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Executives

Jack T. Collins - Executive Director of Investor Relations

Phil Rykhoek - Chief Executive Officer, President and Director

Mark C. Allen - Chief Financial Officer, Senior Vice President, Treasurer and Assistant Secretary

Craig J. McPherson - Chief Operating Officer and Senior Vice President

Robert L. Cornelius - Senior Vice President of Co(2) Operations and Assistant Secretary

Analysts

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Robert Bellinski - Morningstar Inc., Research Division

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Pearce W. Hammond - Simmons & Company International, Research Division

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Denbury Resources (DNR) Q3 2012 Earnings Call November 6, 2012 11:00 AM ET

Operator

Ladies and gentlemen, good morning, thank you for standing by, and welcome to the Third Quarter 2012 Earnings Conference Call. [Operator Instructions] And as a reminder, this conference is being recorded.

I would now like to turn the conference over to our host, Denbury's Executive Director of Investor Relations, Mr. Jack Collins. Please go ahead.

Jack T. Collins

Okay. Thank you, Tom, and good morning, everyone, and thank you for joining us on today's call. With me on the today from Denbury are: Phil Rykhoek, our President and Chief Executive Officer; Mark Allen, our Senior Vice President and Chief Financial Officer; Craig McPherson, our Senior Vice President and Chief Operating Officer; and Bob Cornelius, our Senior Vice President of CO2 Operations.

Before we begin the call, let me remind you that today's call will include forward-looking statements that are based on the best and most reasonable information we have today. There are numerous factors that could cause the actual result to differ materially from what is discussed on today's call. You can read our full disclosure on forward-looking statements and the risk factors associated with our business in our corporate presentation, our latest 10-K and today's press release, all of which are available on our website at www.denbury.com.

Also, over the course of today's call, we will reference certain non-GAAP measures. Reconciliations of and disclosure on these measures are provided in today's press release.

With that out of the way, let me turn the call over to Phil.

Phil Rykhoek

Thanks, Jack, and thank you for joining us on Election Day. Today, we're going to focus primarily on third quarter, which bottom line, I think, you'll find are generally in line with expectations. We'll be looking at 2013 guidance, give a full update on our future plans and so forth at our analyst meeting, which is next Monday, November 12. We hope you can join us at that. But if you can't, be aware that the presentation will be webcast.

We also will be doing a repeat, but a somewhat summarized version of that presentation in New York the morning of Wednesday, November 14. If you'd like to attend either of these meetings and haven't previously registered, please contact investor relations or Jack Collins.

As you know, this quarter we announced the Exxon Mobil transaction asset sale and exchange that includes our Bakken area asset. This transaction is on schedule. We expect it to close around the end of November. If you recall, we'll receive about $1.6 billion in cash, and we'll receivable operating interest in 2 future EOR floods located in our core areas, Webster and Hartzog Draw. In addition, we will acquire additional CO2 from Exxon's LaBarge Field in Southwestern Wyoming, which depending on the form that it takes could reduce those cash proceeds. We are continuing to pursue opportunities to use the cash proceeds to buy additional oil fields that would be EOR candidates in our 2 areas. We love to make that part of a like-kind exchange, and of course, that would reduce our tax leakage. However, it's still too early to know which, if any, of these potential deals could be consummated.

We have until 45 days after closing to identify any such candidates, which means probably about mid-January. And then we have 180 days after closing the Exxon Mobil deal to close any incremental transaction which would be late May.

If we can't do a like-kind exchange transaction, we would initially use the cash proceeds to fully repay our credit facility, and we would have cash left over. Shortly after announcing the Bakken transaction, we resumed our share repurchase program, and we've added about another 4.6 million shares to our total purchases to date. To recap that program, we have now repurchased nearly 19 million shares or approximately 5% of our outstanding shares, and we have an average purchase price of just under $14.50 a share. We have approximately $230 million of remaining purchase -- repurchases authorized under that $500 million program, but as part of the recent bank amendment, which was required in order to authorize the Exxon Mobil transaction, we increased the total stock repurchases allowed under that agreement by an additional $700 million or a revised total of $1.2 billion. Bottom line, that gives us the flexibility to easily expand our repurchase program beyond the $500 million currently approved by our board.

When we look at our stock repurchase program, it's our practice to set aside capital for that program and until we get a little further along, we are uncertain how much incremental liquidity we will have from the Exxon Mobil deal. As such, we have intentionally repurchased our stock at a bit of a slow pace during the last month or 2 pending a more definitive answer regarding the magnitude of potential asset purchases.

Shifting gears quickly to the third quarter. As I mentioned before, as you noticed, we are on track to continue to deliver on our 2012 plan. Craig's going to go through the fields in more detail, but at a very high level, you will note we had a bit of a temporary plateau at some of our tertiary floods this quarter, and the continued growth at our newest floods, Hastings and Oyster Bayou, was basically offset by Hurricane Isaac-related production shut-in. Fortunately, there was no significant damage from the hurricane and production from the shut-in fields has rebounded since then.

