Obsidian Energy Ltd (OBE) 2004 Q4 法說會逐字稿

Welcome to the Penn West Petroleum Fourth Quarter Results Conference Call. (Operator instructions). I will now turn the call over to Mr. William Andrew, President of Penn West Petroleum. Please go ahead, Mr. Andrew.

Thank you, and thanks to everyone who is on the conference call as well as those who are listening to the webcast. In Calgary today I am joined by our executive team that includes Don Rae and Dave Middleton, two of our SVPs; Gerry Elms and Phil Reist who look after our finance and accounting; Thane Jensen, our VP of Exploitation; Bryan Clarke, VP of New Ventures; Christian Kang and Randy Woods who look after marketing and land.

The purpose of this conference call is to review our 2004 fourth quarter and 2004 year end results, as well as to provide an update on recent activities in the Company. Following this review we would be pleased to answer any of your questions. We will note at the start that certain 2003 comparative figures have been restated to reflect a change in accounting policy and the accounting reclassification. For more details please look at note 2 on the consolidated financial statements. During the presentation we'll be using Canadian dollars except where noted, and a 6:1 conversion ratio for the conversion to barrel of oil equivalent.

During the fourth quarter of 2004, Penn West drilled 70 net wells, focusing on development drilling in our Semptimum Plains areas. For the year ended December 31, 2004 we drilled a total of 417 net wells, resulting in 197 natural gas wells and 188 oil wells. This compares with 713 net wells drilled in 2003.

In the fourth quarter of 2004, average daily light oil, conventional heavy oil and natural gas liquids production volumes increased by 14 percent compared to the fourth quarter of 2003. The fourth quarter of 2004, our light oil and natural gas liquids production averaged 34,524 bpd; conventional heavy oil production averaged 19,257 bpd. That is a total of 53,781 bpd.

Average natural gas production for the fourth quarter was 307.5m cfpd, that is a 2 percent decline over the same period in 2003. Total production for the fourth quarter of 2004 averaged 105,000 bpd/e of oil. That is an increase of 6 percent over the fourth quarter in 2003. Total production for the year averaged 105,788 bpd/e of oil. That is an increase of 4 percent over 2003.

Commodity prices were up in the fourth quarter of 2004 and higher than in the fourth quarter 2003. Natural gas prices averaged $681 per mcf, that is up 20 percent over the same period in 2003, while our light oil and natural gas liquids prices averaged $52.67 per barrel. That is a 42 percent increase over the fourth quarter of 2003.

Conventional heavy oil prices were also higher in the fourth quarter of 2004 compared with the same period last year, averaging $29.89 per barrel. That is up some 25 percent from $23.96 per barrel in fourth quarter 2003.

With higher commodity prices in the fourth quarter, gross revenues compared to the same period last year increased by 29 percent from $310.5m in 2003 to $400.5m in 2004.

Operating costs for the fourth quarter of 2004 increased 8 percent to $7.94 per barrel of oil equivalent. That compares with $7.35 per barrel of oil equivalent in the fourth quarter of 2003. Operating costs were impacted by increases in costs of energy and services and in general, an increased industry demand for services. The operating costs have also been impacted by our move from a little bit away from gas towards oil. During 2004, average daily liquids production increased to 50 percent of the Company’s total production. That compares with 46 percent in 2003. So we basically shifted about 8 percent of the production around from gas to oil during the year.

It is important to note that a significant portion of our liquid production is light oil, which commands a premium price, thus the Company can absorb higher operating costs for light oil and still maintain high operating netbacks.

Our netbacks in the fourth quarter were $25.18 per boe, that includes hedging losses of $1.28 per barrel. That is a 23 percent increase over the fourth quarter 2003 netbacks of $20.50.

Cash flow from operations in the fourth quarter of 2004 reached $237.8m. That is a 23 percent increase over the same period in 2003. Net income for the fourth quarter of 2004 was $68.6m, that is up from net income of $38.8m in the fourth quarter of 2003.

Provisions for our income tax increased by 19 percent for year end 2004, to $127m from $107m in 2003. A non-recurring future income tax benefit of $20m was recorded in 2004, and that reflects the tax rate reduction enacted by the government of Alberta in May of 2004. This compares to a non-recurring tax income benefit of $100m reported in 2003 and I think if you remember, that was primarily a federal change.

