Enerplus Corp (ERF) 2010 Q2 法說會逐字稿

Good morning. My name is Sara and I will be your conference operator today. At this time I would like to welcome everyone to THE Enerplus Resources Fund second-quarter results conference call. (Operator Instructions). Ms. Caza, you may begin.

Thank you, operator, and good morning everyone. I would like to welcome you to Enerplus' 2010 second-quarter conference call. Gordon Kerr, our President and CEO, will be summarizing the results of our second quarter in more detail, and giving some additional information on our strategy going forward. To help answer some questions at the end of the call today we also have Ian Dundas, our Executive Vice President, and Rob Waters, our Senior Vice President and Chief Financial Officer.

Before we get started, please note that this call will contain forward-looking information. Listeners should understand the risks and limitations of this information and review our advisory on forward-looking information found at the end of the second-quarter news release issued this morning, and included with our MD&A and financial statements, which are filed on SEDAR and EDGAR and available on our website at www.enerplus.com.

Participants are also directed to our website for replay of this call, as well as other information on Enerplus. Investors may also call our toll-free Investor line at 1-800-319-6462.

All financial figures referenced during this conference call are in Canadian dollars unless otherwise specified, and all conversions of natural gas to barrels of oil equivalent are done on a 6 to 1 conversion ratio.

Following Gord's review we will open the phone lines and answer any questions you may have. I will now turn it over to Gord.

Well, thanks Jo-Anne, and good morning everyone. First of all, let me say I'm very pleased with our results and the progress we have continued to make on a number of our strategic objectives so far this year.

I think the key takeaways from the quarter are production is meeting expectations. Op costs are lower than expected, and we are reducing our guidance going forward. Capital spending is increasing by CAD60 million as a result of the new opportunities we have added to our portfolio of assets, and this is largely on oil focused projects.

G&A costs are lower year-to-date than in 2009. We sold our first non-core conventional production package of 3,400 BOE per day for proceeds of CAD198 million. We bought 126,000 net acres of new land in the Bakken, Marcellus and the Deep Basin areas, and now have over 350,000 net acres of perspective land in these plays that will provide us with significant growth prospects for the future. Our Marcellus and Bakken drilling programs are showing excellent results that support or exceed our type curves. Our balance sheet is strong with a debt to cash flow ratio of 0.9 times.

So let me get into some of the details. Production volumes averaged just under 85,000 BOE per day for the quarter. Op costs were better than expected and decreased to CAD9.82 per BOE. We executed our development capital plans and spent CAD91 million drilling 19 net wells. Cash flow was CAD0.92 per unit, in line with analyst expectations.

We distributed 59% of our cash flow. And when we include development capital spending, our adjusted payout ratio was 115%.

Now on June 30 we sold our first package of assets representing roughly 3,400 BOE a day of production and 13 million BOE of proved plus probable reserves for approximately CAD198 million. Sales metrics were approximately CAD58,000 per flowing BOE and CAD22.83 per BOE of proved plus probable reserves.

This production was from 14 different properties with varied working interest located in central and northern Alberta and had operating cost of roughly CAD17 per BOE.

We expect to sell additional non-core properties in 2010 and into 2011. Also, we are on track with our plans to evaluate strategies for our Kirby Oil Sands interest, and we expect to provide additional direction as to the status in the back half of the year.

During the quarter we renegotiated our syndicated credit facility. And given the increasing costs associated with maintaining unused credit capacity, we elected to reduce the size from CAD1.4 billion to CAD1 billion.

At the end of a quarter only had CAD170 million was done against the facility. This capacity, together with additional planned proceeds from divestment activities, will continue to provide us with significant financial flexibility to support our capital spending plans and additional acquisition opportunities.

Now on the acquisition front we increased our working interests in Fort Berthold, North Dakota by buying out our partner's working interests. We added 14,000 net acres of perspective land, inclusive as of 1,100 BOE per day of early stage, high netback crude oil production from existing wells in the play. The total cost of the acquisition was $108 million.

We now have 25,000 net acres of undeveloped land in Fort Berthold for this perspective for the Bakken and Three Forks, with an average working interest of 95%.

Now Fort Berthold is located in Dunn County, which has some of the best economics and performance results for Bakken production in the state. We believe we can drill up to two Bakken wells per section through a combination of long and short length lateral horizontal wells.

This high-quality light sweet crude oil with expected average netbacks of over CAD55 per BOE based upon current commodity prices and operating cost below CAD5 per BOE. We expect significant production growth from this area in the coming years.

