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Denbury Resources (NYSE:DNR)

Q4 2013 Earnings Call

February 20, 2014 11:00 am ET

Executives

Jack T. Collins - Executive Director of Finance and Investor Relations

Phil Rykhoek - Chief Executive Officer, President and Director

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

Kenneth Craig McPherson - Chief Operating Officer and Senior Vice President

Analysts

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

Arun Jayaram - Crédit Suisse AG, Research Division

David Amoss - Howard Weil Incorporated, Research Division

Richard M. Tullis - Capital One Securities, Inc., Research Division

Robert Bellinski - Morningstar Inc., Research Division

Stephen P. Shepherd - Simmons & Company International, Research Division

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

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

Operator

Good day, ladies and gentlemen, and welcome to the Denbury Resources Fourth Quarter 2013 Results Conference Call. My name is Tony, and I will be your operator for today's conference. [Operator Instructions] I would now like to turn the conference over to your host for today's call, Jack Collins, Denbury's Executive Director of Finance and Investor Relations. Please proceed, sir.

Jack T. Collins

Okay. Thank you, Tony. And good morning, everyone, and thank you for joining us on today's call.

With us today on the call from Denbury are Phil Rykhoek, our President and Chief Executive Officer; Mark Allen, our Senior Vice President and Chief Financial Officer; and Craig McPherson, our Senior Vice President and Chief Operating Officer.

Before the call begins, 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 actual results to differ materially from what is discussed on today's call. You can read our full disclosures on forward-looking statements and the risk factors associated with our business in our corporate presentation, our latest 10-K and today's news release, all of which are available too on our website at www.denbury.com.

Also, over the course of today's call, we will reference certain non-GAAP financial measures. Reconciliations of and disclosure on these measures are provided in today's news release on our website and in our latest 10-K.

With that introduction, I will turn the call over to Phil Rykhoek.

Phil Rykhoek

Thank you, Jack. Thank you for joining us today. Maybe as introduction here, let me just highlight a few of the things that we accomplished in 2013, since this is an annual results conference call. Some of those, of course, that we hit our first tertiary oil production, booked our first proved tertiary oil reserves in the Rocky Mountain at Bell Creek. We put our Riley Ridge gas processing plant into service very late in 2013, in the last few days of December. We've added some man-made CO2, and actually, that's given us about 70 million per day from 2 sources in the Gulf Coast and we plan to get some more that will be expanded later this year. We were able to close on the Cedar Creek Anticline acquisition into March. That was a tax-free exchange. That was, of course, funded with the proceeds from our Bakken transaction.

And on the strategic side, that we've announced our intent to augment our shareholder return by initiating quarterly dividends. We are able to do that by making adjustments to our capital program, which allowed us to accelerate our free cash flow with almost no change through our long-term production growth, thereby, we believe we've increased the total projected shareholder return.

We also increased the certainty of our 2014 cash flow and converted some of our 2014 collars to swaps, and we've started to do the same thing in '15. And I think Mark may cover a little more of that.

The other highlight. Most recently, we've continued our share repurchase program in 2013 and into 2014, and we've now spent $900 million and purchased just over 14%, actually approaching 15%, from other shares that we had outstanding when we initiated the program in late 2011. In just the last 2 months, we've purchased an additional 4% of the company's outstanding shares, increasing our projected production per share growth in 2014 by around 40%. Said another way, or more specifically, as a result of the reduced share count, we're now expecting about 14% production per share growth in 2014 as compared to about 10% previously. We're pleased we've been able to purchase this stock at attractive prices as we believe they're very accretive for our shareholders, and we're obviously conscious of maintaining our strong capital structure. Overall, given our asset base and strategic focus on CO2 enhanced oil recovery, we believe we are positioned to deliver mid to upper single-digit production growth combined with strong dividend growth in the coming years.

With that introduction, let the kind of look at a quick recap of 2013, and then Mark and Craig will give you more details. As we announced last week, production was just right on top of our estimates, maybe slightly ahead, in spite of some weather impacts and delay in completion in the Greencore Pipeline interconnect. However, lower oil prices and higher operating costs combined to lower our bottom-line results on a sequential quarter. We believe that certain of these higher costs are nonrecurring, plus we have made cost reductions one of our key focuses at the company in 2014. So we expect to show significant progress on cost reductions during this year. Craig will give you a bit more specifics on things that we're doing to accomplish that.