Provisions for income taxes in 2004 includes current tax payable of $18m which is 80 percent higher than the $10m paid in 2003 and that is a result of increased taxable income in the year.

Capital expenditures for the year were just under our cash flow from operations and totaled $865m. They included $533m spent on conventional exploration and development, and $332m spent on property acquisitions. For the same period in 2003, capital expenditures were $608m, most of the money in 2003 was spent on exploration and development.

For year end 2004, our proven reserves of oil and natural gas totaled 309m boe. That is up from 306m boe at the end of 2003. Our proven reserves of crude oil and natural gas liquids totaled 202.3m barrels at year end 2004. That is an increase of almost 7 percent year-over-year. Proven reserves of natural gas totaled 637 bcf at year end. That is a decrease of 8.7 percent. Our negative proved reserve revisions totaled 11m boe with the majority of the revisions taken on previous gas reserve calculations.

Probable reserves at year end 2004 of 67.9m barrels, and that represents about 15 percent of our total reserves. Netbacks for fourth quarter were 25.18 per boe. The components of that are our average light oil, liquid netback of 25.96 per barrel. Average conventional heavy oil netback of 7.15 per barrel, and average natural gas netback of 4.61 per barrel. As I noted before, the netback includes hedging losses in the case of our liquids and a very minor hedging gain in the case of natural gas.

At the end of 2004 our bank debt was $503m, that compares with $442m at year end 2003. Over the past four years we have funded our growth largely through internally generated cash flow.

Moving into this year, for the first quarter of 2005, our targeted capital spending is based on a business as usual approach, and we are forecasting at approximately $260m which would yield roughly 260 net wells. We have experienced some cold weather in January and anyone who looks outside in Western Canada right now is aware that the weather is unseasonably warm right now. So we are pushing to get as many of the wells drilled as we can and get them tied in. The main development area, particularly for gas in the winter, is Wildboy and Firebird and we are proceeding on schedule there and will get our work finished. We may end up shutting down some of our drilling a little early in the plains area.

Based on commodity prices of USD $39 per barrel WTI, and USD$6.25 per 1,000 btu of NYMEX natural gas and a currency exchange rate of 80 cents, we are forecasting cash flow of $800-850m in 2005. On average, we have 70mcf/d of natural gas hedged for the first quarter of 2005 with an average floor price of 770mcf, and a ceiling price of $14 per mcf. So we are slightly positive on that hedge right now.

On the power side, starting in 2005, we have an average of approximately 50 megawatts per hour hedged over the next three years at an average price of just under $45 per megawatt. Again, we are slightly to the good on that hedge. We don’t have any hedges in place for our liquids production currently. If you want additional details on our hedge, please consult with our corporate presentation on our website. The web address is www.pennwest.com. There you will see all the tables outlining our hedging numbers and forecast in more detail.

Going forward, focusing on our five core areas and continuing to generate economic prospects through acquisitions, exploration, exploitation and development. We have initiated pattern expansion of our hydrocarbon miscible flood at Swan Hills and are continuing to work on that. As well, we have started or are about to start a carbon dioxide injection at our miscible flood pilot scheme at Pembina. I say have started it – it is about to happen today, so as we speak it should be occurring. The carbon dioxide miscible flood scheme is a cooperative effort of Penn West and the Governments of Canada and Alberta.

Following the annual special meeting of shareholders held August 20, 2004, the Company announced that the board of directors recommended that all of the assets of Penn West be converted into an income trust, contingent on receiving a satisfactory advance tax ruling from the Canada Revenue Agency regarding certain tax consequences of converting into an income trust. To date, an advanced ruling has not been issued by the CRA. Penn West’s legal counsel are actively continuing with this process to obtain a ruling as quickly as possible. In the interim, we are using a business as usual strategy and we are striving to continue to provide our shareholders with an efficiently operated company.

I thank you, and operator, we would be pleased to answer any questions that the audience may have.

Thank you. (Operator instructions) Stephen Calderwood - Raymond James.

Yes, please, Bill. Thanks for taking my questions. The nature of the technical revision in the proven natural gas, can you expand on that?