Also come in April we spent CAD117 million to acquire 154 sections or about 100,000 net acres of undeveloped land in southern Saskatchewan. These lands are in an emerging Bakken play area and are contiguous to our existing landholdings. So we now hold 100% working interest in 142,000 acres in the Freda Lake/Neptune/Oungre area. So in total we held over 180,000 net acres of undeveloped land in the Bakken/tight oil areas of Saskatchewan, North Dakota and Manitoba, which are in the early stages of development.

As a result of our acquisitions and investment activity and the capital opportunities associated with the new land, we heard are revising our 2010 operating guidance. Annual production volumes are now expected to average 85,000 BOE per day versus our original estimate of 86,000 BOE per day, and exit rates of 86,000 BOE per day versus our original estimate of 88,000 BOE per day.

So this guidance takes into account the expected declines on both purchased and sold assets, and again, does not include the impact of any further divestments or acquisitions we may make in the current year.

We also plan to increase our capital spending by CAD60 million to CAD485 million, with the majority of the increase on light oil projects. Approximately 63% of our total development capital this year will be invested in oil projects. As the increase in capital spending is occurring late in 2010, we expect to see a greater impact on production volumes in 2011.

We are also reducing our operating cost guidance. Given the lower cost we have experienced so far this year, as well the sale of higher cost non-core properties, we now expect operating cost will average CAD10.20 per BOE in 2010 versus our original estimate of CAD10.90 per BOE.

In the Marcellus we are seeing improving well productivity, and albeit it is early, lower than expected decline rates in a majority of areas. 21 gross wells were drilled in the quarter, another 15 wells were completed, and seven wells were tied in. Our average working interest in these wells is in the order of 20%.

The bulk of our activity has been focused in Bradford, Lycoming, and Susquehanna counties in Pennsylvania, as well as Marshall County in West Virginia. We currently have six rigs running in this play and may add a seventh during the fourth quarter. We are increasing the number of frac stages from an average of eight stages per well to 10 to 15 stages per well, depending on lateral length.

We also bought another 6,000 net acres of land that we will operate, and we now hold approximately 12,000 net acres in Center and Clinton Counties. We plan to shoot seismic in this area and drill our first operated well later this year.

28 gross wells are currently on production, 23 of which are horizontals and five verticals, with another 39 wells waiting on completion, and 11 wells waiting on pipeline. Completion activity remains somewhat challenging due to increased activity in the play. We do expect these conditions to improve, however, heading into the winter drilling season, as indications are that more crews and equipment are being added to this region by service providers.

Also, given the favorable summer weather, our midstream partners expect to make progress in building the gas gathering and infrastructure required to bring more of our wells on stream.

Looking at our Bakken/tight oil asset we are very encouraged by our drilling results in North Dakota and Montana. Unfortunately, we were restricted in accessing our new land in Saskatchewan due to extremely wet weather and a longer the anticipated spring break up. As the weather has improved, we have begun to move rigs back into the area. We could have up to three rigs running, and drill 10 to 14 wells by year-end, pending further evaluation of our early drilling results.

We drilled 3.5 net horizontal wells in the Sleeping Giant field in Montana during the quarter, and tied in another fourth. The wells we tied in had lengths ranging from 3,750 feet to 9,500 feet with 8 to 18 frac stages. We changed our completion techniques on these wells and the 30 day production rate are significantly better than our original type curve estimates.

Production has ranged from 275 BOE per day on the mid-length lateral wells to almost 1,000 BOE per day on the longer lateral wells. These rates are on average 75% higher than our previous estimate for an incremental cost of only 20%.

The Sleeping Giant field has been on production since the early 2000s, and it is at a relatively advanced state of primary development. There are still a modest number of drilling locations remaining in the field, and along with refrac and recompletion opportunities, which we are evaluating.

At Fort Berthold we drilled an additional well and brought on another four wells on stream in the quarter. 30 day initial production rates for these four wells have averaged approximately 800 barrels per day per well, excluding the associated natural gas, which is not currently being captured.

We are in the process of completing two additional wells, with the third well completed near term. And our plans are to drill an additional five wells over the balance of the year. Given the results we have experienced, as well as the additional interest we have purchased, we are allocating additional capital to our Bakken/tight oil resource play, and now expect to invest over CAD170 million of CAD485 million capital budget in this latest year.

With respect to corporate conversion, we still expect to convert into a dividend paying company on January 1, 2011, assuming unitholder approval. We do not anticipate this will be a taxable event for our unitholders, and intend to maintain our monthly distributions at current levels through the conversion, assuming the current commodity price outlook doesn't change significantly. Our conversion plans are well underway and proceeding as expected.

