and severance. We still may need to look at how we report things, Leo. Are a old, historic company. We're not breaking out LOE, we have that -- those taxes [ph] in there and have to true that up. I think it doesn't truly reflect the team's work there on LOE. So those are the issues around that, lower production and some catch-up with some taxes. Over in Malaysia, while we're still trying -- we want to be a onshore complementary business with an offshore business, but we're still plagued that we have one of the Kikeh spin on a well that's classified as operating expenses. That's still real money for us and swings our OpEx. So that was a single well. We have a lot of capital in Kikeh to finish the development and work on the field. And on occasion, we have a well that we have to work on that's classified as OpEx. In this particular well, we changed some tubing out with erosion, problems with completion that took extra time. And that becomes an expensive well for us and drives up our OpEx on a kind of a one-off quarterly basis.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

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 U.S. gas pricing kind of also weakened a little bit relative to Henry Hub. Can you kind of give us any sort of color around that? And what we should expect sort of going forward?

Roger W. Jenkins

You're right, Syncrude was very low in the fourth quarter. We have around [indiscernible], so we think it'll be higher than that this quarter, as it's -- more of this is Enbridge pullback of prices there -- pullback of available pipeline and infrastructure issues around Canada. We saw that -- it's really tied more to WTI differential lower than it is Brent. Our East Coast Canada will be more Brent based. On the gas side, we're 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 don't -- we always have a slight dip below Henry Hub there any way because most of our gas probably 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 there.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

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 sort of oil versus condensate production on Eagle Ford?

Roger W. Jenkins

I'll let Barry, the one who gives me my standard breakdown. It's not been -- 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 write-ups on U.S. oil price realization. And 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. We just haven't ever broke out the NGLs. I don't want to say they're material because they're growing in the Eagle Ford Shale and they're much below, much below oil prices. So that's what changes our U.S. price realization because we do not fleet a line for NGL. And we are very proud of our API crudes that we have in Eagle Ford where we're not a condensate player. We just have, 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 there.

Barry F.R. Jeffery

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 API quality, so we're getting a good oil price.

Operator

Our next question will come from Guy Baber of Simmons & Company.

Guy A. Baber - Simmons & Company International, Research Division

I wanted to start off back at on the production cost front, and thanks for the color on 4Q. As you're setting the 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'm not sure if that would have an impact or not. You have some similar activity going on in Malaysia. So just trying to get a sense of, if there's any near-term risk to OpEx and just how we should think about that.

Roger W. Jenkins

I am hopeful that OpEx will be down in the first quarter. And I do not know of any of those one-off -- we don't have a workover at Kikeh, which is a big deal. And we are growing production in Eagle Ford and a new well in the West [ph]. And I do not see that as -- I just don't see that as an ongoing change in operating cost there, Gary. I mean, Guy.

Guy A. Baber - Simmons & Company International, Research Division

Okay, all right. That's helpful. And then I was hoping you could just talk a little bit more about the 2014 capital budget of $3.8 billion. Just can you talk about some of the moving parts? I know you have some major projects that you're winding down. Are you offsetting some of that with more capital getting allocated in Eagle Ford? But can you just talk about some of the moving parts? And then how you're thinking about capital allocation in the Eagle Ford, specifically how that's changed? And how should we think about that going through 2014?

Roger W. Jenkins

I don't think it's changed a whole lot. I mean, I really think in 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 skill sets and our deepwater self mobility [ph]. We think that's a better advantage for us. So we're picking through levels of rigs and all with what we think we can operate very, very well and we're doing a very good job at that. If you look at total Eagle Ford Shale this year, about 1.5 billion to 1.6 billion in all of the U.S. Last year it was 1.6 billion. Eagle Ford Shale this year probably a little bit less, 1.3 versus 1.4 as we build the new [ph] facility this year. So that's really probably not changing. We want to -- we have a strategy of being an exploration-driven company, we're going to remain that. We're going to have a $500 million-plus spend every year on exploration. It's not all for wells, but seismic and acreage, et cetera. So when you take the exploration, material enough to make a difference, and you take your Eagle Ford Shale, and you take your other project that you've 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 providers, but companies would have long-term aspirations there. And it ends up what's left is what's needed in Malaysia, and our overall look at cash flow CapEx parities letting that be the driver of our capital allocation, God forbid. That cannot exceed in cash flow and baking that discipline and not getting our debt in par, and continuing with our repurchase if we can afford to do so without breaking debt, et cetera. And that's kind of my thoughts around the budget, if that answers your question.

