Enerplus Corp (ERF) 2009 Q4 法說會逐字稿

Good morning. My name is Sarah, and I will be your conference operator today. At this time I would like to welcome everyone to the Enerplus Resources Fund 2009 year-end results conference call. (Operator Instructions). Ms. Jo-Anne Caza, you may begin.

Good morning everyone. I would like to welcome you to our 2009 year-end results conference call. Mr. Gordon Kerr, our President and Chief Executive Officer, will be relaying our operational results and reserves information in greater detail, as well as providing some color around our strategy going forward.

To help answer some of your questions at the end of the call, we also have with us Mr. Robert Waters, Senior Vice President and Chief Financial Officer, and Mr. Ian Dundas, our Senior Vice President of Business Development.

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 our year-end results news release issued this morning, and included within our MD&A and financial statements filed on SEDAR and EDGAR this morning as well. We also have this information 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. And investors may call our toll-free information line at 1-800-319-6462.

All financial figures referenced during this call are in Canadian dollars, unless otherwise specified, and all conversions of natural gas to barrels of oil equivalent are done are done on a 6 to 1 conversion ratio. Following Gord's review, we will open the phone line and answer any questions you may have. I will now turn it over to Mr. Kerr.

Good morning everyone. First of all, let me start off by saying that 2009 was a significant transition year for Enerplus, as we continued to move from the traditional income trust business model to a hybrid growth and income business model.

We focused on delivering our operational targets, repositioning our asset base, adding key leadership and technical skills to our organization, and balancing our distributions and capital spending with our cash flows. I'm happy to report that we have made significant progress with these strategies.

To help build our future growth potential we invested over CAD500 million in 2009 to help build our inventory of early-stage resource plays. In total we acquired approximately 226,000 net acres of perspective land, the majority of which was in three key growth areas.

One of these acquisitions was our investment in the Marcellus shale gas fairway, which consisted of approximately 126,000 net acres of land. We believe this play is one of the best developing shale gas plays in North America. And its proximity to the largest natural gas market means superior economics to other shale gas plays. Given the current stage of development, we believe this asset will provide tremendous growth potential for Enerplus.

Through this acquisition we added over 2.1 Tcf of natural gas contingent resource, providing us with the opportunity to more than triple our current total natural gas proved plus probable reserves.

In addition to our Marcellus acquisition, we added approximately 78 net sections of Bakken/tight oil perspective land in Saskatchewan and North Dakota to our growth portfolio. We have now accumulated over 100 net sections of undeveloped Bakken land in both Canada and the US, and expect this will be another key growth area for us.

In addition, we added 29 net sections of undeveloped land in the Deep Basin tight gas area of Alberta and British Columbia, where we are pursuing a number of plays, such as the Montney, Nordegg and Mannville formations.

We also increased the best estimate of contingent resources associated with our Kirby Oil Sands lease by 20% to 497 million barrels, adding 83 million barrels from the estimate at year-end 2008.

Now since acquiring the lease in 2007, we have increased the contingent resource estimate by over 100%. And while we have suspended development of the Kirby lease, given the anticipated return on investment and timeline to positive cash flow versus other opportunities in our portfolio, we continue to believe in the geologic quality and potential of the Kirby lease. We are currently evaluating our options to maximize the value of this lease and expect only minimal spending associated with the lease in 2010.

We expect to continue to pursue acquisition opportunities to further improve our asset base in 2010. With an unused bank credit facility of CAD1.4 billion, we have significant capacity to execute this strategy.

The second key component of our strategy is the preservation of our financial strength. Through our disciplined approach to capital spending and distributions, we maintained a strong balance sheet, and exited the year with a trailing data to cash flow ratio of just 0.6 times, one of the lowest in the energy sector.

Our cash flows were significantly impacted by the drop in both crude oil and natural gas prices compared to 2008. We generated cash flow of CAD776 million, down from approximately CAD1.3 billion in 2008. Cash distributions were reduced in 2009 by 56%, and totaled CAD2.23 per unit. In aggregate, 47% of our cash flow was distributed to unitholders. When we combine distributions to unitholders and our development capital spending, our adjusted payout ratio was approximately 87% of our cash flow.

