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Resolute Energy (NYSE:REN)
Q4 2012 Earnings Call
March 07, 2013 4:30 pm ET
Michael N. Stefanoudakis - Senior Vice President, General Counsel and Secretary
Nicholas J. Sutton - Chairman and Chief Executive Officer
Theodore Gazulis - Chief Financial Officer and Executive Vice President
Bret R. Siepman - Vice President of Geology & Geophysics
Paul Taylor
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
John Freeman - Raymond James & Associates, Inc., Research Division
Jeffrey W. Robertson - Barclays Capital, Research Division
Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division
Richard M. Tullis - Capital One Southcoast, Inc., Research Division
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Jason A. Wangler - Wunderlich Securities Inc., Research Division
Good afternoon, and welcome to the Resolute Energy Fourth Quarter and Year End 2012 Earnings Conference Call. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Michael Stefanoudakis, General Counsel. Please go ahead.
Michael N. Stefanoudakis
Thanks, operator. Good afternoon, everyone. My name is Michael Stefanoudakis. I'm the Senior Vice President and General Counsel of Resolute. I'd like to read the forward-looking statement before turning the call over to Nick Sutton, our Chairman and CEO.
This investor conference call includes forward-looking statements within the meaning of the Safe Harbor provisions of the United States Private Securities Litigation Reform Act of 1995. Words such as expect, estimate, project, budget, forecast, anticipate, intend, plan, may, will, could, should, poised, believes, predicts, potential, continue and similar expressions are intended to identify such forward-looking statements.
Forward-looking statements in this conference call may include matters that involve known and unknown risks, uncertainties and other factors that may cause actual results, levels of activity, performance or achievements to differ materially from results expressed or implied by this investor conference call. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this call.
At this time, I'd like to turn the call over to Nick Sutton, our Chairman and CEO.
Nicholas J. Sutton
Thank you, Michael. Good afternoon. As we have done in previous calls, I will provide you with a brief overview of the company and then an operations update. After that, Ted Gazulis, our company's Chief Financial Officer, will review our financial results, then we could take your questions.
As we covered most of the highlights in our press release, I intend to keep my comments brief and focus on providing some context and perspective to what we have achieved over the past 2 years and what it means for the future of Resolute.
First, I am very, very pleased to report that our fourth quarter production was 10,073 BOE per day, an increase of 22% over the same quarter last year. We exceeded our 15% production guidance for the full year 2012 by increasing production to 3.4 million BOE. And today, we are referring -- reaffirming our guidance of a 30% increase of production for the full year 2013 over 2012.
I would like to summarize our achievements during the fourth quarter and full year of 2012. As I just mentioned, we increased total company production in the fourth quarter by 22% over the prior year quarter and produced a total of 3.4 million BOE, exceeding our production guidance.
We continued to strengthen our foundation Aneth Field by drilling new wells, seeing ongoing and increasing response from our CO2 initiative in the Aneth Unit, continuing the water flood project in the Desert Creek IIC formation and completing 2 transactions that help monetize value and increase our operating flexibility.
We have 2 active drilling programs in our oil growth projects in North Dakota and Texas, both of which drove production increases. A 270% increase in production in Texas and a 289% increase in the Williston Basin. Combined, our drilling activities and our investments resulted in an increase of proved reserves to 78.8 million BOE at year end, that's 22% higher than the previous year. 79% of those reserve were classified as crude oil. If we include natural gas liquids, the liquids component rises to 90%.
A brief review of how we got here is in order. In 2011, our asset portfolio was dominated by Aneth Field, a classic giant oilfield with an estimated 1.5 billion equivalent barrels of oil in place. Aneth Field is a great asset. It spins off substantial free cash flow for reinvestment. The supplement and to reduce our dependence on Aneth, in 2011 through 2012, we worked to expand our operations in both the Permian Basin and the Bakken oil shale play of the Williston Basin, both of which are excellent places to reinvest the free cash flow generated by our legacy assets in Aneth Field and in Hilight Field.
In our call at this time last year, we forecasted that reinvestment in the Permian and Williston basins would reduce the waiting to Aneth Field for both our reserves and our production. A year later, I could say that we have done just that.
At year-end 2012, Aneth Field accounted for 75% of our total proved reserves, down from 86% at the end of 2011. Our production from Aneth declined to 64% of company-wide production in the fourth quarter from 73% in the same quarter last year. Obviously, on the exercise of our option, later this month, the shift in reserves and production will be even more dramatic. Although Aneth Field and Hilight Field are mature assets, they remain core to our business strategy. Last year, these legacy fields generated approximately $117 million of field level net income that was available for reinvestment both there and in our Permian and Bakken growth assets.
Now let's discuss each of our major assets and where the growth is expected to come from. As I mentioned previously, and I'm going to repeat this one more time, in 2012, we increased company-wide production to 3.4 million BOE, a 17% increase over the prior year. Every major asset contributed to this growth except for Hilight Field, although even that field performed remarkably well for its age. Aneth Field contributed an incremental 136,000 equivalent barrels of production, our Bakken properties produced an incremental 234,000 equivalent barrels and our Permian Basin production grew by 151,000 equivalent barrels.
What stands out is that about 3/4 of our incremental production in 2012 came from our 2 oil growth assets in the Williston and in the Permian basins.
Turning to our foundational Aneth Field, Aneth produced an average of 6,347 equivalent barrels per day in 2012 or 68% of total company production. Aneth Field production in the fourth quarter was up over 7% from the prior year quarter, and 98% of that production was crude oil. The production increase was driven by a positive response to our CO2 flood in Aneth Unit, increased well run times as a result of intense field focus and the benefit of greater injection of water handling capacity at our central facility during the year. In addition, we successfully drilled and completed 3 gross or 2 net wells in the field.
At the end of 2012, in Aneth, we had an estimated 37 million equivalent barrels of reserves classified as proved developed, nonproducing or proved undeveloped. Of that, 34.5 million BOE are classified as additional barrels that can be recovered by expanding and extending our tertiary CO2 flood projects that are currently in operation. This opportunity represents lower-risk future growth potential from resources that we have already captured.