I think the most important thing to note is that our tertiary production has resumed its growth, averaging around 36,000 barrels per day for the month of October, which keeps us on track to finish the year in the upper half of our 2012 guidance. So in summary, our tertiary program's doing well, meeting expectations and creating value.

While Mark will cover the specifics, the financial results were in line with consensus estimates. A bit lower than prior quarters due to the impact of lower realized oil prices as that offset the benefit of higher production. Given the high percentage of production priced in the LLS-based indexes, we did sell our oil at a premium again this quarter, although it declined about $1 a barrel from last quarter. However, this premium is looking better thus far in Q4 and will improve with the sale of our Bakken assets. We estimate that if you exclude our Bakken area asset, our Q3 premium -- our Q3 premium to NYMEX would have been over $5 a barrel.

With these premium price realizations, our heavy focus on crude oil, over 90% of our crude being related to oil, continued focus on managing operating expenses, we continue to have one of the highest operating margins of our peer group. When you couple our high operating margins with our relatively low finding and development cost, the result is one of the best capital efficiency ratios of our peer group.

We don't expect our operating margins to change significantly following the Exxon Mobil transaction as their higher price realizations will be essentially offset by the higher average operating cost. However, our finding and development cost should decrease somewhat, resulting in an even better capital efficiency ratio pro forma for the Exxon Mobil trade.

In summary, 2012 continues to shape up as a great year for Denbury, and we expect to close the year on a strong note.

So with that introduction, let's look at more of the details, and Mark's going to start with the numbers.

Mark C. Allen

Thanks, Phil. In my comments I'll provide some further analysis of our quarterly results, primarily focusing on sequential changes from the second quarter of 2012. I will also provide some forward-looking guidance for the remainder of 2012 for your financial models. But I'll stay away from discussing 2013 guidance, and that will be covered next week at our Analyst Day.

Our adjusted net income, a non-GAAP measure, for the third quarter was $127 million or $0.33 per diluted share. Adjusted net income in the third quarter, excludes an after-tax noncash fair value hedging loss of $42 million. This was down from the second quarter adjusted net income of $138 million or $0.35 per diluted share, primarily due to lower oil price realizations and higher lease operating costs.

For the same reasons, our adjusted cash flow from operations, which excludes working capital changes, was $350 million for Q3, down slightly from $362 million in Q2. Total production for the quarter of nearly 73,000 barrels of oil equivalent was roughly 1% higher than second quarter levels. As indicated in our press release, we are keeping our 2012 production estimates unchanged, but will expect production to finish in the upper half of the range for both tertiary and total production.

Assuming the Bakken transaction closes at the end of November, we would expect to reduce our annual production estimates by about 1,400 BOEs per day. However, the properties we expect to receive in the transaction would add roughly 300 BOEs per day, resulting in net decrease of about 1,100 BOEs per day to our annual production estimates.

Our average realized oil price, excluding derivative settlements, was about $93 in Q3, down about $2.50 from the second quarter. About half of this decrease is related to a lower premium to NYMEX on our oil sales, which dropped to a positive $0.80 in Q3 from a premium of in excess of $2 in Q2. All of our tertiary production is in the Gulf Coast region, and the majority of it sold on LLS-based indexes.

The average NYMEX price premium for our tertiary production in the third quarter was about $10.60 per barrel compared to a premium of $13.60 per barrel in Q2, with the decrease primarily due to the movement in the LLS price premium.

In the Bakken, our oil and NGLs sold at an average discount of $16.40 per barrel to NYMEX in the third quarter, which is better than the $20 per barrel discount realized in Q2. Excluding NGLs, we sold our Bakken oil at an average price of about $12.40 per barrel below NYMEX in Q3. Based on the LLS and Bakken differentials we have seen thus far in the quarter, and not taking into account any impact from the Bakken transaction, we expect a modest improvement in our average oil differential in Q4.

Moving on to our hedging activity. We continue to execute a strategy of protecting our oil price downside, while retaining upside through costless collars. We currently have oil collars in place through mid-2014, with most of our floors around $80 per barrel and ceilings at over $100 per barrel on a NYMEX basis.

During the third quarter, we restructured most of our oil collar contracts covering the first 3 quarters of 2013. Overall, we increased the average floor price from $70 and $75 per barrel to about $80 per barrel and paid for this by decreasing ceiling prices. Full details of our hedge positions are shown in our corporate presentation available in the Investor Relations section of our website.