The average sales price for our natural gas was CAD3.91 per Mcf, down 52% from 2008. And our average selling price for our crude oil was CAD58.54 per BOE, down 36% from 2008.

Our crude oil and natural gas hedging program helped offset some of the weakness in commodity prices, generating cash gains of CAD155.8 million in 2009. For 2010 we have approximately 39% of our expected natural gas production hedged at an effective price of CAD6.45 per Mcf. And approximately 43% of our expected crude oil production for the year hedged at an effective price of $77.69 per BOE.

Now as management we are also focused on achieving our operational targets in 2009. Daily production averaged 91,569 BOE per day, slightly ahead of our full-year guidance of 91,000 BOE per day. Our December volumes were 3% below our target at 85,400 BOE per day as a result of some unexpected downtime related to cold weather, and unplanned turnarounds at two nonoperated facilities, and delays in capital spending. After adjusting for weather and unplanned downtime, our exit rate would have been approximately 87,200 BOE per day.

Capital spending for the year was CAD299 million, roughly 5% less than our guidance of CAD350 million, and before considering carry capital associated with our Marcellus properties.

Our operating costs for the year were 4% lower than our revised guidance, coming in at CAD9.79 per BOE. And G&A costs were CAD2.64 per BOE during the year, 8% higher than our guidance of CAD2.40 plus.

This was due to one-time cost during the year, including those associated with recent staff reductions, as well as transaction costs related to our senior notes issue. After adjusting for those one-time costs, our G&A per BOE was CAD2.31 per BOE or 6% better than our guidance.

We stated throughout 2009 that part of our transition would include the divestment of non-core assets that do not fit with our strategy going forward. Towards the end of the year we sold approximately CAD100 million of non-core assets. Going forward we plan to market and sale up to 14,000 BOE a day of non-core oil and gas production in Western Canada, which represents roughly 16% of our current production.

We expect to market these assets in multiple packages, and depending on the value we see, there is no guarantee that all or any of these properties will be sold in 2010.

Now as previously reported, Enerplus experienced negative reserve revisions in 2009. Approximately 16% of our total proved plus probable reserves were written off, representing 25% of our natural gas bookings and 3% of our liquid reserves. These negative revisions resulted from the removal of undeveloped drilling locations, changes in an valuation methodology, reservoir performance and decline of natural gas prices.

A significant portion of the reserve reduction was due to the removal of approximately 1,400 undeveloped drilling locations, mostly in our shallow gas assets, and a reduction in the reserves associated with the remaining undeveloped locations. With the acquisition of the Marcellus assets we expect to direct a significant portion of our future natural gas spending to this resource play. As a consequence, spending on our conventional Canadian shallow gas assets will be reduced.

Also, in conjunction with the methodology used by our new third-party reserve evaluators of the assessment of final economic production rates and decline factors, this combined with lower than anticipated well performance and lead to a further reduction of our reserves. Of course, hanging over all of this was a lower natural gas price outlook.

Our 2009 acquisition activities were focused primarily on acquiring land positions in key resource plays to provide growth prospects for the future. While these acquisitions did not add any significant reserves or production in the current year, they did add significant contingent resources and growth potential for future years.

In total our proved plus probable reserves declined by 20% year-over-year to 345 million BOE, including the revisions described in 2009 production. The negative reserve revisions more than offset the reserves added through our capital spending and acquisition activities. As a result, our finding and development and acquisition cost and recycle ratios were negative in 2009, and therefore impractical to calculate.

As we look forward at our capital program, we also had a focus on managing our spending to meet our economic hurdles under lower commodity prices and to preserve our financial strength. Our production guidance for 2009 was lower than our 2008 production levels, but in concert with this focus of preserving our financial strength as we transition the organization.

We invested CAD299 million, net of CAD22 million in Alberta drilling royalty credits, and the CAD12 million of capital carry requirements associated with our Marcellus assets. This was roughly 5% lower than our guidance, due primarily to delays caused by cold weather and lower spending associated with the Marcellus assets.