We also believe that additional upside exists in Aneth Field within Desert Creek, the DC IIC subzone in the McElmo Creek Unit. Two years ago, we reinitiated the waterflood project in that formation and began a recompletion program. We're very encouraged by the results and at year-end 2012, we had 21 producers and 26 injectors operating in the project. Eventually, we plan to implement a CO2 flood in the zone.
One of the benefits of our waterflood project in the DC IIC is that we'll re-pressure the zone, a precondition for the CO2 flood, and much of the well work will carry over directly to the CO2 project, although I caution that more infrastructure will be needed before we can actually begin CO2 injection. In the meantime, the waterflood project has strong economics and contributes to organic oil production growth. In 2013, we plan to re-complete 10 injectors and deepen 10 producing DC IIC wells.
On this topic of upside potential on Aneth, I should also point out that we expect to be able to book CO2 reserves in the Ratherford Unit within the next few years. In 2013, we expect to invest approximately 45% of our capital budget in Aneth Field to increase the rate of CO2 injection in the Aneth Unit, to drill several infill wells and to perform re-completions and injection-enhancement projects throughout the field, including reactivation of the DC IIC waterflood that I just talked about.
In total, these expenditures are focused on continuing the spooling up of production from the asset as a response to the CO2 flood increases. Our ability to increase our injections is directly related to the excellent run times from our new Aneth central compression facility. Certainly, we would expect to see a new and expensive facility operating smoothly. But in my opinion, the results are also attributable to skills and dedication of several employees, and I'd like to tip my hat to them. That's a good transition into where we are deploying cash generator from our Aneth Field.
Now let's turn to the Permian Basin. During 2012, we completed 20 gross or 14 net wells, bringing our total year-end well count up to 196 gross producing wells. Production increased by an average of 567 BOE per day in 2012 -- that's to an average of 567 BOE per day in 2012, a 270% increase over the prior year, and 75% of this production was liquids.
At year end, our position in the Permian Basin covered 40,800 gross or 17,100 net acres. In December 2012, we completed 2 transactions that increased our operating position and extended our visible growth potential in this core area. For $248 million, including closing adjustments, we acquired 9.3 million equivalent barrels of proved reserves at a cost of about $26.67 per BOE.
In the first transaction, we purchased properties in Howard County, Texas and Lea County, New Mexico. The Howard County properties includes 64 vertical drilling locations and 66 recompletion opportunities, and the Lea County properties include approximately 30 infill and deepening opportunities. Most of the acreage is held by production, and we plan to drill 8 to 10 gross wells in Howard County during the year, which will further increase production and value.
In the second transaction, we purchased approximately 1/3 of a set of assets in Ector and Midland counties, Texas, that include 80 existing wells plus 45 vertical drilling locations and 69 recompletion opportunities. Most of the acreage acquired in this transaction is held by production. And we estimate that a 1- to 2-rig drilling program for about 12 months will be sufficient to hold all of the acreage.
The acquired properties produced almost 2,600 BOE per day during the fourth quarter. However, due to the timing of the acquisitions, virtually none of this production from the acquired properties was actually booked in 2012. The acquisitions also increased our multiyear drilling inventory to a total of about 200 vertical drilling locations and 135 recompletion opportunities.
And there's more upside to follow. As part of the second transaction, we paid $5.7 million for an option to purchase the remaining 2/3 of the properties that we did not acquire in the 2nd December transaction for a total consideration of up to $261 million. We filed an 8-K earlier this week announcing our intention to exercise the option. We expect to close the transaction by the end of the first quarter, which will further increase our production and expand our drilling inventory and visible growth potential in this core area.
Today, our Permian Basin position is divided into 3 primary projects. It includes the Wolfbone project area in the Delaware Basin portion of the Permian, the Wolfberry project area located at the Midland Basin portion of the Permian and our Northwest Shelf project, which is in the Southeast of New Mexico.
Our Wolfberry project covers 9,500 gross acres, in which we have an approximate average 43% work interest, primarily in Midland, Howard and Ector counties in Texas. This is a classic stacked, multi-pay zone area producing formations extending over a 3,000-foot strategic column -- stratigraphic column that include the Mississippian, the Strong, the Canyon, the Cline, the Wolfcamp, the Dean and the Spraberry formations. We believe the growth potential exists from approximately 113 vertical drilling locations targeting the Wolfberry interval and 135 recompletion opportunities that are categorized as either proved or probable.
We also believe the potential upside exists for horizontal development in the Wolfcamp, Atoka and Cline formations that we are monitoring offsetting competitor activity in this regard. Our vertical Wolfbone project area is located in the Delaware Basin and includes approximately 24,000 gross acres in which we hold an average working interest of approximately 34%. Our primary objective in this project is the Wolfcamp formation, with the Bone Spring formation serving as a secondary objective. Up to now, our development plan called for vertical wells having between 5 and 8 completion stages in the Wolfcamp and the third Bone Spring sand. We installed gas gathering infrastructure in the second quarter of last year that enabled us to begin selling natural gas and NGLs, enhancing the economics of this area to us.
Recently, the industry has drilled successful horizontal wells directly offsetting our Wolfbone project area in Reeves County. These wells targeted the Wolfcamp and the Leonard oil shales. I don't make it a practice to site other operating -- other operator's data in one of our calls, so I'm merely suggesting that you check EOG's press release issued on February 13.
We're very encouraged by the results, and we are performing technical work to evaluate the potential on our acreage directly offsetting these new wells. We expect to invest about 32% of our 2013 capital budget in the Permian Basin, with the majority of investment allocated to our successful vertical drilling program targeting the Wolfberry play. We plan to participate in drilling 34 gross or 11 net new wells on our new properties in Midland and Ector counties. And I'd point out that the net well count is likely to change upon the exercise of our option to purchase the remaining properties there.