Our lease operating expense in Q3 was $130 million, up $6 million from the prior quarter, primarily due to a full quarter of operating expense at Thompson Field and a higher level of workover and maintenance activities. And on a per BOE basis, our total lease operating expense was about $19.50. Excluding the Bakken area assets, our total lease operating expense per barrel would have been nearly $24 per barrel. For our tertiary operations, lease operating expense per BOE averaged $23.50 for the quarter, up from $23 in the second quarter, primarily due to higher workover activity. Excluding any impact from the Bakken transaction, we continue to expect our total company LOE to be in the low- to mid-$20s on a per BOE basis for the remainder of 2012.

Our G&A expense in Q3 was $38 million, in line with our previous guidance and a slight uptick from the second quarter, primarily due to incremental headcount, which resulted in higher compensation and employee-related costs. About $9 million of our Q3 G&A expense was stock-based compensation. For the fourth quarter, we expect G&A expense to be between $37 million and $40 million, with approximately $8 million to $10 million of that in stock-based compensation.

Our overall DD&A per BOE increased to about $20.50 for the quarter, a slight increase from just over $20 in the second quarter. We expect our DD&A per BOE to decrease moderately after the Bakken transaction due to the reduction in capitalized cost.

Our effective income tax rate for Q3 was in line with expectations, with a total rate of approximately 39% and current taxes at roughly 8% of that total. We expect fourth quarter to be similar to the these levels, between 38% and 39%, excluding any impact of the Bakken transaction.

Moving on to our capital structure. Total debt at September 30, was about $3 billion, up about $100 million from June 30. We had $625 million drawn on our $1.6 billion bank line at the end of the quarter, also up about $100 million from Q2.

We recently received the required approval from our bank group to complete the Bakken transaction. In addition to that approval, our borrowing base was reaffirmed at $1.6 billion, and we modified our bank agreement to increase the total amount that can be returned to shareholders through share repurchases or dividends from $500 million to $1.2 billion. We continue to believe we have the ability to significantly increase our borrowing capacity if we so desired.

Interest expense, net of capitalized interest, decreased roughly $4 million from the prior quarter to $38 million, due in part to the higher capitalized interest. Capitalized interest in Q3 was $19 million. And in Q4, we expect it to range between $18 million and $21 million.

Our capitalization metrics remain strong, and our debt-to-capital ratio is approximately 37%, and our debt to Q3 annualized adjusted cash flow and EBITDA were at 2.2x and about 1.9x, respectively.

Our 2012 capital budget remains $1.5 billion, slightly less than 75% of which has been spent through the first 3 quarters. While we plan to repay borrowings under our bank credit facility with the cash proceeds from the Bakken transaction, excluding the impact of that transaction, we would project our year-end bank debt to be between $700 million and $800 million.

As Phil mentioned, we are continuing to pursue additional acquisitions with the anticipated cash proceeds from the Bakken transaction. If we have potential acquisitions identified at the time of closing, we would escrow some or all of the cash received pending resolution of any like-kind exchange. That means the cash will be placed in escrow and would not be available for us to immediately reduce bank debt.

That's the end of my comments. And I'll turn it over to Craig.

Craig J. McPherson

Okay. Thank you, Mark, and good morning to all. We'll start by reviewing our core tertiary business. Tertiary production was about 34,800 barrels per day during the quarter. That's down slightly from the second quarter. That's primarily due to the impact of hurricane-related and production shut-ins in the quarter. Also as mentioned on previous calls, our tertiary production growth can sometimes experience some lumpiness depending on the timing of response of new phases of CO2 injection, and this past quarter was one where we were waiting on growth from new areas at Delhi.

Let me help you put the third quarter in perspective for the entire year. We experienced 6% sequential growth in the second quarter of 2012 and tertiary production has increased 12% from the prior year third quarter level. Looking forward, we do expect solid sequential production growth in the fourth quarter as we are seeing response from new patterns at existing floods, including Delhi. So with that as backdrop, I'll review a few fields that had material impacts in the third quarter production, and that we expect to drive near-term growth. We'll start with Tinsley.

Tinsley Field production was flat from the second quarter level, and that was in line with our expectations for the field production to plateau in the back half of 2012. As a reminder, Tinsley production grew about 12% sequentially in the second quarter. We do expect fourth quarter production levels at Tinsley to be similar to third quarter as we begin development of that north fault block of the field.

Moving to Delhi. Delhi's production declined about 200 barrels per day in the third quarter compared to the second quarter levels. That production decline was due to maintenance and some remediation work combined with a plateau in the field's response. We have completed all the maintenance and remediation work and have recently seen improved field response, which is enabling Delhi's production to resume an upward trend. We're very pleased with that. At Delhi, production decreased about 100 barrels per day compared to the second quarter, and that was in line with our expectations.

Digging a bit deeper at West Heidelberg, we continue to see positive signs that our conformance work we completed earlier this year has been successful. And at East Heidelberg, we're starting to see production response from our new wells in the Christmas zone. Also at East Heidelberg, we're very pleased with our continued Eutaw zone development. So overall, we expect production at Heidelberg to increase modestly in the fourth quarter as additional patterns in East Heidelberg ramp up.