Guy A. Baber - Simmons & Company International, Research Division

Yes, it definitely does. And then I just had one more modeling one, probably for Barry. But you guys had an underlift, pretty sizable underlift scheduled for -- or planned for 1Q I guess within the guidance. Is that in Malaysia or anywhere else? Can you just tell us where that would be?

Roger W. Jenkins

That will be in Malaysia, Guy.

Operator

Our next question will come from Evan Calio of Morgan Stanley.

Evan Calio - Morgan Stanley, Research Division

Yes, you guys have a lot of projects coming online in 2014, and to get your full year 2014 average guidance following the first quarter guided number. Should we expect all 3 of those offshore projects, both Malaysia and Dalmatian, online at full production levels in 2Q? I mean, can you help me with some of the ramp there on the offshore side?

Roger W. Jenkins

I'll just talk to the color and Barry will help with that a bit, with the ramp here. We're -- in Dalmatian, we have the wells previously drilled and we've completed one, where we'll have gas come on in March. The gas will flow and the oil will flow later, probably at early May. We're very, very happy about how Kikeh is going. Of course, it's been very delayed and not what we wanted it to be because we have to shut in at Kikeh and explain that as to our guidance over and over. So we're doing that now. And so we're in the middle of as we speak and it's no small feat to install these big risers in that Kikeh turf. So we have that behind us. We feel very good about that starting. That's in control. So Siakap North should start as we said in March. Dalmatian will operate in that and the middle of it should start, as I said. Now the 4 fields in Malaysia are doing very well at shallow water, ahead of plan, covering some of these other issues we've had at Kikeh, et cetera. So that's all in pretty good shape. And we have big Kakap, which is nonoperated, big field. But not super material for us but important. We have that starting in March, and we believe we risk the startup of that and how we would like to do that in our system. But it could go from March a couple of months late. That could happen, I believe. I'm certain we'll be able to stay in guidance levels that we provided with that lateness. We've modeled that. That's kind of a rundown of those projects. If you want any more specifics, I'll let Barry get into that for you.

Barry F.R. Jeffery

Yes, I mean, Evan, without getting very specific into other quarters that we're not ready to do, second quarters we're showing a pretty big jump, certainly in that 30 to 40 range. At this time, it's back on or starting to come on. And then for the second half of the year, it's kind of getting another jump by roughly 10, maybe another 5-ish getting into the fourth quarter. So you see how I'm keeping slamming [ph] up to there.

Evan Calio - Morgan Stanley, Research Division

Great. And what's -- do you have an exit rate on 2014? The average...

Barry F.R. Jeffery

I don't know. But that's going to get you awfully close to that 2 55 range, 2 50-plus range.

Evan Calio - Morgan Stanley, Research Division

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

Roger W. Jenkins

We have all that. We have full FID. We have that mostly here this week. Petronas has a special board meeting. They have -- Petronas is building the ship with a group, Korea. That's their CapEx. We are timing for their ship. Every -- all systems go there fully on to flow in '18.

Evan Calio - Morgan Stanley, Research Division

Okay. So you just had a toll on that. Is that how it works with the...

Roger W. Jenkins

We're going to sell them gas. We sell gas to Petronas today. Petronas is one of the leading LNG players in the world. We sell them gas every day at SK at a factor of an oil link to Japanese crude cocktail price. We've made that agreement with them and we're going to sell to them that and move forward.

Evan Calio - Morgan Stanley, Research Division

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

Roger W. Jenkins

I'll let Kevin answer that. I don't believe anything has changed in the bring home scenario there. Let's let Kevin...

Kevin G. Fitzgerald

What we've talked about all along is we should have -- once the sale gets completed, in the neighborhood of $600 million to bring back. That's what we're still modeling. And when we bring back that money from the U.K, naturally there's some potential tax implications, so we'll look at what our foreign tax credits are and the like and try to maximize tax positions as far as moving some money around in other parts of the world. And hopefully, there's some damage charge that we took in the fourth quarter. Hopefully, that's it, or certainly a majority of it, but until the deal gets closed and we get final numbers, final inventory item, all of that nature, there's always could be some movement in that number, hope we don't get below that number.

Evan Calio - Morgan Stanley, Research Division

Great. Just lastly for me on Cameroon. You mentioned a February spud, days to drill, when should we expect results on that one? Is it a bigger well FEED?

Roger W. Jenkins

We're on -- it's going to be about a 50- to 70-day well. But it's in our control, we operate, we're picking up the rig from Diamond Offshore and the shipyard with them -- are coming from another operator, rather, I'm sorry. When's the next call? I think it could be close for the next call that we make. So, so pleasurable for me. I can't wait for the next one, really, I don't know the date. It's so great.