On the newly acquired assets in Howard County, we plan to participate in as many as 8 to 10 gross or 4 to 5 net Wolfberry wells. While the current development plan calls for vertical wells, as I just mentioned, we're evaluating the potential of horizontal development. And after conducting a thorough technical review, we may decide to add horizontal wells to this development plan.
On North Dakota, during the year, we completed 31 gross or 6.6 net wells; and at year end, we had 4 gross or 1.1 net wells waiting on completion, giving us a year-end total of 58 gross or 14 net wells -- producing wells in the Williston Basin.
The activity increased production from the Bakken shale to 861 BOE per day, which was 289% higher than the prior year. Nearly all of our production for the Bakken is liquids and it's mostly crude oil. Our Bakken position is divided into 2 areas: the New Home and the Paris project areas. Combined, they hold 88,100 gross or about 32,300 net acres.
At New Home, we own a 22,900 net acre position in Williams County. All of our wells at New Home are producing from the Middle Bakken. Based on industry drilling results in different parts of Williams County, we believe that upside exists from the Three Forks formation, which sits below the Bakken. Only 53% of our total acreage position in this project is developed, and 71% of the acreage is held by production, which provides for strong future growth potential.
In our Paris project area, we operated a 19,100 gross acre or 9,400 net acre position in McKenzie County. We have no meaningful lease expirations in this project until 2014.
Looking forward, we believe that focus is important. We are also cognizant of our need to delever our balance sheet, particularly in light of the anticipated exercise of our Permian purchase option. As a result, despite the encouraging results in the Bakken, particularly as costs have come down and product prices stabilized, we have decided to evaluate the market for a Bakken position, as disclosed in an 8-K that we filed earlier this week. That's our current plan is to spend minimal capital on our Bakken assets in 2013.
Looking to our Hilight Field in the Powder River Basin. While production from this asset declined by 6% to 1,539 BOE per day, this area still represented 17% of our total production last year, and it is an important source of free cash flow. We've allocated very little capital to this area for 2013, giving the impact of continuing low natural gas prices. But we will continue our technical evaluation in emerging tight oil plays in the Powder River Basin, including the Mowry, the Turner and the Niobrara. We are also using our 3 seismic data to evaluate certain deeper prospects, including the Minnelusa.
To wrap up, I want to congratulate our team for the hard work, their diligence and their creativity in 2012. They have my thanks, the thanks our Board of Directors and hopefully, the thanks of our shareholders. Resolute is strategically positioned with increasing production from Aneth Field, a multiyear drilling inventory of economic projects
in the Permian Basin and elsewhere. As a result, we have a longer conveyor belt of new oil wells to drive future growth potential. And it is important to reiterate that we do not seek growth at any cost, as our team remains -- maintains a constant focus on improving cost efficiencies to enhance returns.
I'll now turn the call over to Ted Gazulis to discuss our financial results in more detail.
Theodore Gazulis
Thank you, Nick. Good afternoon, and thank you to all of you who are listening to our call today. We were pleased with our operating and financial results for both the full year and the fourth quarter of 2012, and we think 2013 will be a good one for Resolute.
Oil production is always the principal driver of financial performance in our business. And for the fourth quarter of 2012, we grew total production from -- or to 927,000 equivalent barrels from 759,000 equivalent barrels for the fourth quarter of 2011, as the 22% number that Nick has mentioned. Production for the full year of 3,409,000 equivalent barrels was up 17% from 2,924,000 equivalent barrels for 2011. That 17% increase was somewhat ahead of our -- the midpoint of our announced guidance of 15% production growth.
Revenue, excluding realized derivative settlements in the fourth quarter of 2012, rose to $66.9 million, 13% higher than the year-ago period, driven primarily by the increase in production. During the period, average realized per unit revenue, excluding realized derivative settlements, was $72.15 a BOE, which was down from $77.61 a BOE in the same quarter last year.
For full year 2012, revenue per BOE decreased 2% to $75.77 from $77.60 in 2011. Not surprisingly perhaps, with rising production came increases in operating expenses. Our aggregate lease operating expense in the fourth quarter of 2012 rose to $21.8 million from $16.9 million in the same quarter of last year. I would note, however, that on a sequential basis, while lease operating expenses in aggregate increased 2% over the third quarter amount, they actually declined by 5% on a per-unit basis, from $24.75 during the third quarter of 2012 to $23.58 in the fourth quarter. The increase in lease operating expenses this year versus last came primarily from higher workover activity in Aneth Field and increased cost levels in North Dakota and Texas.
For the full year 2012, total LOE rose 34% to $79.9 million as compared to $59.5 million in the prior year, an increase on a per-unit basis to $23.45 per BOE in 2012, up from $20.35 per BOE in 2011. The increase reflects our ownership of additional working interest in Aneth Field, as well as the other factors I just mentioned.
Total production taxes in 2012 increased to 37 -- pardon me, $35.7 million as compared to $31.4 million for 2011, reflecting a relatively consistent rate of about 14% of revenue. In aggregate, the production tax increased with higher production volumes, combined with higher ad valorem tax estimates resulting from increases in the assessed value of reserves in 2012 and offset by a receipt of enhanced oil recovery credits.
On a unit of production basis, full year production taxes decreased from $10.73 a BOE in 2011 to $10.48 a BOE in 2012. We incurred G&A expense of $6.5 million for the fourth quarter or $6.90 a BOE, a 17% decrease on a per-unit basis from the prior year quarter totals of $6.3 million and $8.35 a BOE. On a sequential basis, aggregate G&A expense decreased slightly from $6.7 million.
For the full year 2012, we incurred G&A expense of $24 million or $7.05 a BOE as compared to G&A expense of $20.9 million or $7.15 a BOE during 2011. As we've grown our business, we've added talented staff across all of our assets, which is reflected in higher salaries and wages. But I'd also point out that during the year, we placed 2 tranches of senior notes, we made 3 acquisitions and have 1 disposition. And as a result, costs for outside professional services were higher in 2012, offset by increased overhead billings and capitalized time. In any case, however, increasing production led to a lower per BOE G&A cost.