So to conclude, Enerplus is executing on the game plan we set out at the start of the year. We are becoming more focused and continuing to build our portfolio of assets in the key play areas that we have targeted. We are continuing our non-core asset disposition program and expect we will sell additional properties in the current year.

We have a sizable and stable production base from existing properties that provide cash flow to support both distributions to our investors and reinvestment into our asset base. Our financial strength remains a competitive advantage and gives us the financial flexibility to support our capital spending plans beyond the current year and pursue additional acquisitions.

With that, I will now turn it back to the operator to take any questions from the audience. And thank you for your attention.

(Operator Instructions). Gordon Tait, BMO Capital Markets.

A couple of questions. First of all, on the operating cost improvement, I understand that some of that was because you sold off some higher cost properties. But is there anything else that you're doing to bring operating costs down? Is something going on in some areas where it is more of a structural improvement?

We obviously over the course of the last year have taken a deeper look in our service providers, as well as how we are spending our monies, and again, some of it will be related to those non-core properties that have been sold, as well as ones that may be sold. So I think there is some structural improvement in there, as well as the impacts of moving out the higher cost properties.

Then secondly with these Bakken lands, particularly around Fort Berthold, those are pretty -- it sounds like pretty impressive IP rates and so on. You mentioned that you're looking at drilling intensity of about two wells per section. Now is that something you think you could improve on? Because it seems to me that there is some higher drilling intensities going on in different parts of that play, or at least near there.

These are early stage play developments. There is a lot of activity going on, not just with regard to how many wells can be put into a section, but as we also say in our release, we are also reviewing for the Three Forks potential. There is the extension of the laterals. There is how many stages you can put in. So there are a lot of things that are at play here relative to assessing the full development potential on these property interests.

Now, as I said, we are strongly encouraged by what we are seeing, and obviously that was a factor for us to increase our interest here. So we are going to be, obviously, drilling additional wells, as I said, and evaluating the results, and it will be a combination of what can you actually extract out of two wells per section, and also how many stages and then, again, what should be the length of these things. There is a lot of work that is ongoing, not just by us, but by others in this region.

Then, lastly, is it fair to say are you looking to balance out your production stream a little bit more? You have always been a little bit more on the gassy side. Are you deliberately trying to boost your oil weighting?

Again, we stepped into the Marcellus and over time I think, as we have said before, we expect to increase the production out of that area to about 100 million cubic feet per day over the next three to four years.

Having said that, certainly we look at our portfolio of assets from a commodity perspective. And I think as we look out and we looked at the oil production project that we have in front of us there could be an increase in the oil side of the equation here. But I think fundamentally we are going to stay within that 50% to 60% type of range on both of the commodities, so it could vary one way or the other.

(Operator Instructions). Andrew Fairbanks, Bank of America.

I know it is a little early to be talking about expectations for 2011, but do you have just any kind of general character of what the production levels would be or capital spending as you look out to firm up the plans post conversion?

Well, again, keep in mind with regard to production that we are planning to sell additional non-core properties. So that certainly is going to have an effect on the production. All I am really going to say at this particular point in time is that as we look out past 2010 with the portfolio as -- that we have accomplished here so far, if I see increased opportunity for capital spending -- and that is also why we talk about our financial flexibility on the strength -- that is not just what you see today, but what we see in the future. So at this point I think that is the only comment I would be prepared to make.

That's great, thanks. Then I guess the second question would be, are you seeing anything in terms of accelerating completion costs in the Bakken, or has that part of the capital program been fairly stable as activity levels ramp up here?

The activity levels have been high; they are continuing to be high. We are seeing increases in cost, but I think for us the key is while we are seeing some increase in costs, we are also seeing encouraging results, and maybe better than what we would have been projecting when we first stepped into these play areas, and putting aside the Sleeping Giant that we were already in, in Montana. So that is to be expected.

I think I said in earlier calls, even in the Marcellus, as activity picks up there will be competition for services. I think the thing of note is that the service providers, certainly they recognize the opportunity and they are doing what they can to move additional services into these developing areas.

That's great. Thanks.

(Operator Instructions). [Paul Meyerhoff].

The question I had would be in terms of funds from operation. Do you target what your distributions or dividends will be after the conversion? Do you have a target?

I think we have been quite clear that through the conversion process we are looking to maintain our distributions at the CAD0.18 per month, so that is in effect our target right now.

Okay, thank you. The other question I had was, what is your total acreage in the Marcellus?

We are holding about 136,000 net acres in the Marcellus.

There are no further questions at this time.

Well, operator, if there are no further questions, and given everybody, I'm sure, wants to get onto a busy Friday, I think we will end the call. So thanks to everyone who joined us this morning.

This concludes today's conference call. You may now disconnect.