Operator

We will go on next to Roger Read of Wells Fargo.

Roger D. Read - Wells Fargo Securities, LLC, Research Division

Well, I guess the question I'd love to ask is your quarterly production numbers, but I understand you don't want to give those just yet. But 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 or where you're not the operator, so we can kind of know what to look at over the next say 4 to 6 months more closely?

Roger W. Jenkins

Well, Roger, I mean, it's -- no, we're always into this. When you're the leading growing oil provider in the space, you always have to drill oil all the time. That's what we've been doing for a long time, and we're very, very proud of it. I think first step we always have to grow in Eagle Ford coast. We're a big Eagle Ford player, more heavily pulled back in the fourth quarter. We think we're in good shape for the guidance in this quarter. So to me, one of the things you look at there is we -- how much we're increasing production there. So how much we're increasing production first is how many wells we're adding. If you look at that ratio, we feel we're in good shape, we're in control of that destiny there. So that's a big part of it. Let me get my production sheet here. And then -- so we have always the Eagle Ford Shale growth feed. We then have the projects in Sarawak Oil and that would be almost a full year of those projects producing well and they're all online, which is no small feat, it's 4 platforms we set, we 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's a third piece of the growth. The only part we're not operating is the Kakap piece, and which I spoke over a few minutes ago. We have in March. We feel we've risked that appropriately in what we have in our guidance and the lateness of that by 2 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 the promotion from here, forgot about Dalmatian, that's a project that is drilled and we have the technique held up for weather in the Gulf. And handed over very quickly, where we're completing the wells. So it’s a lot of new production coming online now, Roger.

Roger D. Read - Wells Fargo Securities, LLC, Research Division

Oh, no, we're well aware it's a lot, just want to make sure it actually -- it gets there.

Roger W. Jenkins

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

Roger D. Read - Wells Fargo Securities, LLC, Research Division

All right. I don't doubt that. And then as you look for growth beyond '14, obviously, some of the exploration wells in '13 didn't turn out as good as hoped. There's 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 up 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'd be comfortable with at this particular point, given the balance sheet and assuming a reasonable resolution to the U.K. downstream?

Roger W. Jenkins

Well, it's just kind of a misnomer about Murphy that we just fall off the face of the earth after a couple of years because of exploration. I mentioned earlier today, we have 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 million, 30 million barrels a piece. While we've been very unhappy with the deepwater exploration, we made a lot of changes to personnel. We're still a company that's growing production and you know well out into '16. And I'm not going to ever guide because people will beat me up if I'm still alive in 2018, we're in bad peril here. But now look at this, we're just maintaining production of a very tight band all the way through '18, '19, even if we don't have any exploration success at all in the ocean. And after routing 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 super major purchase or anything like that. We do have to get our cash flow CapEx parity always maintained. We have to get the Milford Haven U.K. issue behind us, before we looked at doing that. We have been focusing on North America and onshore, but I'm looking at things that could help all of the P, not get me way out of kilter on cash flow CapEx, meaning we could 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'll be looking to do it, and we're looking at it now. But it's not that simple to prove yourself and have -- I'm not interested in NPV, [indiscernible] a purchase to be quite honest. So the fact, looking a little bit in offshore globally in the Gulf at the end of '12 and those are really not what I originally wanted because they have a higher decline in the onshore. But that's the story on that, if that answers your question.

Operator

And next we'll go to Pavel Molchanov of Raymond James.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

Similar question to the last one, but more on the exploration side. So appreciate the color on Bamboo and Titan. And then beyond those 2 prospects, can you help us with the sequencing on maybe what's spudding in kind of Q2 and in the second half?

Roger W. Jenkins

What's going to happen there is we have our rig at Dalmatian today, completed 1 well and have another 1 to go each [indiscernible] not known significant completion. We're going to take that rig to Titan and operate and drill that well ourselves. We have finished our work in Brunei for the year. And we have 2 pretty high risk but properly partnered, big gas prospects in Brunei and Indonesia. Those start in March. Rig is lined up to go there in March with those 2 wells back-to-back in Indonesia, finished in Brunei. We would like to drill in Perth basin very late this year. It's probably not going to make it. A nice well to drill in Vietnam with our partner, Santos, in the midyear. And we'll definitely have the rig lined up and frac-ed and towed to the NTEM well, Bamboo-1 now, and we -- back in the Gulf we originally started to. So Dalmatian, Titan and then we are looking at about 3 different Gulf of Mexico opportunities now. Would not like to name those specifically at this point but probably finishing off the year at the Gulf. I'm a little short on wells. I always say I'd like to drill 10, but I really want to drill all things happened with rig [indiscernible], around the world. We're probably looking at 7 now. But we have the CapEx and the ability to drill 10. So now would look at some other opportunities, both in the Gulf and globally [indiscernible].