Moving to adjusted EBITDA, a non-GAAP measure, in the fourth quarter of 2012, we generated adjusted EBITDA of $31.8 million or $34.27 a BOE, which was a 16% interest -- pardon me, increase from the prior year period. During full year 2012, we generated $31.83 per BOE of adjusted EBITDA or an aggregate of $108.5 million, a 1% increase over 2011, as production increases in 2012 were offset by increased operating costs and related production taxes and administrative expenses.
Turning now to our base capital program. We invested $228.2 million during 2012 across all of our project areas. In addition, we acquired Denbury's interest in Aneth Field for $37.7 million; and at year end, we bought some great assets in the Permian Basin for $248 million. Offsetting that, we received $49.5 million in proceeds from the sale of certain Aneth Field properties to the Navajo Nation Oil and Gas Company.
Looking ahead to 2013 for a moment, based on our pro forma cash flow from operations, which includes the newly acquired Permian Basin assets, more than 90% of our 2013 capital plan should be funded through internally generated cash flow from operations, plus the $47 million that we received earlier this year from Navajo Nation Oil and Gas for the second installment of their purchase of those Aneth Field assets.
Finally, I'd like to talk about liquidity. At year-end 2012, we had $562 million of long-term debt outstanding, which consisted of $400 million of senior notes issued during 2012 and $162 million of borrowing on our revolving credit facility, which has a borrowing base of $330 million.
With that, I thank you again all for listening. And I'll turn the call back to the operator for Q&A. Operator?
Question-and-Answer Session
[Operator Instructions] And our first question is from Ron Mills of Johnson Rice.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
A question related less to the earnings release and more to the 8-K filing you put out this morning, which showed the financial impact of the Permian acquisitions and just want to make sure I'm reading it right. It looks like you're trying to do an adjusted EBITDA for the 9-month period standalone versus in the Permian acquisitions, it looks like your EBITDA would have grown by almost 2x, with production growing by about 50% at least, in my opinion, highlights the attractiveness of the high-margin Permian properties. Am I reading too much into that? Or is that -- am I moving along the right track there as we try to get a sense as to what the full year impact of having all the properties are including the option exercise?
Nicholas J. Sutton
Yes, I mean, the reason we put that 8-K out there was to give you some guidance, and it's really pretty much just math. And I think you're looking at it right. I think we get a tremendous financial leverage from the Permian acquisitions, particularly as we add in the second tranche of the second acquisition. The operating environment is very efficient there. I think we're going to bring down our unit costs as a result. And frankly, we're also -- I think we're going to have -- as we look at our unit G&A, the numerator is not going to go up nearly as much as the denominator. So I think that we do get that leveraging impact off of those acquisitions as you've described.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
And then looking at that 8-K and that impact relative to the guidance release you put out a week ago or 2 weeks ago, did you, from a -- it looks like from a G&A standpoint, it seems like you've fully burdened the company with all of the G&A increases from what seems to be a build-out of the Midland Basin. And yet, from a production standpoint, it's still -- it seems like you're assuming your base case vertical development, which is really self-funded from the Permian properties to the extent the horizontal valuation comes to or converts into a horizontal drilling later in the year. Is it also safe to assume that you -- the G&A button won't really move, but you have a chance to improve on the growth opportunities?
Nicholas J. Sutton
I think that you've picked up on a key point, if I understand your question, Ron. And that is -- first of all, I'd point out that the guidance that we put out earlier did not anticipate the exercise of the second -- or of the option to pick up the second tranche. Now we certainly indicated that it was our intention to exercise that option. But based on the facts that were on the table at that time, we felt that our guidance should be reflective of the status quo, in effect, the acquisitions that we made during 2012, but not anticipating the second tranche coming in, in this month. Now we have filed the 8-K indicating our intention to exercise, and we're very much on track to get that done. When we did our guidance, the guidance was, on one hand, did not get the uplift associated with the option. But as a practical matter, the G&A number was pretty heavily burdened in anticipation of that option exercise, simply because they were growing, the Midland staff we're growing the people who can -- the number of people who are essential to having a good field operation, and I think we have got a good core in our Midland office. And we look forward to supplementing that even if we didn't do the second tranche. But now the fact is we are. So I think that what you'll see is when we issue a revised guidance number that incorporates the exercise of the option, we will see a little bit of uptick in G&A, but it's not going to be fully commensurate with the size of the assets, the size of production, the size of the cash flow that comes with those assets. And the second part of your question kind of got onto the horizontal. And we're really fortunate here in that there are a number of companies drilling all around us. I mean, if you look at Pioneer's releases as to what it's doing in the Wolfcamp and over in Reeves County, we've got Cimarex and EOG and others, Reliance, they're all drilling around us with horizontal wells. And so if we just took -- added the wells that are really adjacent to our acreage, or either the tow or the drilling pad is virtually up against our lease line, that's probably half a dozen wells or more at let's call it $7 million a copy. So that's about $50 million just right there that we're able to, in effect, piggyback off of other people's checkbooks. So we certainly know how to drill horizontal wells, and we've got a top-rate technical team. And I would expect that we will move into horizontal drilling, but we're not going to just do it overnight. I think that those efficiencies will come into play. Certainly, we'll look at our drilling budget at that time, and we may back out some vertical wells as -- just for financial reasons, as we move horizontal. But I'd hasten to add that all of our vertical well counts are such that we can drill all those out without impacting the vertical or the horizontal well potential on our acreage. So again, we're not in any rush to get in here. Much of the acreage is HBP. We've got people around us spending a lot of money in effect walking the whole industry up the learning curve, and I think that puts us in a really strong position.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
And then lastly, just on the option exercise. You talked about -- when you talked about your budget and also, today, you talked about the deleveraging aspect of the Bakken sale in terms of preparing for the option exercise from a revolver standpoint and a contribution from the acquired properties. It sounds like from the intent to exercise that you -- you're well covered on the option exercise price.