Looking at production in 2014, we have started a little bit behind due to a combination of weather and delay in the Greencore Pipeline interconnect. The impact of these items, combined with a recently planned shutdown of our Riley Ridge gas processing facility for the month of December for maintenance and improvements, have led us to conclude we will likely be in the lower half of previously estimated production ranges for 2014. Again, just as a reminder though, if you look at production growth on a per-share basis, our production metrics has still improved over prior guidance, as our recent stock repurchases have accumulated 4% of the outstanding shares.

We are also encouraged by some recent production trends, particularly at Bell Creek, where production's begun to respond as expected with the completion of the Greencore Pipeline interconnect. What that does is that allows us to transport the CO2 that we owned from ExxonMobil Shute Creek plant to Bell Creek Field. Bell Creek's tertiary production recently exceeded 500 barrels a day, up from the fourth quarter average of 177.

On a non-tertiary side, we also had some positive results. If you recall, one of the reasons we elected to defer CO2 floodings at several of our fields was to give us the opportunity to first pursue these conventional projects, which we believe generate an attractive rate of return and also increase the amount of oil we ultimately recover. At Hartzog, we've now drilled and completed our first 2 infill horizontal wells in chain [ph] formation. The first well posted an initial 30-day production rate of about 400 barrels a day. That was in line with our pre-drill estimates, even though the horizontal section was a little bit shorter than planned. We just started pumping the second well a few days ago. Based on the initial rates we've seen, we expect this initial 30-day production rate to meet or exceed that of the first one. We plan to drill 6 additional wells at Hartzog this year, first of which was spud a few days ago, and we've identified 30 locations we plan to drill over the next few years.

I'll conclude my remarks by saying that we remain focused on increasing shareholder value by optimizing the development of our attractive asset base with an emphasis on cost reductions in 2014. With the recent hedge -- oil hedge conversion and current outlook for '14, we are well positioned to more than fund our planned capital expenditures and dividends for the year with cash flow from operations. Our first ever dividend payment will be paid on March 25. We continue to anticipate growing the dividend to an annualized rate of $0.50 to $0.60 next year from the current annualized rate of $0.25 per share. We believe in our strategy and its long-term economic benefits, and we expect to create value for our shareholders through a combination of growth, dividends and share repurchases.

And with that, I'll let Mark and Craig give you more details. Mark?

Mark C. Allen

Thanks, Phil. My comments will summarize some of the notable financial items in our release, primarily focusing on the sequential changes from the third quarter. I'll also provide some forward-looking estimates to help you in updating your financial models.

Our non-GAAP adjusted net income for the fourth quarter was approximately $100 million, down $65 million from the third quarter of 2013, due primarily to lower realized oil prices, higher DD&A expense and higher lease operating expense. These negative impacts were partially offset by a lower estimated income tax rate for Q4.

Our non-GAAP adjusted cash flow from operations, which excludes working capital changes, was $295 million for Q4, down approximately $55 million from Q3, primarily driven by lower oil prices. Total production for the quarter came in at just below 71,500 barrels of oil equivalent per day, roughly flat with Q3 as growth -- as number of our tertiary floods was offset by non-tertiary declines. Craig will provide more details on our Q4 production and our production drivers going forward in his comments.

Our average realized oil price, excluding derivative settlements, was $93 per barrel for the quarter, down 12% from the $106 per barrel average in the third quarter. Relative to NYMEX prices, the oil price we received was roughly $4.50 below NYMEX prices in Q4 compared to roughly flat with NYMEX levels in Q3. The average premium to NYMEX in Q4 for our Gulf Coast tertiary production, which primarily receives LLS pricing, was about $0.30 per barrel, down approximately $4 per barrel from Q3, as LLS prices were negatively impacted by additional pipeline capacity into the market. This was by far the lowest premium we have had for our Gulf Coast tertiary production in the last 3 years.

In the Rocky Mountain region, the NYMEX price differential for our Cedar Creek Anticline production was the widest we have experienced in the last few years as well, on a combination of increasing oil production and less demand due to refinery downtime.

Our Gulf Coast and Rocky Mountain region oil price differentials have improved somewhat thus far in 2014, and we currently expect that our differentials will be slightly negative to NYMEX by $1 or $2 in the first quarter and then hopefully back closer to even to NYMEX after that.

Moving on to our hedging activity. Our move to a growth and income focus and increase in our share buyback activity has increased the importance of our oil price certainty. Because of this, in December, we converted our 2014 oil collars to fixed-price swaps, averaging approximately $93 per barrel for 2014. Additionally, we have converted some of our 2015 collars to fixed-price swaps, and will likely continue to do so, if we are able to lock in prices that line up with our long-term model. Full details of our hedging positions are shown on the updated investor presentation that was posted to our website this morning.