Moving to Oyster Bayou. Oyster Bayou's production increased over 200 barrels per day for the third quarter to over 1,500 barrels per day. As mentioned in last quarter's call, all the reservoir response characteristics continue to indicate a very good flood. As we displaced existing water in the reservoir with CO2, and that CO2 moves towards our producing wells, it grabs oil and that should increase our oil production. We're looking at ways to increase our water disposal and CO2 injection at Oyster Bayou to accelerate this process further. We have seen continued production growth at Oyster Bayou in the fourth quarter, and we expect additional growth over the next few years.

At Hastings, production increased by over 800 barrels per day from the second quarter, to just about 2,800 barrels per day. Hastings' production continues to respond quite well. And this bodes very well for the future CO2 floods at Thompson and Webster fields, which are close geographically, and they are technically similar to Hastings. We do expect production growth at Hastings to moderate somewhat in the fourth quarter as we reach the capacity of our recycle compression. Additional compression is anticipated late in the fourth quarter.

Most of our other tertiary fields were either flat or modestly declined. Many experienced some hurricane-related production downtime in the third quarter. With their normal decline and hurricane shut-ins, production from these fields declined over 7% sequentially. I'll move now to the Bakken.

Given our pending transaction with Exxon Mobil, I'm not going to review Bakken in detail. But in summary, Bakken production grew 8% sequentially as we brought several new drilling pads online during the quarter, and we increased our participation in non-operated wells in advance of the Exxon Mobil transaction.

Looking now at our total company. Production was nearly 73,000 barrels of oil equivalent per day, and that's approximately a 1% increase compared to the second quarter, and this is 9% higher than our 2011 third quarter level.

Moving to operating cost. Tertiary lease operating cost averaged $23.50 per barrel. That's a slight increase from Q3, from about $23 in the second quarter, driven mainly by an increase in our well work. Compared to the third quarter of 2011, costs were down 6% on a per barrel of oil equivalent basis. Overall, we expect tertiary operating cost to remain near this level in the fourth quarter, but to trend lower as production from our newest floods at Hastings and Oyster Bayou ramps up.

Total company operating cost averaged about $19.50 per barrel of oil equivalent in the third quarter. That's a slight increase compared to the second quarter 2012 and a 10% decrease compared to the third quarter of 2011.

That concludes my remarks, and I'll turn the call over to Bob.

Robert L. Cornelius

Thank you, Craig. Good morning to all. I'll start off with a review of our Gulf Coast area CO2 operations. At Jackson Dome, we produced just over 1 Bcf per day of CO2 during the quarter. That's up 13% sequentially. We had 2 drilling rigs operating in the Jackson Dome area during the quarter to develop our CO2 resources for use in the Gulf Coast areas floods. The wells drilled during 2012 are primarily right wells, so it is unlikely that we'll booking additional proved reserves at Jackson Dome this year. However, with these new wells coming online, our CO2 production from the field recently reached a new daily record high of just over 1.1 Bcf per day. Now in addition to the natural CO2, we continue to make progress on securing future CO2 supply from man-made or anthropogenic sources to increase our Gulf Coast CO2 volume.

Industry emitters are starting to realize that CO2 oil recovery offers a proven method of storing man-made CO2 underground, while boosting domestic oil production. Also, our existing CO2 pipeline transportation system provides a meaningful strategic advantage in securing future anthropogenic sources of CO2 along the Gulf Coast.

Construction of 2 industrial facilities in the Gulf Coast providing us anthropogenic CO2 remain on track. Air Products' steam reform -- steam methane reformer located near Port Arthur, Texas is expect to be online by the end of the first quarter of 2013. Now that will provide us with approximately 50 million cubic feet a day for use at our Hastings tertiary operations. Also, Mississippi Powers' integrated combined cycle power plant should be completed during 2014, and that could provide up to 115 million cubic feet a day of CO2 to our Mississippi tertiary operations. In addition to these 2 sources, we are also discussing additional offtake agreements with sponsors of several existing or proposed facilities in the Gulf Coast region. Of note, Leucadia's Lake Charles clean energy recently announced they entered into long-term commercial offtake agreements for their proposed gasification facilities. The Leucadia plant could provide us approximately 200 million cubic feet a day of CO2 by the end of 2018.

I think I'll move now to the Rocky Mountain CO2 operations. We are pleased to report the construction of our first major CO2 pipeline in the Rockies is nearing completion. The 232-mile, Greencore pipeline will connect our source of CO2 at ConocoPhillips' Lost Cabin processing facility to our Bell Creek oilfield. We expect the pipeline to be completed on schedule and on budget. The total capital cost is at the midpoint of our originally estimated capital range of about $275 million to $325 million.