Nicholas J. Sutton
Yes, Ron. I think Ted is at a position to address that with more specificity.
Theodore Gazulis
Sure. Yes, Ron, basically, the -- our existing revolver plus the borrowing capacity that would come with the properties associated with that option exercise will fully allow us to exercise the option under our revolving credit facility. We don't expect that that's going to be where we are forever, obviously. If we -- we are in the position where we're looking to monetize the Bakken acreage, and that of course -- or, properties, I should say, rather than acreage. And that obviously will dramatically decrease our leverage. There are lots of things that we can do going forward if we want to continue to bring the leverage down. As we've said, over time, we think that as a company, we want to be and we're comfortable in the range of 2.5x to 3x debt-to-EBITDA. But we will use our balance sheet and use our leverage capacity to get our arms around really terrific acquisitions. And that's what we've done here. We think these Permian properties are terrific. We think the second or the option exercise is a great use of leverage. And we recognize that we're a little bit out of the game when you've done that. So we have to delever to make sure that we have the ability to make changes in our leverage to be back in the game and growing the company. We're in the middle of -- we're in a process of negotiating the documents for the financing right now, so I really don't see that as an issue. And we're looking forward to getting that option exercised.
And our next question is from John Freeman of Raymond James.
John Freeman - Raymond James & Associates, Inc., Research Division
Not to beat a dead horse here. But on the exercise on this -- on the second option, I'm assuming, it was, I think most of us assume it's pretty much a foregone conclusion that you all are going to exercise this. And I'm just trying to get a sense of what to do on the CapEx side. Because you all did say last week that following, if you did exercise it, you'd update the CapEx. And maybe just some color, or should I just assume the high end of the range now?
Nicholas J. Sutton
Obviously, we are pulling all the information in, and we will be issuing revised guidance and that includes CapEx. I mean, a simple way of looking at it is that, I said earlier, 34 gross and 11 net wells. Well, I mean, if we take our working interest up to, let's call it, round numbers, 100%, if we did the same number of wells, that would gross up our capital program rather significantly. And at the same time, these properties are going to be bringing in significant cash flow. So I would expect to see our capital program go up, and it probably will be more than the high end of the guidance that we gave you before because, as I mentioned to Ron earlier, the guidance that we issued before was based on what was on the table at that time, and we had not announced any intention to exercise the option then. And so what was on the table then did not include capital that would come along with the exercised option. So again, all of this will be delivered to you shortly after we close on the option. As was noted earlier, you can look in the 8-Ks that we filed today, it gives you a lot of guidance on what these properties have done recently and it gives you the opportunity or the ability to, almost using your 4-function calculator, figure out what we should be able to expect in the form of increased revenues. Given our debt situation after we exercise, and we will have a comfortable amount of liquidity even after we exercise, but it's above, as Ted said, it's above our comfort range. And so I would not expect us -- to see us come up with some radical, expanded, huge CapEx program because we're going to make sure that we delever the balance sheet while we exploit the value that's embedded in these properties we're acquiring.
John Freeman - Raymond James & Associates, Inc., Research Division
Okay, that's helpful. And then on the DC IIC, which continues to go really well with the 21 wells that are online now, average rate of just over 60 wells a day. And I'm trying to think about, on the production impact, the additional 10 you bring online. Can I still, kind of as a rule of thumb, assume that on the recompletions that they generally come online at about 100 barrels a day?
Nicholas J. Sutton
I think that's a fair assessment in that we've had some that were higher than that and some that were not that high. The 60 barrels a day is an average, and that includes wells that have been online for 2 years now. So I think that's a reasonable working estimate.
John Freeman - Raymond James & Associates, Inc., Research Division
Okay. And then just the last question for me, and I'll turn it over to somebody else. And I don't want to put any words in your mouth, Nick, but on the Permian side, it sounds like there's not really any lease expiration issues that are really driving kind of the vertical mantra. You're just sort of trying to piggyback off of others. And based on, I mean, if nothing else, just the activity that Pioneer alone is going to have. If the results are just off the charts good, there's nothing else that's kind of handicapping you all to shift to horizontal, right, in terms of lease explorations?
Nicholas J. Sutton
No, not really. I mean, much of the acreage that we acquired, particularly in the Midland Basin, is largely HBP. Over in Reeves County in the Delaware Basin, we have the standard run of lease expirations in front of us, but nothing pressing and where we think anything sensitive, we've seen about getting some extensions. And so there's nothing in the lease situation itself that would drive us to the -- go vertical as opposed to horizontal. I mean, it's just, we you look at the economics and certainly, lease expirations is one of the things we look at, and that's one of the reasons we started out with vertical simply because when we started the project in Reeves County, we did have some lease expirations in front of us. But I think we've taken care of a good bit of those and we're taking care of what other expirations we see out there as we go forward.
And the next question is from Jeff Robertson of Barclays.
Jeffrey W. Robertson - Barclays Capital, Research Division
Nick, just a question on capital. Have you all said how much capital you have in the current budget on the RSP properties?
Nicholas J. Sutton
I don't think we've broke it out that -- with that much granularity, although I think we did say that in my comments, the percentage of our capital budget that is going to go to the Permian. And I -- those -- the majority of that is targeted in the Midland Basin. Some of that will be on the first set of properties that we acquired, and some of it will be on the second set of properties. And I think it's roughly 30-some percent of our capital budget is going to the Permian.
Jeffrey W. Robertson - Barclays Capital, Research Division
Okay. Nick, on these assets that you all have acquired, is there any opportunity to add incremental interest as you -- or in terms of acquisition opportunities?
Nicholas J. Sutton
On the second acquisition in December, we're going to -- as to those properties in particular, we're going to acquire the -- all the remaining interest in this -- I mean, all our remaining interest that counts in the exercise of the option. In the first transaction there, where we are a non-off in the Midland Basin, we have anywhere from a 25% to a 50% working interest. And there's a possibility that we're going to be able to pick up some additional interest in those properties some time this year.