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

Okay. Any activity in Kurdistan this year?

Roger W. Jenkins

No. We have exited those blocks and are no longer playing in Kurdistan.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

No more Kurdistan, okay. I was asking because it's still on the website. So okay, understood. And what percentage are you...

Roger W. Jenkins

And I will and this is a -- we still have our name on the door there, and we're in the process of exiting and that's probably why it's still on.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

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

Roger W. Jenkins

I think I had it in my remarks, it's $595 million of exploration and $295 million of the $595 million is for wells, and the rest would be at least [indiscernible] in the Gulf and seismic. Exploration expenditure is around the floor.

Operator

And at this time, we have one question in queue [Operator Instructions] We'll go next to Rakesh Advani of Credit Suisse.

Edward Westlake - Crédit Suisse AG, Research Division

It's Ed Westlake. I guess just on the -- keeping on the exploration theme, I mean, in terms of getting access to acreage, I mean, obviously, you're 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 hit those kind of 8 to 10 wells year-over-year that you'd like to do?

Roger W. Jenkins

Well I don't think it's really insignificant to drill 7, if it's 7 good ones. I think if you take Murphy and benchmark Murphy on an acreage basis per BOE, per reserves, per production, almost any metric we would be the leader in an acreage basis. So we have enormous acreage position per basin with just new 3D seismic in, very excited about being able to drill there. Nice acquisition 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're surrounded by BP and Statoil, and Chevron now, and 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, we have many prospects here but really depends on the success here and building a nice position Equatorial Guinea with seismic. So we probably are in pretty good shape for '14 and '15, but it's an ever running business to keep that going. That's why you have the $500-plus million CapEx and over half of it for drilling and the other half has to be for seismic and continuation of that effort. And if you are inconsistent on that spend, [indiscernible] the year where you have 3 or 4 wells, which is a lot different than 7 to 10, and that's where the problems arise and that's what we're trying to avoid.

Edward Westlake - Crédit Suisse AG, Research Division

Yes, in the Australian acreage, I mean, obviously, a frontier but potentially interesting as you say with the majors there. When do you reckon you'll have done enough -- I mean how long -- will it be 2 years of seismic and...

Roger W. Jenkins

Well, in the first basin, we're definitely going to drill the wells. We're going to drill 3 wells there and we have a rig contract in San Juan do so and it's going to be right at the end of '14. So we're going to do that and we're very pleased with what we're seeing in the seismic there. And this is not superexpensive frontier from a weather perspective. The Southern rate bite or the offshore Southern Australia severe weather will be very similar to what the Chevron would be in the U.K. That will be something where we're fortunate and happy about our commitment to the Block of seismic only. And we have other people that will be drilling, as it says in my remarks, who will be drilling ahead of us. And we'll be able to have the seismic follow-up their drilling and de-risk there. And I think puts us in a real good position for a company of our size. We also have a partner there. So that's the comments on the Australian side.

Edward Westlake - Crédit Suisse AG, Research Division

Thanks for bringing me back to the U.K. Just final question just switching back to the North American Shale, the Eagle Ford. I mean, just run through if you had to look at the year, what were the major excitements? Was it Pearsall, Buda, down spacing some very lower acreages, was it just improvements and recoveries or busts or...

Roger W. Jenkins

All of those. Everything you said. Plus, if I look back at our team this year in Eagle Ford, look at Eagle Ford Shale OpEx of startup quarter 1 at $22.62 and everybody's screaming about it, but we ended up to fourth quarter at 17, actually had a 13 in the third quarter. So increasing OpEx there and improving OpEx metrics is big, putting in the facilities there, getting a real fine-tuned machine that's drilling some great rigs and has gone very, very well for us. Has a very large reserve booking there, about 85 million barrels, which took care of our entire company. We have 2 feeds there probably in the 275 million range, and we think that could go to 600 million now versus becoming a real go-to legacy field, the biggest field in the company's history and proving drilling, significant reserve booking, improving the OpEx, cost improving continues there. Like the other players, I'm proud of the fact that while we're not a shale scale, a 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.

Edward Westlake - Crédit Suisse AG, Research Division

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

Roger W. Jenkins

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

Operator

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

Roger W. Jenkins

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

Operator

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

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Source: Murphy Oil Management Discusses Q4 2013 Results - Earnings Call Transcript
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