Mature cash generating properties continue to be a core part of our business, and over 60% of our capital spending was invested in these properties within our waterflood, shallow gas, tight gas and Bakken/tight oil plays.

Our investment in growth projects grew in 2009 to roughly CAD82 million, up from CAD55 million in 2008. This spending helped advance projects in our Bakken/tight oil, tight gas, oil sands and Marcellus Shale gas plays, and included land, seismic and pilot drilling in these areas.

Approximately 40% of our capital was spent on our crude oil properties, and 60% on our natural gas properties. We drilled 313 net wells across our portfolio with a 99% success rate, adding over 11,500 BOE a day of new production at an average onstream cost of 26,000 BOE per day.

Our oil activities were concentrated in our Bakken/tight oil and waterflood assets, spending CAD86 million. We expect to increase our spending in these resource plays by close to 150% in 2010, with about 70 net wells planned. We anticipate production growth in both resource plays by year-end.

Our natural gas spending was concentrated on our shallow gas and tight gas assets in Canada, with a significant amount of the spending occurring in the first half of 2009. As natural gas prices weakened in the second quarter, we suspended our summer drilling program at Shackleton in Saskatchewan and shifted our activities to Alberta, benefiting from the royalty drilling incentive program.

In total, we drilled 259 net shallow gas wells, including 120 net wells eligible for credits. Our spending on our existing assets in these two resource plays is expected to decrease by over 40% in 2010.

In our Marcellus Shale gas play we invested CAD29 million, CAD12 million representing Enerplus' shared of capital, CAD12 million in carry capital, which covers 50% of our partner's capital, and CAD5 million in the purchase of additional land and seismic.

This is an early-stage growth play, and there will be challenges as activity levels continue to increase as the play develops. But we are encouraged by our results to date and our position in the play. Decline rates on our producing wells are as good as our expectations, and in fact better. This is further supported by competitor activity in the play.

We had planned to drill 15 wells and complete 7 wells by year-end; however, only 12 wells were drilled and five wells were completed due to scheduling and availability of services towards the end of the year.

At year-end we had a total of 43 wells chilled in the Marcellus play, with 11 wells on production, 22 wells waiting to be completed, and 10 wells awaiting tie-in. We currently have four rigs working in the play with a fifth-grade expected early in the second quarter. We plan to drill and complete 12 gross wells and tie-in eight additional wells during the first quarter. Completion and tie-in activity is also expected to increase throughout the year as infrastructure is put into place.

We anticipate our Marcellus production to grow in 2010 from 2.1 million cubic feet per day to over 18 million cubic feet per day by year-end, with the spending of CAD80 million and the drilling of 11 net wells.

So as we look forward in 2010, we expect to invest approximately CAD425 million in our assets, net of CAD33 million of drilling credits. This represents an increase of 35% over our 2009 program due to the improvement in crude oil prices and increased opportunities associated with our early-stage growth-oriented assets.

We expect to spend CAD260 million on our Canadian asset and CAD165 million on our US operations. About 55% will be directed to oil opportunities and the remainder on natural gas. Based on our capital spending plans for 2010, we expect to produce an average of 37,000 barrels per day of crude oil and natural gas liquids and 296 million cubic feet per day of natural gas, totaling approximately 86,000 barrels of oil equivalent.

We expect our crude oil and natural gas liquids production to increase over the course of the year and make up approximately 45% of our exit rate volumes versus 40% at the end of 2009. Our exit production rate is expected to increase to approximately 88,000 BOE per day, setting the stage for continued growth in 2011. This outlook does not include any acquisition or divestment activities.

Let me now just turn finally to the corporate conversion question. With the implementation of the SIFT tax, January 1, 2011, and the elimination of the tax exemption for trusts, we expect to have a special meeting of unitholders in December this year and convert to a corporation on or about January 1 of 2011, of course, subject to approval of our plans by our Board of Directors.

We remain committed to having a meaningful component of income distribution in our business model; however, we must also have a growth component in our business model. We have and will continue to position ourselves to offer investors both. We expect to continue to distribute a significant portion of our cash flow to unitholders once we are a corporation. We believe we will be able to utilize our tax pools to meet the new tax obligations providing shelter from cash taxes for two to three years beyond 2010.