Jeffrey W. Robertson - Barclays Capital, Research Division
Okay. And a question on the Bakken. Where are you in the process? Or are you just still putting a data room together? Have you opened one? Do you have a timeframe that you'd like to try to hit?
Nicholas J. Sutton
The data room is not open. I think indications of interest are coming along. Data will be open late this month or early in April and the target would be to get a transaction done. If we get the value that we think we should get, we'd look to close that sometime in June to early July.
Jeffrey W. Robertson - Barclays Capital, Research Division
Okay. And then last question, Ted, do you have a feel for what the borrowing base will look like once you roll in the rest of the RSP properties?
Theodore Gazulis
I actually have a pretty good feel. But I don't think I'm in a position to discuss that right now. We are still working through the documents with our friendly bankers. And I think I'd be remiss if I threw a number out there today. Certainly, when we get to the stage of the -- announcing a revised capital plan, we'll provide all that data.
Nicholas J. Sutton
But I think it's safe to say right now that the borrowing base is going to be sufficient, by any stretch, to give us adequate liquidity post the exercise.
Theodore Gazulis
Yes, that's absolutely right.
And our next question is from Noel Parks of Ladenburg Thalmann.
Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division
Just a few things. Talking about the potential Bakken sale again. I realize, of course, asset pricing is always a bit of a moving target. Are your expectations very high for the sort of number you're looking for in order to sell it? Or are you more thinking, we want something that's fair, given the current marketplace, but not prepared to go to the mat to just get exactly the number we want?
Nicholas J. Sutton
I mean, that's -- that's kind of a loaded question. Let's put it this way, my hopes are always very high, but the market is the market. And we have a certain minimum price that we can't really disclose for obvious reasons. And yet, it's, as I say, the market will be the market.
Theodore Gazulis
Nick, let me also point out for -- I mean, Noel, you've known us for a long time. We are committed to appropriately deleveraging the balance sheet after we exercise the option. We're not interested and it's not in the best interest of any of our stakeholders, management, shareholders, bondholders, employees, you name it, for us to give away assets. And to the extent that there's a robust market for properties and we get evaluation that we feel comfortable with, I don't know that we're going to stand on our -- stand on the hilltop and say, "We've got to get this number and not a penny less." But I can absolutely assure you that if the valuations don't come in, we would rather be -- we'd rather live with a little more leverage for a little longer period of time than give away assets that frankly, we think, are quite valuable.
Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division
Great. And I'm a little bit unclear about what the basis looks like for the Bakken properties. And do you think you'll have much of a taxable event, a tax hit on their sale?
Nicholas J. Sutton
One of the things that we did and one of the reasons that we have the debt on the books that we do is that we reserved, if you will, the cash that came in, in January for the second half of the NNOGC sale and we'll basically do a like-kind exchange with that money. When you -- when we do that, I don't anticipate that we'll have any meaningful tax consequences.
Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division
Great. And if you kept the properties, I mean, is farm-out an option? In a way, it seems a little bit of shame that you guys have gone to so much trouble to take over the Marathon properties and to sort of get it up to speed as operators in the basin and then looking at divesting them. Is hanging onto them and just looking for some other capital than your own to go after them an option?
Nicholas J. Sutton
Certainly, it's an option.
Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division
Okay, okay. One thing you did mention about the Powder River Basin is you said that, I think you were using 3D seismic to evaluate deeper targets than the ones generally thought about. And I couldn't quite catch the name of the formation you were looking at.
Nicholas J. Sutton
The formation, Noel, that I mentioned is called the Minnelusa, and it's deeper than the Muddy. There's almost a trend or a string of Minnelusa fields in the Powder River Basin and the wells can be extremely prolific. I mean, this is a conventional reservoir. It's not one that you have to go out with horizontal and huge fracs and all that. It is a conventional reservoir. And when you find these fields, they may not be huge in aerial extent, but the individual well statistics could be quite stout, a million barrels or more per well. There are some 10-million barrel fields that are Minnelusa fields. So it's got a lot of potential and our team is really working the data hard and seeing some interesting things. We haven't advanced them to a hard prospect point at this stage, but it's again the benefit of 3D seismic, you can see a lot of things that you couldn't see previously. A lot of the Minnelusa fields that have been drilled over the years were done on 2D seismic, and that's a tough game. With 3D, you have a much better ability to image these. And so we're kind of guardedly excited or enthusiastic about the possibility of something along these lines.
Theodore Gazulis
And I think there's one other thing that just it goes without saying and it's also the benefit of the acreage that's held by production. We have -- we've had the luxury of shooting a 3D and having our geotechnical team really reevaluate it, and that has huge value.
Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division
Right. And what sort of depth are we talking about for the Minnelusa?
Nicholas J. Sutton
I'm going to -- we've got Bret Siepman in our Denver office on the call, and Bret can give you quite a bit more color than I did. So Bret, feel free to jump in and correct anything that I misspoken and enlighten all of us.
Bret R. Siepman
No, Nick, I think you've got it all right. Noel, the depths are around 12,000 feet. And one of the things that Nick alluded to is you don't have to put big fracs on these wells. So you can get down and drill them and even look at them and know whether you've got a discovery or not without spending a whole heck a lot of money. We don't have AFEs so I can't quote a price, but it's relatively low cost compared to the resource play type of drilling that you might be thinking of.
Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division
That's helpful. And just one last thing. Given the second set of properties you're going to be getting, having exercised the option and the debt you now have on the balance sheet. Post that deal, what's capitalized interest going to look like heading into, well, I guess for the rest of 2013 compared to what it's been running before?
Nicholas J. Sutton
That, unfortunately, Noel, I am doing this call from a room in Boston. I do not have that information right at my hands. We can get back to you on that. Jim Tuell and I can kind of push through that and get some data back to you.
And next, we have a question from Richard Tullis of Capital One South Coast.
Richard M. Tullis - Capital One Southcoast, Inc., Research Division
I think most everything has been touched on already, but just a couple more. Nick, what's your rate of return on your Permian wells in the new area, the RSP area, say, using current NYMEx pricing?