Construction activity at the Bell Creek oilfield is well underway, and we expect to start injecting CO2 into the field in the first quarter of 2013. We expect to obtain additional CO2 supply from Exxon Mobil's Shute Creek facility, and we are working to secure a pipeline interconnect between our Greencore pipeline to the pipeline that transports CO2 from Exxon Mobil's Shute Creek facility. This pipeline interconnect would significantly reduce the cost and timing of delivery of CO2 from Shute Creek to Bell Creek and future Hartzog Draw flood.

It would also allow us to potentially defer an expansion of our Riley Ridge facility beyond the plant's facility to process a raw gas stream of around 200 million cubic feet per day. Now moving to the Riley Ridge gas processing facility, we identified issues related to design and construction of the plant, which prompted us to change the plant's general contractor. But our facilities team is working diligently to correct the issues identified. But we now expect first natural gas and helium production around mid-2013. This is about 6 months later than we most recently estimated.

The delay of this facility has no impact on our plans to construct a carbon dioxide sweetening facility near Riley Ridge to separate the CO2 from the gas stream and then ultimately a pipeline could connect the facility to our Rocky Mountain oilfields in the second half of this decade. We recently commenced the permitting process for that sweetening plant and the attached pipeline system. Now as to the Rocky Mountain anthropogenic CO2, DKRW Advanced Fuels recently announced they signed a construction contract for their proposed coal-to-Liquids facility. The DKR plant could provide our Rocky Mountain operations nearly 100 million cubic feet a day of CO2 in the second half of the decade.

So in conclusion, our CO2 supply and transportation operations are performing well and expected to continue to meet the needs of our expanding tertiary oil production operations.

With that, I think I'll turn it over to Jack.

Jack T. Collins

Okay, thank you, Bob. Tom, that concludes management's prepared remarks. Can you please open the call up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question today comes from the line of David Deckelbaum with KeyBanc.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Just wanted to get an update on the compressor installations at Hastings. What sort of additional capacity is being put in there towards the end of this year, with potentially additional plans for next year? Could you walk us through that and just provide a little bit more color on what's left to do there and sort of the timing and capacity that we could see?

Robert L. Cornelius

This is Bob Cornelius. We have a compressor that is now in place, and we are making the final connections to that, and we're working on the electricity instrumentation on that. Really hope to have that compressor up and running by the first week in December, so that should help us, as Craig pointed out, to continue to produce an increase of production at Hastings. As to the first quarter, we're looking at some other compression into the first and second quarter to continue to maintain our recycle capacity as the field grows.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Okay, thank you. And Phil, just back to the acquisitions that you all might be looking at. I know that you have until January 15. I guess I'm wondering, would there be any reason right now to look for an acquisition that might be a bit larger than would necessitate for sort of tax efficiency here? Any reason to be a little bit more opportunistic now and just sort of look at doing a larger package and just financing that through considering the strength of the balance here.

Phil Rykhoek

Well, if you're asking, could it exceed the proceeds from Exxon, I think that's almost a certain no. We are talking to a few people. It's hard to say yet whether they'll be successful or not, so we hesitate to even guide expectations, I guess. It's kind of a limited group of people that have fields that we want, and then of course, unfortunately, we can't negotiate with ourselves, it takes the other side. So we're working on it. We do have a little bit of time. Last call, I think, we couched it, it's probably not likely to be large. So that -- that there is a little bit in there that would be a little bit larger, but definitely would never exceed the proceeds, and it likely will be quite a bit less.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Fair enough. And if I could just do one more, Phil. I'm wondering if you could give us any -- if you could put any probability around actually executing a more favorable structure for the contract for CO2 purchase from Exxon to minimize tax leakage. What would be the probability on getting something like that done? What are the impediments and how much do you think that could save you?

Phil Rykhoek

Well, we're working diligently on that. And I think that's actually in both of our interest because it actually helps Exxon, too. So both companies, I believe, are motivated to make that the preferred way of contracting -- or obtaining, it's not actually a contract, that would be a mineral interest in the property of obtaining additional CO2 from LaBarge. I believe still, if we go down that route, it probably is an upfront payment of $200 million to $250 million. And so it would save tax on a portion thereof related to those -- that cash out of pocket. But that's what we're still working on. As to the impediments, it's just a little bit more complicated, I guess, than a simple purchase contract because you need to consider a processing agreement because, obviously, they would be processing our gas. You need to hand over gas imbalances and that sort of thing. So all those agreements are in process. We're optimistic that, that will be the route that we go, and I think we're both striving toward that, but it is a bit more complicated than just a simple purchase contract.

Operator

And our next question today comes from the line of Robert Bellinski representing Morningstar.

Robert Bellinski - Morningstar Inc., Research Division

I was just wondering, you mentioned trying to secure the pipeline interconnect at Shute Creek. I was just wondering, how much does owning those CO2 volumes actually impact your ability to secure that transportation versus just a purchase agreement?

