TALISMAN ENERGY FIRST QUARTER CONFERENCE CALL TRANSCRIPT

Transcription

1 TALISMAN ENERGY FIRST QUARTER CONFERENCE CALL TRANSCRIPT John Manzoni, President and CEO Ladies and gentlemen, thank you for joining our call today. As usual, I am joined by the management team here in Calgary who will help to answer your questions after Scott and I have given you the main points. A word about the commodity price outlook as context to what I shall talk about in terms of our capital program for the year. Gas prices here in North America continue to reflect the combination of oversupply and an unusually warm winter and have remained below what we believe to be a necessary long-term equilibrium price. However, with the injection season now upon us, it s quite possible this gets even worse before it gets better, and we have adjusted our capital plans accordingly. There are some early voices of optimism that the coal switching which has occurred over the last quarter will play a role in accelerating a recovery but I don t think anyone is expecting positive news until at least the end of this year and we need to be ready for this to last well into Oil prices have been strong, and we believe Brent will continue to be underpinned at the $90 to $100 per barrel range. We should expect some volatility around that, just as we re seeing today on the upside as a result of geopolitics, but as a base projection, we remain comfortable in the $90 to $100 range. Turning to the first quarter, we had a strong quarter in terms of operating results. Production was very strong at 462,000 barrels a day, 4% above the equivalent quarter last year and underpinned by a very strong quarter in both North America, which was driven by the shale being about 50% higher than a year ago, and by Southeast Asia which had a record gas production quarter delivering 136,000 barrels a day. Cash flow was up 5% over the first quarter last year. Prices and volumes were up, but were offset to some extent by higher taxes and higher costs. Earnings from operations were $167 million for the quarter, reflecting higher prices, but also higher costs than a year ago, and a higher DD&A rate which Scott will explain in a moment. Costs were down from the fourth quarter last year, when you may recall we had significant shutdown activity, particularly in the North Sea but they are up on the equivalent quarter a year ago. This reflects in part increased activity since that time for instance, we have new operations at Kitan in Australia, Jambi in Indonesia, and Equion in Colombia. In North America we ve also flowed through the new Pennsylvania impact fee which this quarter includes a historical component. If we exclude the historical part of that impact fee, we continue to see a trend of reducing unit costs in the shale business. In the exploration portfolio, we have found a significant oil leg in the Kurdamir-2 well in Kurdistan, which is sufficiently encouraging for us to plan an appraisal program on the structure. It s early days, but 1

2 we are very encouraged by what we see so far. And in Papua New Guinea, our exploration wells continue to turn up what we expected which is that the structures we re drilling tend to be full to spill. The latest well, Ketu-2, was another very positive result, and is building on our gas resource exactly according to plan. In Colombia, it s a little slow as we wait for the authorities to grant the relevant operating permits but we are making progress and I expect through this year we will see increasing news flow. In Vietnam we have started drilling the Ngoc Thach exploration well in block 5-2 in the Nam Con Son basin. We wrote off the unsuccessful Situche Norte well in Peru. We hoped the well would more or less double the commercial reserves we already have in Peru, but it didn t work. We are reviewing how to proceed in Peru in light of that result, and will finalize our plans in the next quarter. We have had a good start to the year with disposals, and have secured about $1 billion so far. This is about focusing our portfolio. We continue to examine options in the North Sea, including the dilution of some of our big redevelopment projects there, and I have also said we ll look at our exploration portfolio. As I ve just mentioned, we have recently drilled dry holes in Peru and South Makassar, and we are in the final stages of determining our forward plans for both places. I am confident we will achieve our original objective of $1 billion to $2 billion as we go through the rest of the year. Another highlight of the first quarter is that in our Asian business, we are very close to announcing the award of operatorship of an existing producing asset. This will build on our existing business with immediate production and cash flow, and we see opportunity to add significant value upside through further investment. It s an asset which allows us to do what we do well, which is to maximize recovery and value from relatively mature fields and I hope we can give you more details on this in the very near future. I indicated at the start of the call that we have taken further steps to reduce capital in light of the depressed gas price. I see no reason to continue spending money in dry gas shales when it doesn t remunerate. So, at our fourth quarter call, we said we would reduce spending on exploration and development to just above $4 billion, and that corresponded to running three rigs for instance in the Marcellus. We have now reduced that further to a single-rig program in the Marcellus, and in fact we are at that level today. We are now projecting capital expenditure on E&D activities for this year at around $3.6 billion. Dry gas spending in that figure is at a minimum and, looking forward, will be only a couple of hundred million dollars. We are holding land where we need to, because it makes sense to retain our position in the best dry gas plays for another day. In the Montney, we re running a four-rig program to continue to delineate the play and we have agreed a sensible program there with our partners Sasol, who are paying most of the capital. We are continuing to build operational momentum in the Eagle Ford and are currently running 12 rigs and two dedicated frac crews. Drilling performance is improving all the time, and we expect to hold 12 rigs through the rest of this year. And we have not changed our plans in the Duvernay, where we will complete a six-well pilot program through the remainder of this year. In our fourth quarter call in February, I gave you guidance that, as a result of our reduction in spending on currently uneconomic dry gas, we would grow like for like production during 2012 somewhere between 0 and 5% off the 2011 outcome, which was 425,000 barrels a day. Since then, we have reduced dry gas 2