Moving on to our operating costs. We reported pretax charge of $16 million to lease operating expense in Q4 related to the Delhi Field incident, bringing our total expense related to this incident to $114 million, the majority of which has already been spent. These charges reflect our estimated costs to remediate area and cover other estimated costs associated with the release. However, it is possible that other charges could arise that are not estimable or known at this time. This charge also does not reflect any potential insurance recoveries for these expenses, which we are not able to record until receipt is virtually certain.

Excluding the Delhi charge, our overall tertiary lease operating expense increased sequentially on a per-BOE basis from Q3, primarily due to the startup of Bell Creek in the fourth quarter, which has a high unit operating cost during the early startup phase, and increase in our workover expenses, and higher CO2 costs, primarily as a result of the addition of higher-cost man-made CO2 supply. I would note that our full year 2013 operating costs per BOE, excluding the Delhi charge, was about $24 per BOE, which is at the lower end of our expectations, and though it -- which was [indiscernible] be in the mid-$20 per BOE range.

For 2014, we expect our overall LOE to be in the mid-20s on a $1 per BOE range basis, excluding any potential additional Delhi-related remediation expenses. And I would expect the first quarter might be slightly higher with the slower production start to the year.

G&A expense was roughly $34 million in Q4, down from $36 million in Q3. For the fourth quarter, about $9 million of our G&A expense was stock-based compensation. For 2014, we expect G&A expenses to be in the upper $30 million to mid-$40 million range each quarter, with approximately $7 million to $10 million of that in stock-based compensations. You should expect the first quarter will be near the upper end of the range due to taxes associated with the bonus and long-term incentive payments in the quarter.

For depletion, depreciation and amortization, our overall DD&A per BOE increased to about $22 per barrel in Q4 from $19 in Q3, primarily due to Bell Creek costs being added to our depletion calculation, increased finding and development costs and increases in CO2 and other fixed asset depreciation. This was slightly higher than our guidance of $20 to $21 per BOE as we had larger than unusual depreciation in our other our fixed assets this period, which increased our rate by approximately $1 per BOE. For 2014, we expect our DD&A rate to average between $21 and $22 per BOE.

Our effective income tax rate for Q4 was approximately 31%, as our estimated statutory rate decreased from 38% -- sorry, from 38.5% to 38% during the quarter. And the impacts of other true-ups in our estimated taxes for the year were also recognized in the quarter.

Current income taxes represented a $13 million benefit in Q4, since the placement of Riley Ridge into service allowed us to recognize certain associated tax benefits that were not previously anticipated in our tax provision. For 2014, we anticipate our effective tax rate will be between 37% and 38%, with current taxes representing between 20% and 30% of total taxes.

Moving to our capital structure. Total debt at December 31 was approximately $3.3 billion, nearly unchanged from September 30 levels. We had $340 million drawn on our bank line at December 31, up from $310 million at the end of Q3, and we ended Q4 with roughly $12 million in cash. Based on our current assumptions for cash flows and capital expenditures for 2014, along with our share repurchases to date, we anticipate ending the year with bank debt between $500 million and $600 million, excluding the impact of any incremental share repurchases in 2014.

Interest expense, net of amounts capitalized, was $40 million, an increase from $35 million in Q3, mostly due to a $5 million reduction in capitalized interest following the start-up of the Bell Creek CO2 flood. With the placement of Riley Ridge into service, we expect capitalized interest to decline further in 2014 to between $5 million and $10 million per quarter, with the amount being closer to the lower end of the range early in the year and increasing throughout the year. Our capitalization metrics remained solid as our debt-to-capital ratio was approximately 38% at quarter end and our debt to 2013 EBITDA was about 2.4x, and it would have been about 2.2x if the Delhi remediation and other nonrecurring items were excluded.

Our 2014 capital budget remains at $1.0 billion, plus an estimated $125 million for other items including capitalized interest, internal acquisition, exploration and development costs and preproduction EOR startup costs.

As Phil mentioned, we've been actively repurchasing stock over the last few months, spending about $250 million on share repurchases in the fourth quarter and to-date in 2014. With these purchases, we have repurchased over 14% of our total shares outstanding since October 2011, an average price of just under $15.70 per share, and we have $250 million remaining authorized under our program.

And now I'll turn it over to Craig for an operational review.