Phil Rykhoek

I don't think that matters. I mean, the point is, we will have incremental CO2 available to us from Exxon. We already had some CO2 available for Grieve Field and, potentially, a little extra over what we needed at Grieve. But the trick is, of course, to get it into our pipeline. So we're pursuing the interconnect optimistic that, that will come into fruition. But if it doesn't, then in order to get those extra volumes to Bell Creek or Hartzog, we would have to have our line in place, which is, unfortunately, probably takes a few years to get that done.

Operator

And next we'll go to the line of Michael Scialla with Stifel, Nicolaus.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

You talked after you did the -- announced the Exxon Bakken transaction about potentially reordering the tertiary projects, and I realize the deal hasn't closed yet. But any further thoughts along those lines, in particular Hastings is performing, looks like Thompson and Webster might be candidates to move up in the pecking order, but I just wanted to see what you’re thinking there is now?

Phil Rykhoek

We'll tell you next Monday. We actually haven't looked at the order, and we'll go through what the proposed order is and couple that with 2013 guidance and maybe even a little color beyond that, but we plan to cover that next week.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay. Probably some of the other questions I have, I'm probably looking at the same response. But in terms of the Jackson Dome, not adding much there this year in terms of reserves. But next year, you had also talked at the -- during the transaction, that you do plan to do some additional drilling there. I just want to see if you have further thoughts along those lines for next year.

Phil Rykhoek

Well, yes, it is a little bit of the same response because we'll also, obviously, cover CO2 sources next week. I mean, I think it's, in short, safe to say we probably will do a bit more drilling there than what we have historically. But we do -- have had some encouraging news on the anthropogenic sources also, for instance, as Bob mentioned in his prepared remarks, the Lake Charles plant, Leucadia, put out a press release a week or so ago. So we're kind of encouraged that there may be some supplements to our natural source, but we have a plan -- I guess the short answer, we have a plan with or without those man-made sources, and we will show you some of that next week.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And in terms of the first injection at Bell Creek, you've been guiding that in early 2013. The only thing standing in the way there, construction of the Greencore pipeline, or is there anything else that could potentially push that one way or the other?

Craig J. McPherson

The completion of Greencore pipeline. Also there is a small facility at the tailgate of ConocoPhillips' Lost Cabin plant that have to be finished. That work is underway. But that part has to be finished so we can take the gas from -- that ConocoPhillips can deliver the gas to us and at the beginning of our pipeline. Still on track, we expect that to happen, but that's still yet to be completed.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

And then last one for me. Say you don't get much, or anything done for that matter, in terms of like-kind exchange, would you anticipate using all the excess cash, the proceeds from the deal to repurchase stock? It looks like you're gearing up to do that, if I'm reading you correctly.

Phil Rykhoek

Well, we'd likely use some of it. I mean, it all goes somewhat depending on the price. I mean, I would like to do an asset deal, but obviously it needs to be a reasonable price. And we think our stock is a good bargain at this point, but that all depends on where oil prices go and what our stock does. So it's a little hard to say or answer that we'd spend it all for stock because of a whole bunch of conditions on that. And the one step that makes that a little easier is we now have bank approval to spend more, so it makes it a little quicker for our board or for us to increase the stock purchases. But I think both of those just depends on pricing, really.

Operator

Our next question comes from the line of Ryan Oatman representing SunTrust.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

My question also kind of centers around the thoughts on the additional share repurchases. Can you walk me through your thought process, how you weigh share repurchases versus reinvesting into CO2 fields. And then the formalities needed from the board to increase the authorization on the one hand, and then also how a repurchase compares in your mind with a potential special dividend or instituting a regular common dividend?

Phil Rykhoek

Well, you had a lot of parts to your question there. First of all, we always -- if you look at what we've done with stock repurchase, we want to have it funded. So if you recall a year or so ago, we took a little bit out of CapEx through 2012 and used some of that money to fund some repurchases. Depending on what happens with the other asset purchases and so forth in this Exxon deal, we obviously have increased liquidity, so we may have some additional funds, but that's foremost, I guess, in our mind is, we need to have a way to pay for it. And then secondly, of course, like I mentioned before, it depends on where the stock price is, where oil price is and so forth, whether it's more economic to buy stock or to expand floods. Where our stock has recently traded, which is we believe below proved PV-10, stock looks like it's an attractive purchase. And it's difficult for us to match that return by investing in our projects because if you can buy stock substantially below PV-10 Value, that's a pretty good deal. Just a side note, that's kind of how we purchase Encore was, essentially, for about proved PV-10. And of course, oil price was a little less at that point in time, it was in the 70s. But we probably -- in fact, it's in our slide show, and we'll probably touch on it again next week. But we probably have made 50% on that $4 billion deal, and we've not yet booked anything at EOR related properties like CCA or Bell Creek. So that was a very attractive deal, and we spent $4 billion kind of on that basis. So that's kind of how we look at it. But it's all definitely relative to where the stock is and where oil goes.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Okay, that's helpful. And then just on dividend versus share repurchase. Do you have any thoughts there?