3 spending even further and, while I don t believe we need to change our guidance, we are now clearly at the bottom of the 0 5% range in underlying growth. The actual outcome for the year will depend on the asset sales we make, and their particular timing through the year. From the assets we have sold so far, we have probably sold about 5,000 barrels a day for the year. Liquids or liquids-linked production will be a little over 50% of the total for the year as a whole, and we ll see year-on-year liquids growth in North America business from the Eagle Ford and in Southeast Asia as a result of contributions from Jambi and Kitan. I should just mention that despite a very strong start to the year in terms of production, the middle two quarters will be lower due to the normal planed turnaround activity so hence we are maintaining our original guidance for the year. Now, turning to the Yme project in Norway. At the last call, I noted I would have more information at the end of the first quarter. What s been happening on the project is that we ve been completing our own, independent studies to assess what is required to complete the platform. These studies are part of the normal handover process between the contractor who built the platform, and us as operator of the licence. It s been something of an evolving story, because we have been progressively understanding the shortfalls of the platform as constructed against Norwegian standards. A majority of those studies have now been completed, and the main conclusions shared with both our partners in the project and SBM, who built and incidentally owns the platform. They indicate a substantial amount of work is needed to put the platform in a state of compliance. Up until now, we have been trying to assist SBM, within the constraints of the EPC contract. We have had considerable numbers of engineers and technical teams present and working alongside SBM. In light of the conclusions of the studies I have mentioned, we believe the best route now is to allow SBM to complete the work independently as per the original contract. We ll reduce our own presence alongside their teams, both onshore and offshore, of course maintaining sufficient manpower in both places to discharge our proper responsibilities as license owner. We ll also remain available to assist them as they detail a work program which delivers a compliant platform which is ready to be handed over to us as operator. Last quarter, I took Yme production out of Until such a time as a plan to complete a platform which meets specifications is defined and agreed as workable, I have decided to completely remove Yme from our forward projections. In parallel, we are examining all options to get the development completed. I fully expect our medium term growth guidance of 5 10% will remain valid despite removing Yme. We have also decided it is prudent to take some writedown on the project, mainly because it will now be later than we originally projected and costs will increase. The project was on our books for just under $900 million and we have included in our first quarter results a writedown of $250 million after tax to reflect a delay, and our best judgment today of a range of outcomes. So, progressively over the last two quarters, we have removed Yme completely from the forward projections and insulated our balance sheet to the extent we believe prudent. We will now move forwards with Yme being fixed on the side so to speak. There is obviously considerable complexity in this, 3

4 including the performance of the contractor and compensation for what has happened. I suspect that will take considerable time, and will be quite separate from our continued intent to get the platform working and producing oil. Now ladies and gentlemen, let me turn to Scott to provide some more detail on the first quarter before going to your questions. Scott Thomson, Executive Vice-President, Finance, and CFO Thanks, John. I ll review our results, balance sheet, disposal activity during the quarter and our hedging position. Cash flow in the period was approximately $850 million, which was 5% higher than the same period last year and 3% higher than the immediately preceding quarter as higher oil prices and a smaller realized loss on held-for-trading financial instruments were partially offset by higher operating expenses and lower North American gas prices. Cash taxes were higher than in the fourth quarter of 2011 as a result of higher taxable income in the UK and Southeast Asia, but were relatively unchanged compared to the first quarter of Non-GAAP earnings from operations of $167 million were approximately the same as the first quarter of 2011 and $50 million higher than the previous quarter and were impacted by lower dry hole expense, lower exploration expense and higher DD&A. Similar to a year ago, both cash flow and earnings from operations in the quarter were impacted by the timing of liftings. You ll recall that, in the company s international operations, the results are influenced by the timing of crude oil liftings, which cause inventories to increase or decrease from quarter to quarter. During the first quarter, we experienced an inventory increase of 550,000 barrels arising mainly in Norway, Algeria and Australia. Had this inventory been lifted before the quarter-end, cash flow and earnings from operations would have been an estimated $46 million and $31 million higher, respectively. Net income in the period was approximately $290 million compared to losses in both the first and fourth quarters of In addition to the items noted previously, the principal factors contributing to this result were the gain on disposal arising from the sale of non-core coal assets offset by the writedown taken on the Yme project. As John noted, the completion during the first quarter of various studies of the Yme project and the knowledge that it will now be delivered later than projected and likely at an increased cost, has led us to conclude that a writedown of its carrying value is appropriate. Accordingly, we recorded an impairment expense of approximately $980 million in respect of Yme during the quarter which, at the prevailing Norwegian tax rate, is approximately $250 million after tax. The remaining book value associated with the company s investment in Yme is approximately $630 million. The realized price in the quarter of approximately $65 per boe was relatively unchanged from the first quarter of While the realized oil and liquids price increased by 11%, the realized natural gas price decreased by 12%. Netbacks were 9% lower than in the first quarter of 2011 due principally to increased production in royalty paying jurisdictions and higher opex per boe. Although netbacks were lower in North America, as a result of lower gas prices and higher operating costs, they were higher in all other areas of the business. 4