While our cash flows and the amount we distribute will vary depending upon commodity prices, production volumes and costs, we do not expect to adjust our monthly cash distributions as a result of our conversion to a corporation.

So with that, I will now turn the call back over to the operator to take any questions from the audience.

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

A couple of questions on your resource plays. You have added a lot of contingent resources, particularly in that Marcellus -- the Marcellus Shale Fairway. I was wondering what kind of capital do you reckon you're going to have to spend say over the next three or four years to start to move some of that from contingent resource into reserves?

I think if you look back at our disclosure when we announced the transaction, over the next four to five years we expect to spend in the order of CAD800 million with respect to our share of the cost in this play.

And again, we look to grow the production over that time frame net to Enerplus in the order of 100 million cubic feet a day of production. So it is going to be, I would say, a timeline that fits within the context of meaningful cash flows within the next -- I will say two to three years, and obviously an ability to grow it even beyond that.

Then in terms of some more production sales, what areas are you targeting to sell out of?

Maybe that is a question I will let Ian handle, but basically we have a number of targeted areas that we have put into packages and that we are basically moving forward on in terms of marketing. But, Ian, maybe you want to add some color.

Sure. As Gordon said, it is 14,000 BOE a day that we can touch and identify that just -- it doesn't fit our long-term plan. And if you look at the highest level it is evenly split between gas and liquids, a lower level of operatorship generally, and I would say no particular focus. It is mostly an Alberta -- a little bit into BC, a squidge into Saskatchewan.

They're not bad assets by any stretch of the imagination, but they are generally smaller pieces that we are not focusing on and are not trying to grow, and have decided that they would be best suited in someone else's hands, subject to valuation.

Will they have a smaller impact on your reserve base? Like if you take the proportion coming out of your production, will it be the same proportion coming out of your reserves or will it be a smaller proportion?

Relatively equivalent. These would be -- have a heavier PDP focus though, a relatively modest amount of probable reserves associated with them. And in assets that typically we haven't spent much capital in over time.

Lastly, you might have put this out before, but if you'll remind me, approximately how many potential well locations do you have in your Bakken plays, both the Sleeping Giant plus your new properties?

I think at this stage it would be somewhat preliminary for us to comment on how many wells that we will have in our Bakken play. We are moving forward, as I say, with the acquisition of acreage. And we are evaluating it as we go, so we haven't put any information out on that at this point.

(Operator Instructions). Paul Rachelle, Veritas Investments.

My question is regarding the royalty litigation you have in the Marcellus. Maybe if you could just give us more color on that situation, how many leases have been amended, maybe how many leases are contested?

I think at this point I'm not really quite conversant with what litigation you are referencing. Honestly, I mean, there are some issues out there in the industry overall associated with the rate of royalty. And in the course, I think, that the requirement is a 15% basic royalty. And so is that what you are referring to?

I was just referring to the MD&A, you have the minimum royalty litigation disclosure there. You are mentioning that there are some legal action, and that Chief has been amending some of the leases in response to that. So I'm just looking for some color on the situation, maybe how far along the leases, what proportion of leases have been amended and so on?

I think that at this particular point in time there has been very little in the way of amendment. It is an issue I think that has hung over the industry, but we are fairly optimistic quite frankly that the lease constructs that we have with our partner, Chief, are in good shape. So we may -- certainly we would want to have full transparency and disclosure around those types of issues, but it is not something that we are overly concerned about.

Maybe in terms of your decline rates, would you happen to have an estimate for a one year decline at the Marcellus, given what you have seen right now?

I don't think it is that dissimilar to others, but we are early stage in this. I think that typically in these plays you are seeing one year decline rates in order of 60% to 70% on wells, so it is not dissimilar to that. And as I said earlier on, we are strongly encouraged by what we see to date in terms of us setting the tight curves that we built into our economic forecast.

Okay, that was all the questions I have. Thanks.

There are no further questions at this time.

Okay, well if that is the case, thank you, operator. And thank you everyone for joining us on this call. I guess we will call it a day.

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