Kenneth Craig McPherson

Okay. Thank you, Mark. Total company production for the quarter was 71,466 barrels of oil equivalent per day, resulting in the full year production coming in just above the midpoint of 2013 guidance. Our tertiary operations performed in line with our estimates in the fourth quarter, oil production averaging just above 38,600 barrels per day. Our tertiary oil production increased on a sequential quarter basis due to continued growth at Heidelberg and Oyster Bayou fields, improved production facility run time at Hastings, increased CO2 injection at Delhi, and a gradual production response at Bell Creek. These increases were partially offset by continued declines at our mature tertiary fields.

As you will recall, we halted CO2 injection into the southwesternmost area of our Delhi Field beginning late in Q2 as we remediated portions of that area from a release of well fluids. We have resumed injection into all but the directly impacted area of the field, and as a result, sequential production increased by nearly 280 barrels per day. We anticipate Delhi's production to be relatively flat at the fourth quarter level in 2014 until the reversionary interest occurs later in the year.

At Hastings, sequential production increased by about 570 barrels per day in Q4, as the facility run time improved and newer areas of the field began to respond to CO2 injection. We do expect production growth in 2014 at Hastings as additional patterns began to respond to CO2 injection.

Oyster Bayou continues to show steady growth, increasing about 660 barrels per day sequentially in Q4. We are currently developing a lower A-2 Zone at Oyster Bayou and optimizing the initial A-1 Zone. As a result, we see additional production growth at Oyster Bayou in the second half of 2014 as we start seeing a production contribution from the A-2 Zone late in the year.

Heidelberg was another bright spot for the quarter with the field's tertiary production increasing by about 650 barrels per day from Q3 levels. We do expect production growth from Heidelberg in 2014 as our development program will focus on expanding the Christmas Zone development on the east part of the field. For our mature area tertiary properties, production declined by 8% sequentially and was 12% lower year-over-year. The sequential quarter decline was a result of the combination of factors, including some weather-related downtime and a temporary shutting of several wells for planned workovers. We have various capital projects planned that we anticipate will lower our mature area production decline in 2014.

With that, let's move to the Rocky Mountain region. Bell Creek's tertiary production increased gradually during the fourth quarter, as the field continued to respond to the CO2 injection we started earlier in the year. Even though our CO2 source volumes from ConocoPhillips were lower than planned, the oil production response to the field has recently increased as we've been able to augment our CO2 supply for the field with our CO2 from ExxonMobil's Shute Creek plant, following the completion of our Greencore Pipeline interconnect.

We do anticipate tertiary production at Bell Creek to grow throughout 2014 and for the CO [ph] to be a key driver of our overall planned tertiary growth for the year. At Grieve Field in Wyoming, we continue to inject CO2 and water to build operating pressure, and we anticipate first oil production in 2015. Production from our non-tertiary assets decreased to 32,863 barrels of oil equivalent per day from 34,018 in the third quarter, primarily due to production declines at our non-tertiary Texas and Rocky Mountain fields.

Our Shute Creek gas line production was 18,601 barrels of oil equivalent in the fourth quarter compared to 18,872 in Q3. The decline in non-tertiary production was primarily attributable to above-normal levels of weather interruptions and repair-related downtime. Our team continues to look for opportunities to enhance production on our non-tertiary assets in advance of our planned CO2 floods.

Phil mentioned and gave overview of our initial Hartzog Draw drilling results, and we've been encouraged also by our recent Cedar Creek Anticline results. During the fourth quarter, we drilled 3 new horizontal wells in CCA, which had average initial 30-day production rates of approximately 160 barrels of oil per day. That exceeds our pre-drill expectations by over 20%. In 2014, we plan to drill 11 more horizontal wells, which will be part of the multi-year program to further develop the water flood. Similar to Hartzog, these horizontal wells in CCA will have utility both in the current water flood and the subsequent CO2 flood.

I'll move now to the lease operating expenses. Our lease operating expense per barrel of equivalent production, excluding the Delhi Field charge, increased by 13% from the third quarter to $26.24 per BOE in the fourth quarter. Operating costs for our tertiary properties, excluding the Delhi charge, averaged $28.72 per barrel during the fourth quarter, and that's an increase from $25.08 in the prior quarter. The sequential increase in quarterly LOE, excluding Delhi, reflects more workover activity, additional operating costs during the startup phase at Bell Creek and higher cost of man-made CO2s. The increased workover activity resulted in approximately $2 of BOE increase compared to the previous quarter. The increased workover activity represents an emphasis in the quarter on several P&A wells' well integrity, conformance work, and a unusually high number of extensive well repairs. Much of this work will be nonrecurring, and we expect our overall 2014 operating costs to be in the mid-$20s per barrel. Although man-made CO2 has raised our operating cost, it has reduced our CO2 capital cost, in particular at Jackson Dome, where it effectively replaces the drilling of several CO2 wells.