Certainly. Two main areas. We had a couple of properties booked on gas that were too far away in terms of distance, too far away in terms of the future to keep them on the books any longer, so we took those off the books. They were primarily in Northern British Columbia and about 35-40 miles away from any existing pipeline. We looked at it, we looked at the economics, and it didn’t make sense to keep those reserves on the books.

The other revisions, we took some revisions in our Northern Shallow Gas in the [Suze] area and in [Title] Prairie. Obviously I agree with the revisions that were made, however I would temper that with the fact that we had been basically unable to access those resources for about two years because of an ongoing dispute with the First Nations in the area.

Recently a major step was taken towards resolution of that, with a judgment by the Alberta courts that backed up, the AEUB in Alberta and also backed up the process that we had been through on consultation. We are anxious to get back into that area. It is probably too late this year, but next year we are anxious to get back in there and get things straightened up.

Excellent, thank you. On the C02 flood, you mentioned it. I am interested in two things. What reserve additions do you expect from C02 flood at the end of 2005, and what do you mean with the statement by a cooperative effort by the Canadian Government and the Government of Alberta?

We would be booking minimal if any reserves at the end of next year on C02. The pilot is planned for two years. We’ve increased the density on our well spacing so we are expecting some reasonable data by the end of one year. When I say cooperative effort, there is money available at the federal level, as I think most people know, with regard to sequestering of C02 and also new technology. We are taking advantage of that program.

As well, the Province of Alberta has a very similar program on new technology, enhanced recovery in C02 sequestration. So we have received support from both levels of government on this project. If you look in the federal budget, there is at least a paragraph regarding C02 and the C02 infrastructures behind this plan for Alberta.

Thanks, Bill.

Your next question comes from Christopher Steel; Tristone Capital.

Good morning, Bill. A couple questions for you. In terms of Q4, the $101m acquisitions in terms of the capex. Can you give us some color in terms of production reserves acquired, and where?

I won’t give you any color on reserves, I’ll give you some idea on production, and where. Principally the properties acquired were acquired very late in the quarter. They were primarily Southern Alberta, a little bit in Southwest Saskatchewan and the metrics on the deal were, I thought, reasonable. I won’t go any further than that because we are still in the process of doing the final closing on them and I will respect the confidentiality with the vendor.

And in terms of capex this year, the $260m for Q1. In the E&P mode of things, would you expect to spend cash flow for the full fiscal year, if that is the course?

I don’t know. Obviously one of the difficulties of operating with a defined agenda in terms of our strategic alternative, our feeling was to go forward with the first quarter because we thought that the likelihood of us converting to a trust was basically receiving the satisfactory ruling and doing the conversion, wasn’t likely in the first quarter because of the time that is involved after we decide to go.

So we went ahead with the first quarter. Now we are obviously getting into a time and place where we are looking at the second quarter of activity. My thought is that it will probably be business as usual, but I also have the thought in the back of my head that we will temper the second quarter a little bit in terms of a full E&P program.

In terms of just looking back in ’04, backing out acquisitions, about half a billion spent on drilling, 3m BOE added on a P+P basis. Can you comment on drill bit efficiency and what happened last year and what changes looking into ’05?

I will look at basically the whole spending within the Company. When you break it down, I feel that we were as efficient as we’ve historically been on acquisitions. I feel that we were quite efficient on in-field drilling and that we were quite efficient on optimization of either assets that we acquired during the year or previous assets.

That was offset and not quite completely offset, but that was offset to some extent by our cost that we incurred in drilling. We are disappointed and continue to be disappointed with our drilling results.

What have we done for 2005? We have basically just tightened the rope up a little bit in terms of prospects that we are looking at drilling. We’ve tried to take even more risk out of the equation, go back and concentrate primarily on in-field drilling, look at the opportunities – and we have many opportunities for horizontal drilling – in the Company. So we are doing a lot of that.

Just to round out, what would be current production?

Our current production is about 104,000 bpd.

104,000. Last question: do you have a number of land value from an independent evaluator yet?

We have gone through that process and we do have a land value.

Can you provide that?

Not right now.

Okay, thank you.

Your next question comes from David All; DLA Analytics, Inc.

Good morning, Bill. A couple of questions. Just kind of a follow-up, I mean, my understanding was before the strategic alternative was mentioned, that you had a pretty good quarter in 2004 in adding reserves up in the Northern Territories, that is Wildboy, Firebird. But if I look at this, you drilled 385 wells. If I take your gross additions and revisions and everything, it looks to me like your average was 50,000 barrels a well, at $1.4m per well. That is not what we were hearing last year.