Phil Rykhoek

Well, I think the issue on dividend is you probably -- you don't want to start dividends unless you know you can sustain it for indefinitely. And again, we're getting in a little bit into future guidance, which we'll cover more next week. But we still think we, conceptually, have a few years where we will be spending cash flow, but we expect our free cash to really start to be generated more in the second part of this decade. And so we think it might be premature to do dividends today. Probably something that we think could be a strong possibility in the future, but we want to get to the point where we have free cash in the foreseeable future.

Operator

Next question comes from the line of Hsulin Peng with Robert Baird.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

I understand that you will give us some more guidance on Monday, but I was wondering if you can kind of talk about the key drivers for tertiary production growth in '13? Because based on what I -- I mean, for Oyster Bayou and Hastings, by now you're around 4,300, and I know from the -- your presentation slide, it can peak out combined to somewhere around 20, but understand that it takes a few years to get there. So I'm just trying to get a little bit of sense as to how you will ramp in '13 and how other fields will contribute to '13 as well?

Phil Rykhoek

I think I'm going to have to ask you to wait until Monday for that one.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

All of it?

Phil Rykhoek

Maybe there's nothing to talk about next week.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay. Well, how about this. So your average CAGR for tertiary is around 13% to 15% and based on my numbers right now, it seems like probably going to be below that average for 2013. Is that fair?

Phil Rykhoek

Sorry, I'm not going to go there on that one either.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

All right. So then my other question is helium production. I know you said that it's delayed for about 6 months until mid-2013. How material -- can you just remind us how material that is in terms of the production level and the pricing again for helium?

Phil Rykhoek

Well the pricing for helium is around $70 an Mcf. Of course, gas is what it is. What's the BOE number, Bob? It's at about -- well, we expect it to -- the plant is going to -- it may take a few months to ramp up to this volume, but the initial capacity of the plant is 100 million a day of raw gas, and that translates into methane of about 1,500 BOEs a day of natural gas. There is a planned expansion of that plant to take it to 200 million a day of raw gas, but that expansion is probably at least 1.5 years off. We need to drill a couple more wells. It takes about 2 years to drill the wells, and so it's going to take us a little while to get to that next step up, so that's probably, what, '13, probably '14 or '15.

Robert L. Cornelius

Yes.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay, so '14, '15, and how much for percentage of that is helium?

Phil Rykhoek

Oh, helium is about 0.5% or 0.6% of that stream, so when I quoted 100 million a day, that's the raw 88s [ph] volume, and it'd be 0.5% or 0.6% of that.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay, got it. So it doesn't -- although in the numbers, it doesn't seem like it's very material, right, in terms of cash flow generation?

Phil Rykhoek

It's not very material. Well, it isn't real big to our company, in all honesty. And we've really purchased, as you know, Riley Ridge for the CO2. But it does produce a revenue stream. And the helium, while quite small relative to production, is a pretty large percent of the revenue, particularly where natural gas is today.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay, got it. And then I guess the last question, in general, conceptually, is it fair to assume that you plan to live within cash flow for 2013?

Phil Rykhoek

Well, I know you're determined to get 2013.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Is there any high, low?

Phil Rykhoek

But I think we have, I'll repeat, we've said publicly that we want to look at being at least close to cash flow depending on what oil price you assume. And again, I'm going to defer the precise numbers until next week.

Operator

And we'll go to the line of Pearce Hammond with Simmons & Company.

Pearce W. Hammond - Simmons & Company International, Research Division

Is there a better opportunity to acquire oilfields that you can flood in the Rockies, or is it easier to do that in the Gulf Coast, or are they both just equally hard?

Phil Rykhoek

Well, I think it's just who the potential willing seller might be. It's not that -- obviously, the area hasn't anything to do with it, it's just who owns them. So I don't -- I'd say they're equally hard. Just because we found it a little bit difficult for people to want let go of oil, oil-producing assets. I think they like the cash flow, and they like having that higher percentage of oil in their portfolio.

Pearce W. Hammond - Simmons & Company International, Research Division

Are you seeing more sort of potential assets for sale in the Rockies than in the Gulf Coast?

Phil Rykhoek

We're talking to a few, and I guess all I can say is, there's a couple in both.

Operator

And our next question comes from the line of Jason Wangler with Wunderlich Securities.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Just curious on Riley Ridge, I just want to make sure I heard it right. Are you looking now at -- when do you think you're going to be able to get the CO2 to come out of that field? I thought I heard maybe 2015 or beyond, I just wanted to make sure I heard that right.