We have various initiatives underway across the company to reduce both our operating costs and our capital costs. So let me drive through few of them. We have a team looking at different designs of our future CO2 facilities to reduce the cost to build them and install them. We're spending more time evaluating multiple field development options to find the optimum development plan to maximize the value of the field. We're placing more emphasis on improving the run time of our compression through improved maintenance and reliability. We're focused on optimizing our very large usage of electricity. For us, employing the use of root-cause failure analysis to understand -- understand each equipment or well failure and why it occurs so that we can fix the root cause preventing the failure from being repeated. Our objective is to continue Denbury's tradition of moving quickly, while also challenging ourselves to optimize each component of our business, and looking for new ideas.

Let's move now to our CO2 supply and transportation operations, which in general are performing quite well and fulfilling our need in our growing demand from tertiary oil production operations. In the Gulf Coast region, we've produced just under 900 million cubic feet per day of CO2 from Jackson Dome during the quarter. We continue to make good progress in increasing our supply of man-made CO2 sources. Today, we're currently injecting about 70 million cubic feet per day of CO2 being captured from both Air Products and PotashCorp into Denbury operated Gulf Coast fields.

Additionally, we should begin receiving about 115 million cubic feet per day of CO2 from Mississippi Power's plant to our Mississippi tertiary operations late this year. In addition to these sources, we're in various stages of discussions with other project sponsors that could further increase our Gulf Coast CO2 sources later this decade.

In the Rocky Mountain region, we've recently announced that we placed the Riley Ridge gas processing plant into service late in 2013, slightly ahead of our previously estimated in-service date of the fourth quarter of this year. We are currently selling both methane and helium from the plant, and are reinjecting the residual CO2-enhancing gas. As is typical of most new complex processing plants, we're learning how to optimize equipment and process so our run time could have been intermittent, but they are also steadily improving.

Also, we did have some operational downtime in the first quarter when the supply of electricity was temporarily stopped. We will have a month of previously unplanned downtime in summer related to a turnaround during which we plan to perform some maintenance and make some modest, low-cost improvements to increase the operability of the plant. Overall, Riley Ridge is well on its way to ultimately becoming our anchor source of CO2 in the Rocky Mountain regions.

With that, let's talk about proved reserves. Last week, we announced our year-end 2013 proved reserve for 468 million barrels of oil equivalent. We have 2 significant reserve additions, which enable a 330% reserve replacement during the year. We added 34 million barrels from our new CO2 flood at Bell Creek, and also added 43 million barrels from acquisitions, primarily Cedar Creek Anticline. The estimated discounted net present value of our proved reserves before income taxes was $10.6 billion.

And with that, I'll turn the call back over to Jack.

Jack T. Collins

Okay. Thanks, Craig. Tony, that concludes management's prepared remarks. Can you please open the call up for questions?

Question-and-Answer Session

Operator

[Operator Instructions] And first in queue is Jason Wangler with Wunderlich Securities.

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

Just if I heard you right, Craig, I think you said that Delhi -- you expect it to be flat for 2014. Can you just walk through kind of what you see the life cycle of that field doing with, obviously, the issues last year? Is that going to be flat this year and then hopefully start to increase, or where are we out there?

Kenneth Craig McPherson

I think it will be flat through the end of the third quarter when we have our reversionary interest. When our reversionary interest occurs, the production will drop proportionately. We do expect productions to start growing in 2015 as we continue development of that field.

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

Okay. So it's with the interest and then it'll grow from there on a gross basis. Okay, that's helpful. And then just the only other thing I was just curious on is on the share buybacks. I mean, you still got $250 million left -- I mean, I know the party line has been when you're under the proven asset value, which is obviously well ahead of where you are at on a stock price basis. I mean, what is the comfort level as far as that $250 million or maybe even extending that further depending on where you see the value there?

Phil Rykhoek

Well, it's subject to board authorization, and of course, it's a bit subjective. I think the key thing to continued buybacks, of course, pieces value relative to NAV, the current oil price, et cetera, but we also have to look at how we fund it and what that does for our balance sheet. So I think to the extent that we spend the full $250 million or possibly extend that, I mean, I think we'd have to look for ways to fund it, which most likely would mean potentially a trade for capital expenditures.