Is it just a combination that your results have come out to be more disappointing, or your reserve auditor is being very, very cautious about reserve additions? I have a couple of other questions, but why don’t we just start with that one first?

The first one is a dandy anyway, so we will start with that. I think people who know me know it is not my habit to spread disinformation or misinformation. I felt that we had a reasonable first quarter last year in terms of Wildboy and Firebird and the production adds. If you look at our reserve report, we’ve done a bit of a reconciliation. Part of the bang on the gas reserves was about 480 plus BCF reduction in terms of revisions. I would compare that against companies that are much larger than ours and it is a significantly larger revision in terms of percentage and it is basically, on an absolute basis, it is as large a revision as I’ve seen in some companies that are substantially larger than we are.

So we are still struggling with the drill bit and we struggled with the drill bit in 2003; we struggled a little more in 2004. I felt that 2004 was better, much better than 2003. 2003 we basically had no luck with the drill bit. 2005 I felt that our first quarter was much better. 2004 I felt that our first quarter was much better than ’03. However, as you have observed, we can do a better job and we have to do a better job.

So basically you drilled a lot of in-field wells and you didn’t get – low risk, but low return wells?

We are currently drilling a lot of in-field wells in 2005.

Now just two other quick questions. Have you secured a long-term C02 supply for the Pembina C02 flood project? There is a brief mention in the earnings document, the release, that you may look at other strategic alternatives. Was this referring to the strategic options going into the year in terms of acquisitions, or is there a possibility that the CRA won’t give you approval for –

I will handle the first one. We have signed confidentiality agreements with a number of potential suppliers for C02. We are currently very, very involved with one potential supplier to the point of detailed engineering and cost planning as well as detailed submissions to a couple levels of government.

Our feeling is that there will be a supply of C02 available to Penn West to go through with this project and that the timing will be within some of the guidance that we have given before, which was in the 2008/2009 timeframe.

The second part, and I am not going to dwell on it a whole lot, and that is on the strategic alternatives. I think we have been very clear on the direction that the company intends to take. The board of directors accepted a management recommendation in August that we convert all of the assets of Penn West to an income trust. We went forward to our annual meeting with a resolution that we would do the same, with a caveat that we obtain satisfactory advance income tax ruling from the Canada Revenue Agency.

We have been at that for the better part of a year now, and as we said in our press release, we are diligently working for this. We feel that we have made good progress and we are moving forward with the advance tax ruling. Our bottom line and our belief is that in securing this advance tax ruling we are not only working in the best interest of the existing shareholders, but also in the best interest of future unit owners of Penn West Trust. So we are absolutely committed and moving forward with that process.

We talk about other strategic alternatives because you have to look at the eventuality or the possibility – I shouldn’t say eventuality – the possibility that the income trust wouldn’t be a conversion, wouldn’t be an alternative. I am not going to speculate on the chances of that, but it is just language that has to be put into our release.

Thank you very much, Bill.

Your next question comes from Ryan Shay - Sprott Securities.

Good morning. On your cash flow guidance for 2005 of between $800-850m, how much do you have in there for cash income taxes?

I am going to avoid your question, Ryan. The principal reason is sort of the point we are at on the strategic alternatives, that we are treating any tax estimates as confidential. That is part of the ongoing ruling process we have with the CRA, and also the taxes will change on adoption of a strategic alternative, the tax situation will change in the Company. I don’t think I am in a position right now to speculate on tax payable.

But in that $800-850m you put out as guidance, presumably there are some cash income taxes in there?

No.

So that is a pre-tax number?

Yes.

Okay. And where do you think production will be coming out of the winter time into 2Q?

We think we will be somewhere around 107-108,000 boe a day.

Just to ask the last question, for the purpose of calculating finding costs under NI 51 101, we need the future development capital or the change in future development capital. Can we get that number?

I will let Gerry dig it up here and I will continue on with other questions. I will just throw that out in a minute, if that is all right.

Just to clarify again, that $800-850m of your ’05 cash flow guidance is a pre-tax number?

Pre-income tax number, yes. Ryan, the number is $397m on future development costs, of which $170m are in 2005.