5 I d like to take a moment to provide some colour regarding the operating expenses and DD&A trends. Operating expenses of approximately $580 million were $125 million higher than the first quarter of There were four broad reasons for this. First, increased activity in Colombia and Southeast Asia, with new operations at Kitan and Jambi Merang. Second, the Pennsylvania impact fee came into effect, which resulted in a charge for the quarter of $21 million, of which $18 million was a one-time impact resulting from the retrospective application of the legislation to wells drilled pre Third, the movement in unlifted oil volumes added approximately $35 million relative to last year, since the inventory increase in the period was less than in the corresponding period in The remainder of the increase arose from an increase in maintenance activity in the North Sea. Unit operating expenses increased by 10% over the same period last year reflecting increases in North America and the North Sea. North America unit opex was down 40 cents per boe after normalizing for the one-time retrospective element of the Pennsylvania impact fee, which added $1 per boe to the unit rate in the quarter. The underlying trend is a continuing decrease in the North America rate. The increase in the North Sea rate relative to the first quarter of 2011 was the result of higher maintenance and lower production. Operating expenses decreased by $54 million relative to the immediately preceding quarter as the reduction of maintenance costs in the North Sea and Southeast Asia exceeded the impact of the Pennsylvania impact fee and increased activity in the Eagle Ford. Unit operating expenses benefited additionally from increased production. DD&A expense of approximately $600 million was approximately $130 million higher than the first quarter of The increase in activity in Colombia and Southeast Asia again contributed to the increase, as did the movement in unlifted oil volumes which added $25 million to DD&A in the quarter. The remainder of the increase was the result of rate increases resulting from reserves revisions in the fourth quarter of Compared to the fourth quarter of 2011, the $57 million increase in DD&A was due to increased production, a full quarter of Kitan and rate increases. Total capital expenditure for the quarter, including exploration expensed, was $1.1 billion of which $1 billion was associated with exploration and development activity. Approximately $600 million of this amount was spent in North America, $230 million on North Sea development, $70 million on Southeast Asia development and $70 million on international exploration. For the rest of the year we expect the runrate in North America to reduce quite dramatically given the reduced activity in the Marcellus. As John noted, we have made good progress towards our disposal target of $1 billion to $2 billion. We completed the sale of a non-core coal asset in the first quarter for proceeds of $500 million and expect to complete the sales of our non-core Shaunavon and Whitecourt assets during the second quarter for a further $450 million. At March 31, we had net debt of $4 billion, compared to $4.5 billion at December 31, 2011 reflecting the disposal proceeds received in the quarter. Available borrowing capacity at March 31 was $3.2 billion. Turning to our hedging program. During the first quarter, we had just $9 million of cash outflows associated with our hedging program, compared to $47 million in the first quarter of 2011 and $39 million in the immediately preceding quarter, since our out-of-the-money hedges rolled off at the end of In 2012 we have 50,000 barrels per day of oil hedged in the second quarter: 30,000 barrels per day are hedged in 90 by 150 collars, and 20,000 barrels per day are hedged in 90 by 125 collars. In the third and fourth quarters we have 30,000 barrels per day of Brent hedged: 20,000 barrels per day in 90 by 150 collars, and 10,000 barrels per day hedged in 90 by 120 collars. 5

6 We have no gas hedges in place for 2012, and no hedges in 2013 to date. Those are my highlights. I ll turn the call back over to John. John Manzoni, President and CEO Thanks, Scott. Ladies and gentlemen, just before your questions to summarize the quarter. We had a very strong operating quarter, with great production, which sets us up well for the year. We have reduced our capital plans further, with only a very small proportion drilling dry gas in the current environment and despite that we ll hold our production guidance for the year, although clearly we expect to be at the bottom end. We have made great progress in terms of focusing the portfolio with $1 billion already sold this year and more to go. We have discovered oil in Kurdistan, and our PNG program is also going well. Still to come this year will be more results from Colombia, and some interesting wells offshore Vietnam. In Malaysia, we have been awarded operatorship of the Kinabalu field at the end of the existing PSC towards the end of this year. The field is producing today, it ll create a hub around our Sabah exploration activities, and we are looking forward to increasing recovery and value from the field. And we have put the Yme project to one side and will build our forward plans to exclude it until such time we decide how to progress. I think that s enough from us. And now to your questions. 6