Operator

Our next question in queue will come from Arun Jayaram from Crédit Suisse.

Arun Jayaram - Crédit Suisse AG, Research Division

Phil, just a quick question. When you shifted to the value-over-volumes strategy, you talked about Denbury embracing an execution culture. We've seen some issues at Delhi, at Riley Ridge and some timing delays at Bell Creek. I just wanted to see if you could comment -- do you think these are isolated in nature? And as we move for the '14 and '15, what are some of the risks that we should maybe pay closer attention to as you look to execute your program?

Phil Rykhoek

Well, I think that's an excellent question. When we said that we were focusing on that, we obviously had a little bit of a precursor of what was happening. That's one of the downside of doing results in February just looking back at the fourth quarter. So we knew there were some of these issues out there that was part of the impetus to really focus on cost reductions. We do think, as Craig mentioned, many -- much of this is nonrecurring. Workover costs were a couple of bucks higher than normal. Normal trend, if you look at it, is about $3 a barrel. It was nearly $6, actually, $5.70. So I think we are in that transition of getting the results. I think it may take us just a little bit before you see some really improved results. But this was -- kind of started late last year; and unfortunately, the results we're talking about today, most of those operation results were before we really kind of pushed this.

Arun Jayaram - Crédit Suisse AG, Research Division

And just zeroing in on Bell Creek, I know you were having some -- a little bit of intermittent supply issues from the Lost Cabin Creek plant. With Shute Creek and the interconnect done, are you good in terms of having a reliable CO2 supply to Bell Creek?

Phil Rykhoek

Well, it's much better. I mean, conceptually, just to tone the details a little bit, I believe, if you've -- well, I know you follow this, but for the ones who maybe haven't, we were expecting the interconnect to be finished in late November. Instead, partly due to permitting and so forth, it was finished in late January. Today, we're getting a lot of CO2 into Bell Creek. We're seeing it respond nicely. But conceptually, we're probably 30 to 60 days behind. So if you look at the production growth curve, it's just lagging. And it's -- we're not concerned about the trajectory. We're not concerned about the response. It's just a timing issue, because we weren't able to get as much CO2 there as we'd hoped. Now we're getting the CO2 from Exxon, and we still are reliant obviously on ConocoPhillips also. So to the extent that they have good run time there, that will obviously help. They had a few -- we had a few problems kind of third quarter and into fourth, but late in the fourth quarter, the Conoco was a bit more consistent.

Arun Jayaram - Crédit Suisse AG, Research Division

My last question, Phil, regarding Riley Ridge at the plant turnaround. Are there going to be any operating costs that flow through LOE for that turnaround? Or is it going to go be all capitalized? And just maybe some help on what that -- how much capital for that turnaround?

Kenneth Craig McPherson

This is Craig. It's -- the total cost, I'm not quite sure of the split between CapEx and OpEx, but the cost of that is probably $5 million or $6 million.

Operator

Our next question will come from David Amoss with Howard Weil.

David Amoss - Howard Weil Incorporated, Research Division

Just wanted to kind of get into a little bit more of the nitty-gritty at your mature properties. It looks like that you mentioned there is a little bit of a larger sequential decline there 4Q versus 3Q, and weather -- a combination of weather, some workovers. Can you kind of go into the details of what the weather impact was in 4Q? Why you're doing more workovers and well repairs? And then how that's kind of bled into the first quarter and what you expect the trend to be there at the mature properties through 2014?

Kenneth Craig McPherson

Well I'll start. So we'll start with some of the weather-related events. We did have some pretty severe weather really throughout our Gulf Coast assets in the fourth quarter, unexpected, and so in particular we had some power outages. When the power turns off, our compressors stop, and it's a significant impact. I don't have that weather-related downtime quantified. That was a pretty big impact. The increase in workover costs was a bit of a rash of well sizers [ph] as well as well integrity issues that we [indiscernible] on. So they were, in particular, extensive relative to our average costs of work-around. I think that's just an anomalous event. I think we'll get back to our average cost of a workover, but obviously we had an increase there. We also had -- part of the increased cost there is a focus on P&As, and so we've had some additional work really in response to -- as we learned from the Delhi event, we've left our threshold and standard of what's an acceptable well and what's an acceptable flood, so that requires us to do some more well integrity work, and some more P&A work. So that's really what's driving that fourth quarter increase in workovers. I'd add one more component to that: it goes back to Phil's comment about optimization. But we're doing more work on conformance and we saw some opportunities to better optimize our floods, and so there was a big emphasis in the fourth quarter for some conformance work. So all of that combined added to an increased focus of spending in the mature assets. And frankly, because we had some wells down because we're working on them, production was a bit off there relative to what'll happen.