Phil Rykhoek

No, that's not correct. There is a planned expansion of the plant, increasing the volume from 100 million a day to 200 million a day of raw gas. But CO2, while we're working on the sweetener plant, and we're working on the pipeline, and we have submitted plans, et cetera, the goal -- the current plan is that would be in place around 2017.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Okay. I just wanted to make sure I heard that right. And then just maybe for Mark, on the credit facility as we go through and, obviously, there's some moving parts here in getting the deal done with Exxon on anything that you may add. Do you see anything happening on the credit facility as far as the size of it? I mean, I know you could probably pay some of that down at least, but do you see the size of it moving around at all?

Mark C. Allen

No, I think we're in good shape for where we want to be right now. So we got plenty of cushion. We could increase the borrowing base if we wanted to, but we haven't felt necessary to that.

Operator

And we have a question from Andrew Coleman with Raymond James.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

I have a question that, hopefully, won't give us too much of an insight into 2013. But you said capitalized interest was almost $20 million for the quarter, I assume with the Greencore pipeline, we'll see capitalized interest drop down quite a bit next year?

Mark C. Allen

That would be correct. We'll probably -- at this point out, I expect that we'll capitalize it through the end of the year, while we're getting the system pressured up and running. But yes, that will drop off next year.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Okay, cool. And then secondarily, I guess, Craig, with Tinsley and Hastings, how many patterns are currently up at both those fields, and how many more are left to kind of be brought online as you expand the CO2 footprint out for both of those?

Craig J. McPherson

I don't think I have those numbers at the tip of my tongue, but we'll review that in a bit more detail next week. At Tinsley, we've got a couple more years of development there for the north fault block in that area. And in Hastings, we've got multiple years of additional pattern development, that we'll give you more detail on that next week. But we'll be doing that for multiple years, and we just -- as we progress geographically across our reservoir.

Phil Rykhoek

Tinsley is near to maturity. Basically, we're going to expand in the north area. We're trying to actually accelerate them a little bit. So that's the main focus regarding next year, but after that, Tinsley is just about developed.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

All right. So shorter term then, as you said, at Hastings, it's going to be looking for the recycle and compression and then you'll be -- once you get that, you'll start kind of go into additional patterns in Hastings?

Craig J. McPherson

That's correct. We'll talk about it next week, but we'll continue to add recycle compression at Hastings as we put additional patterns on and as the production grows and CO2 recycle volumes increase with it.

Operator

[Operator Instructions] And we'll go to the line of Noel Parks representing Ladenburg Thalmann.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Could you just go over again what you said in the initial comments about what was happening out at Heidelberg. I think, basically, you were talking about some activity at East Heidelberg, and if you could just go over that again?

Craig J. McPherson

Yes, we're expanding the development of the Eutaw zone in Heidelberg, and we're expanding the development of the Christmas zone in Eutaw -- I'm sorry, in East Heidelberg. The Christmas zone is relatively new to us. The Eutaw zone has been our primary zone of production for quite some time there.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Okay. The second zone, you said it's the Christmas, is that right?

Craig J. McPherson

That's correct.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Okay. I wasn't familiar with that. It think that's probably what caught my attention. Is it just an adjacent zone to the Eutaw?

Craig J. McPherson

That's correct. That's just part of the stacked pay horizon within the Heidelberg Field.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Okay. And, I mean, was that included from the beginning of the estimate of potential on the field?

Craig J. McPherson

Yes.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

It was?

Craig J. McPherson

Yes.

Operator

And there are no further questions at this time. Mr. Collins, I'll turn the call back over to you for closing remarks.

Jack T. Collins

Okay, thank you. And thank you, again, everyone, for your attendance and participation today.

Updating you quickly on our upcoming investor event. As you heard mentioned several times on today's call, we will be holding our annual Analyst Day in Houston this Monday, November 12. At the meeting, management will provide a detailed operational update and provide initial guidance for 2013. The presentation will begin at 1 p.m. Central time and will be webcast. The slides for the presentation webcast will be accessible through the Investor Relations section of our website.

In addition, Phil and Craig will be giving a recap of the Analyst Day presentation in New York next Wednesday, November 14, starting at 8 a.m. Eastern. Please contact me or someone in the Investor Relations group if you are interested in attending either event.

Also, Phil will be presenting at the Bank of America Merrill Lynch Global Energy Conference on Tuesday, November 13, at about 3:00 Eastern, and the slides and webcast to this presentation will also be accessible on our website.

Lastly, you can mark on your calendars that we'll be reporting fourth quarter 2012 results on Thursday, February 21, 2013, and we'll hold our conference call that day at 10 a.m. Central. Thanks, again, for joining us, and enjoy the rest of your day. Bye.

Operator

Ladies and gentlemen, that does conclude our conference for today. Thank you for your participation and using the AT&T Executive TeleConference. You may now disconnect.

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