Nicholas J. Sutton
We haven't really gotten into details like that with the public. But one of the things I can tell you is that we're going to try to tee up an Analyst Meeting and really give you all a chance to do a deeper dive on these properties. And that will probably take place within the next couple of months. I mean, we're going to get this acquisition behind us and then we're going to -- we'd like to invite all of you in and really do a deep dive through the geology, the engineering, the economics and all of that. So I'd just as soon defer that until we have a broader group of people who can participate and ask all the questions they want.
Richard M. Tullis - Capital One Southcoast, Inc., Research Division
Okay. And you may not be ready to answer this at this time. What's the well cost on the RSP wells, the verticals?
Nicholas J. Sutton
Right now, we're looking at a little bit over $2 million.
Richard M. Tullis - Capital One Southcoast, Inc., Research Division
$2 million. Okay, and then just finally, there hasn't been a whole lot in the Q&A on Aneth Field. But given the recent performance there, any change to your longer-term growth outlook for Aneth?
Nicholas J. Sutton
Not really. I mean, as we've always said, the thing about the CO2 projects is that timing, in particular, is a variable that comes into play. And I think we've told you and others that our assessment of the Aneth CO2 project, which frankly it's the CO2 floods that really are driving the production growth there. We're a little bit slower than we would have anticipated on day one, but the volumes are coming on. And in particular, we're really seeing it now in Phases 1, 2 and 3 and we've made some statements about the production in the Aneth unit, which is where Phases 1, 2, 3 and 4 is today compared to what it was when we first acquired that unit. And it's up substantially. And we're also getting a quicker response in Phase 4 than we did in Phases 1, 2 and 3 simply because by having -- the way I look at it, it's sort of, I don't know if you've got a visual map in front of you, Richard, but remember, the far northwest was 1, 2 and 3, and then we moved it a little bit to the east, then that was Phase 4. I think some of the CO2 out of Phase 3 was moving, as you would expect, migrating and coming into a little bit of the western portion of Phase 4. So I would say that our responses out of Phase 4 are much quicker than when we first initiated with emerging CO2 floods, so to speak. And So I think we're going to see some good results there. Production continues to increase. I think we're going to continue to see good results in the Desert Creek IIC, and I'd emphasize again that that's setting up that subzone for an eventual CO2 flood by repressurizing it with the water and the reinitiated water flood. And then we're working on the Ratherford unit, and that's -- I'll remind you, we don't have any of those reserves on our books right now simply because over the last several years, they were sort of truncated by the SEC 5-year rule. As we balance out the whole thing in terms of just the field processing capacity and whatnot, we think we're going to be closer to being able to get the Ratherford reserves on the book. I'd also point out that we're -- in this year, 2013, we intend to do a little testing on the residual oils on concept in Aneth. And so that could add to production, could add to reserves. We also have done reservoir simulations, which would indicate that there's going to be room for some infilling in Ratherford -- or I mean, in the Aneth Field. And we're going to be testing some of that. I'm not suggesting just sort of blanket infill or downspacing, but select infills. Like last year, we got our B-414 well that came on at hundreds of barrels a day. And I think we're going to be able to replicate that with some of the drilling that we've got on schedule. So we're pushing all the buttons in Aneth. And I think we're going to continue to see nice production increases. And I would say our long-term plan hasn't changed to any significant extent, with the exception of changes that seem to take place in our anticipated timing of things and some cost creep that inevitably comes in, in days like this.
And our next question is from Ryan Oatman of SunTrust.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Wanted to talk a little bit more on Bakken, as most of the strategy questions have been asked and answered here. It looks like those are 2 kind of very different properties. Would you want to sell that in one fell swoop, or would you consider 2 different buyers there?
Nicholas J. Sutton
Our current plan is, certainly, I'd just love to sell it in, to use your word, one fell swoop. But as you point out, they have different characteristics. And it's -- we're setting it up so that essentially, 2 different parts of a package.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Okay, okay, that's helpful. And then I saw in the 8-K some permitting delays and whatnot in McKenzie County. Can you just elaborate a little bit on that, a little bit more color there? And then is that something that you see as temporary, that can be -- the results fairly quickly? Or is that like a longer-term issue for that portion of the play?
Nicholas J. Sutton
Are you referring to a specific area, Ryan?
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
I guess, it was, in McKenzie County, it sounded like that -- there were some permitting delays that might have prevented you guys from really getting after that in 2013, in addition to, of course, the strategy shift towards the Permian.
Nicholas J. Sutton
Right. That's -- that is our Paris project area in McKenzie County. And yes, you're absolutely right. We have experienced some delays. One of the things that some of that acreage is federal acreage. And despite all the assurances out of Washington that they're really interested in assisting the country with energy independence and whatnot, it's proven to be extremely time-consuming to get delays out of the federal government, as opposed to the local fee simple lands with the farmers and the ranchers. And we're working our way through that. You've got all the stipulations that relate to wildlife and archaeological sites and all this and that. It really gets down to delays. And the first of the permits should be popping out at the end of the pipeline pretty soon. And by pretty soon, I mean, like August. But it's been a long process. And I think once the permits start to emerge from the long pipeline, they should come through in, not a continuous process, but -- you get the cumulative effect of a 2-year process that's been ongoing.
And our next question is from Jason Wangler of Wunderlich Securities.
Jason A. Wangler - Wunderlich Securities Inc., Research Division
Just was curious as far as the McElmo Creek Unit. You're going to look into the water flood. How long will you be water flooding you think in terms of that? And then as you look into doing CO2 there, do you have an idea of, I know its early, but a rough estimate of the timing of that and maybe even the incremental cost?
Nicholas J. Sutton
We've got all of that sort of laid out. And I'm going to ask Paul Taylor, who is on the line, to give whatever color he can because he's much closer to the granularity of that project than I am.
Paul Taylor
I'm sorry, could you repeat the question, please?