Your next question comes from Roger Serin; TD Newcrest.

Good morning, Bill. All of my questions have been answered with the exception of one. I noticed in the past when you have addressed the issue of your strategic alternatives, you’ve added the phrase ‘if a satisfactory advance ruling is not granted, Penn West will continue to operate under the other strategic alternatives available to it.’ And that was missing, from what I can tell, in the press release of today. Is there a reason for that or am I just reading too much into it.

Another good question. Maybe we forgot, but I think we are just getting deep into this process now. We are focusing on what we hope will be the logical conclusion that we move forward with what we had proposed in August.

I’ll ask one additional question if you don’t mind, Bill. On capital programs, you have indicated acquisitions and in-field drilling and optimization have been quite effective. For 2005 capex, how much of – if you were to spend your cash flow for argument’s sake – how much of that would have to be exploration and how much would be the other side? Lower risk?

What you are asking is if we flipped over to a trust, how easy would it be to throw the switch?

It is sounding a lot like a trust to me.

Yes, the facilities budget was about $100m for the year, drilling was, [inaudible] inflation is about $325m. That would be, the opportunity to temper that somewhat. Our acquisitions we generally budget at around 15-20 percent of total capital so it is around the $100m mark.

We already have trimmed our land budget from last year and the year before. We would obviously continue with optimization on the environmental side and we continue to commit money to the C02 and also to our water flood. I guess where there could potentially be some change would be on about $450m that is tied up in drilling completions and facilities.

Thanks very much.

Your next question comes from Dave Ednar, Globe and Mail.

I wonder if you can shed any light on what is taking so long? Is it a particular point that is stalling the process or is there a number of points? Any color you can provide vis-à-vis what the government is thinking?

I should answer the question with a brush-off, but I won’t. It has been almost a year. This is a very large company with a partnership structure. The conversion, basically the restructuring of a company like Penn West into an income trust is a significant event. A lot of money involved. I guess my sense is that the people that are working on behalf of the citizens of Canada in Ottawa are trying to do the best job that they can, and our staff and our legal counsel as well are trying to do the best job they can for the shareholders of Penn West. So it is an evolved process. As we said in the press release, we are diligently continuing with the process.

Okay, then. One other one. CSFB came out with a report I think two weeks ago now on the trust market in general, basically calling the whole thing a [pomsey] scheme. I was wondering what Penn West thoughts are on that kind of comment which is bouncing around out there, anyway, given that you will be the largest conventional trust?

Everybody is entitled to their opinion. As I said before to a number of people and have said before publicly that there are well-run conventional oil and gas companies, there are less well-run conventional oil and gas companies. There are well-run trusts and then there are trusts that are less than well-run. Our intention in running Penn West as a trust is to give the same commitment that we’ve given over the past 12 years running it as an E&P company. We feel it is a viable alternative for the Company. We feel there is certainly some movement on behalf of our shareholders to look at this alternative, which we have done and we have recommended that we go there. I don’t believe that we would have made the recommendation as management and I don’t believe our directors would have endorsed the recommendation had they felt it was a [pomsey] scheme.

Okay, great. And actually on the point of ownership question, which happened in December, it looks like the government has backed off quite a bit. But in terms of risk to potential – if Penn West becomes a trust, how big of a risk is that in your mind, the idea that foreign ownership could be capped?

I don’t think it is a huge risk. I don’t really consider it a large risk.

Thanks.

(Operator instructions) Your next question comes from Matt McKisick, MMCAP.

Have you guys looked at the option of listing in the U.S. if you do decide to convert into a trust? One interesting play that is out there is the Penn Grove which has listed in the U.S. and is getting a much higher premium for their U.S. listed shares over their Canadian listed shares. That might bring more value to the Company.

We haven’t given any consideration to that currently. That is always an alternative for the future.

Okay, thank you.

Mr. Andrew, there are no further questions at this time. Please continue.

Well thank you all very much. I am about to get on an airplane and go to New York to give a speech tomorrow, if we can make it down there. I do thank you. If there are any calls, any questions that you have, you can leave a voicemail with me and I will certainly attempt to answer them. Also, Gerry Elms will be available to answer your questions via the voicemail. Thank you very much.

Ladies and gentlemen, this concludes the conference call for today. Thank you for participating, please disconnect your lines.