David Amoss - Howard Weil Incorporated, Research Division

Okay, great. That's really helpful. And just one more. Can you talk about the Rockies differentials. I mean, you had some refinery downtime. It sounds like there's some transportation constraints. I mean, is all that kind of behind you at this point or does that bleed through into the first half of '14 as well?

Mark C. Allen

Into the first couple of months or month or 2 here, but we are seeing it right now turning back to kind of historical norms, which is kind of in the $6 to $7 minus range NYMEX. So, yes, we had the refinery issue. I think in St. Paul that kind of carried into Q4 and just caused some bottlenecks and price impacts there. So we are seeing that turn around as well as in the Gulf Coast, so the LLS has widened back out a bit now. So we're feeling good about where we sit there.

Operator

Our next question and you will come from Richard Tullis with Capital One.

Richard M. Tullis - Capital One Securities, Inc., Research Division

Just 2 quick questions from me. Craig, going back to the Rockies conventional drilling, what are the formations being targeted for 2014? I think you had mentioned about 11 wells to be drilled. Are those all Shannon wells or is it a combination of targets?

Kenneth Craig McPherson

No, it's Shannon.

Richard M. Tullis - Capital One Securities, Inc., Research Division

All Shannon. What are the costs for the new wells?

Kenneth Craig McPherson

Costs us about $7 million, $7.5 million.

Phil Rykhoek

That's gross.

Kenneth Craig McPherson

That's gross, yes.

Phil Rykhoek

By net, it's $5 million to $6 million.

Kenneth Craig McPherson

Yes.

Richard M. Tullis - Capital One Securities, Inc., Research Division

Okay. And then on the Bell Creek reserves -- I know you were able to book a good amount in last year's year-end report. Based on where we are now, how much is left to bring to 1P, and what's the approximate timing there?

Mark C. Allen

You mean, bring to 3P?

Richard M. Tullis - Capital One Securities, Inc., Research Division

Bring to proved.

Phil Rykhoek

I'm not sure I followed your question. At Bell Creek?

Richard M. Tullis - Capital One Securities, Inc., Research Division

Yes.

Richard M. Tullis - Capital One Securities, Inc., Research Division

Well, we booked 34 million barrels at Bell Creek. We estimate the total reserves there of 40 million to 50 million. So it could be 5 million to 15 million more, I think if that answers question. That's not too atypical of how we book many of our floods. Usually it's in the 75% range at the estimated 3P number, and this one came out pretty close to that.

Richard M. Tullis - Capital One Securities, Inc., Research Division

Okay. So you don't anticipate bringing in any more prove there for the next year or 2?

Mark C. Allen

Yes. I use that -- Yes. No, I wouldn't expect anything in the next year or 2. I think there would be potential to add to that, say, 4 or 5 years out.

Operator

Our next question in queue will come from Brian Kuzma [ph] with Fitcom [ph].

Unknown Analyst

I just wanted to follow up on your anthropogenic sourcing of CO2 in terms of what's the relative supply cost there relative to using Jackson Dome? And then also, you had mentioned some sort of CapEx savings from procuring it elsewhere. What would you have had to spend to kind of -- to get that level of CO2?

Mark C. Allen

Well, our Jackson Dome CO2 is, it is by far the cheapest that we have cost, I believe it's in the $0.30 to $0.40 operating cost and there is probably another $0.10 of DD&A. So -- and you're probably approaching $0.50 in Mcf for Jackson Dome. The anthropogenic, on the other hand, is probably close to twice that. We hesitate to give precise numbers because it does vary a bit by contract. But generally, it approaches $1, again, with some variability. We also have similar cost of CO2 from the Lost Cabin plant. ConocoPhilips is also on that same general range. Although the CO2 they're getting from Exxon is quite a bit less, of course, we prepay for most of that. So there is a bit of variability. We, of course, have the Mississippi power plant coming on later this year, and we anticipate that it will -- maybe it's more than Jackson Dome, but maybe a little less than some of the current anthropogenic. So I don't know if that gives you a flavor. It's in some way, I guess, it's the range of, say, $0.40 to $0.50 at Jackson Dome to up to $1 or may be just a little bit above for some of the others. Yes, and the well. Of course, the well cost -- we don't have to drill wells like we did for these anthropogenics, or of course, you say about 15 million or 16 million per well that we're drilling in Jackson Dome, and that 70 million a day replaced at least 1 well maybe 2.