Jason A. Wangler - Wunderlich Securities Inc., Research Division
Yes, just as far as McElmo Creek, you're obviously going to do the water flood. As you move to CO2, do you have at least a rough estimate on when the timing of that would begin, and then also just the capital that you would be spending to get that up and running?
Paul Taylor
I think -- I'd like to think of it this way. We're trying to optimize the timing of these different projects and also, in terms of how we allocate CO2 all across the field. In other words, we will be moving it from Aneth to McElmo as capacities allows us to, as well as when the infrastructure will be available for us to do that. But for example, right now, we actually are injecting CO2 in a couple of the patterns and learning about that. That will give us more information about how those particular patterns can compete, if you will, against the other patterns around the Aneth Field. So we're sort of taking a measured approach with that. And that will give us also a better idea on how far we can go before we need that additional infrastructure and the gas handling capacity at McElmo. But all that said and done, I think that the answer would be, we will be trying to ramp this thing up I'd say sometime by year end, at least focus some more CO2 in that area. But the infrastructure and compression and so forth that goes along with that is still a project that we're going to make a, I would say, a final investment decision on probably by the end of this quarter.
Jason A. Wangler - Wunderlich Securities Inc., Research Division
Okay, that's helpful. And then just one more if I could over at Aneth. And you had a couple of those with NNOGC. Is there anything else coming with that or are the deals or the interest now pretty much set going forward?
Nicholas J. Sutton
You'll remember, Jason, that when, as part of the deal that we did with Navajo Nation Oil and Gas this last year, we allowed them to exercise 1 of the 3 options that they had originally under what we have called the cooperative agreement that we entered into back in 2004 when we first bought the Aneth unit from Chevron. That cooperative agreement gave the Navajo Nation Oil and Gas Company 3 options to acquire additional bytes of the field. And they were triggered, the rights were triggered by certain financial metrics. They were getting close to being able to trigger the first one. And that, and some other operational considerations, caused us to sit down and talk with them about the -- some revisions in the cooperative agreement. And they wanted to be able to exercise that first option, which they did for the $100 million that we've talked about. As part of that, the second option went away, and the third option was set to be on a date certain, and that is in 2017. So when you ask whether there's anything left out there, there is one more option for them to be able to acquire 10% of the interest that we acquired originally from Chevron and Exxon. It's not 10% as adjusted by the Denbury acquisition and other kinds of things. So it's just 10%, and that's the only other thing that's out there.
And next, we have a follow-up question from Jeff Robertson of Barclays.
Jeffrey W. Robertson - Barclays Capital, Research Division
Just a question back on the Minnelusa and the Powder. Is there any enhanced oil recovery potential in that formation where you all are?
Nicholas J. Sutton
You know, I suspect there is. But right now, I frankly have been concentrating on the primary, because I'd love to break in a little Minnelusa field and get that kind of primary recovery. And ultimately, it probably lends itself to some kind of a secondary recovery.
And next, we have a follow-up from Ron Mills of Johnson Rice.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
Just from a bookkeeping standpoint. Nick, if you all exercise the option on the new date of March 22, is that the date that we should assume that the purchase of the remaining interest would close? Or would there be a lag between that exercise and when you would close, just from an accounting standpoint of the incremental production that will be coming in the door?
Nicholas J. Sutton
No, we're looking at closing on that date.
And this concludes our question-an-answer session. I would like to turn the conference back over to management for any closing remarks.
Nicholas J. Sutton
No closing remarks other than to say thank you very much. I think 2012 was a good year for us. We made some transformational changes that I think are exciting. We continue to focus on our oil production, and we look to see that oil production continue to grow. And so I think that 2012 and the activities that we did in 2012 set us up for really an exceptional 2013. We already indicated that we expect production growth of over 30%. That doesn't include the second tranche of the RSP acquisition. And as we've said before, you get your production growth from drilling, you can get your production growth through acquisitions and we're doing it both ways. And so again, thank you very much for your time and interest. And if you have any further questions, really, absolutely feel free to reach out to us. Thank you again.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
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text: Bugs item #8928, was opened at 2007-02-28 04:12 You can respond by visiting: http://rubyforge.org/tracker/?func=detail&atid=3149&aid=8928&group_id=797 Category: None Group: None Status: Open Resolution: None Priority: 3 Submitted By: Nikolai Lugovoi (meadow) Assigned to: Nobody (None) Summary: rspec_on_rails 0.8.0-RC1 controller tests make double call to setup_with_fixtures Initial Comment: call to super in Spec::Rails::Runner::FunctionalEvalContext#setup results in double call to setup_with_fixtures. The problem is described in details at http://rubyforge.org/tracker/index.php?func=detail&aid=8894&group_id=797&atid=3150 and http://dev.rubyonrails.org/ticket/7665 So, here's my understanding (Mx are labels to distinguish methods): first, active_record/fixtures.rb redefine TestCase#setup as TestCase#setup_with_fixtures (M1). next, defining "setup" method in FunctionalEvalContext (M2) triggers TestCase.method_added, which makes M2 to be "setup_without_fixtures" and creates new "setup" method (M3) as def setup setup_with_fixtures # (M1) setup_without_fixtures #(M2) end last, ControllerEvalContext also defines "setup" method (M4) and finally we have in runtime: ControllerEvalContext#setup: (M4) calls super -> FunctionalEvalContext#setup (M3) FunctionalEvalContext#setup: (M3) calls setup_with_fixtures -> method from fixtures.rb (M1) calls setup_without_fixtures -> method from context/functional.rb (M2) But #setup defined in context/functional.rb (M2) calls super -> that is again setup_with_fixtures (M1) So, is call to "super" necessary in FunctionalEvalContext#setup or it can be safely removed? ---------------------------------------------------------------------- >Comment By: Nikolai Lugovoi (meadow) Date: 2007-02-28 04:16 Message: oops, rails trac ticket on my problem is at http://dev.rubyonrails.org/ticket/7672 ---------------------------------------------------------------------- You can respond by visiting: http://rubyforge.org/tracker/?func=detail&atid=3149&aid=8928&group_id=797


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