Kenneth Craig McPherson

Yes. And the anthropogenic is concert rate forever. The production out at the Jackson Dome declined, so eventually you got to keep spending that money to get that constant rate.

Unknown Analyst

And then going back to this mature field declines that you guys are seeing, what are your total proved reserves on just the mature fields?

Mark C. Allen

If you wait one second, we probably can give you that.

Unknown Analyst

Maybe while you look that up, just to put it in context. Like when I think of CO2 declines, I'm typically thinking like 5% kind of terminal declines, and yet it looks like so it's down 12% this year, it looks like it was down 13% in '12. Is like -- is there something else going on other than just flat decline? And is there any way that you can actually get this production back up?

Mark C. Allen

Yes. Well one, the answer to your first question. I believe we were just under 50 million barrels of reserves on mature properties. Actually, there'll be detail on some of this with the 10-K we hope to file next week. And there'll be a schedule in there that has this. Back to your question, 12%. I mean, normally, I've always tried to guide people to around 10%, so it's not too far off. We actually anticipate the decline in 2014 to be less than 10% or i.e. maybe offsetting a little bit of the overreach in 2013. As Craig said, some of that was kind of -- I think you've check-focused too much on fourth quarter rate because there was a little bit of weather and other things in the fourth quarter, but we are actively working to manage the conformance which, coincidentally, was part of the LOE cost. And so we would think -- I mean, if you look kind of long term, I think 10% is a fair rate. We think '14 will be a little bit less than that.

Unknown Analyst

So then like, when Tinsley goes into decline, will it have a long plateau period or does it go into 10% decline in '15-'16 time frame?

Mark C. Allen

Well, it actually has been in a plateau if you look at it the last, what, 3 years or '12 and '13 and probably '14 are in that 8,000-barrel-a-day range. So it's kind of in that plateau period now. It is finishing up the last bit of work there, so probably in next year, in '15, it probably will start declining. Typically, the decline gets a little bit faster in their first year or 2. And if you look, we have that in our slide show, I think we showed the initial decline rates by field in our slide show, and I think we've saved like 15% and up to 25%,

Kenneth Craig McPherson

Yes.

Mark C. Allen

So normally your first year or 2 will be a bit steeper and then it will slow down.

Operator

The next question will come from Robert Bellinski with Morningstar.

Robert Bellinski - Morningstar Inc., Research Division

Just a quick one from me, following-up on those new wells for the Hartzog Draw. Maybe I missed this earlier, but can you give us some sense of what led you to drill that horizontal shorter that you planned?

Kenneth Craig McPherson

Well, for the first well, we ran into some drilling difficulties, so we called it short. Being able to keep spending the money in incremental value -- we thought we [indiscernible] we did. So that's the reason. We finished the second well. It actually came in -- we got all the TD and it actually came in under cost. So we believe we've optimized that flood, and we continue to frankly we think we've got optimization opportunities on the drilling cost. We're very optimistic.

Operator

Our next question in queue will come from Stephen Shepherd with Simmons & Company.

Stephen P. Shepherd - Simmons & Company International, Research Division

I'm just trying to better delineate the drivers behind the decision to now target the well into the '14 production guidance range. To what extent, if you have the ability to break this out, is that being driven by the Riley Ridge shutdown versus weather versus other variables? Is one item a larger driver than any of the others, or are there any other factors that led to that? Just trying to get some more detail there.

Phil Rykhoek

Well, it's really the -- it's probably the latter 2. I mean, I don't think weather hurts us in January, but obviously, we don't anticipate that going forward and it probably wasn't a huge driver. We did have facility shutdown for a couple of days because of lack of power at some of our EOR fields. So it didn't help us, of course. But we can say that's a more minor effect. But shutting down Riley Ridge for a month or an estimated month is a few hundred barrels a day to the annual average. And we talked about earlier, there was a question on Bell Creek. I mean, Bell Creek is responding well, but it's probably running 60 days behind. So when you kind of factor that in, and Bell Creek's one of the strong drivers of 2014, that's why we kind of focused on those. I mean, if you split hairs, you can, obviously, find pros and cons in various fields, but we felt like those 2 are probably what kind of led us to think it's going to be hard to recover at Bell Creek and you're not going to recover Riley Ridge, unless we can do that turnaround faster than a month.

Operator

Our next question in queue will come from Noel Parks with Ladenburg Thalmann.

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

Sorry if I missed couple of these from earlier, but in the financials I have a couple of questions. The capitalized interest for the quarter, I think, was a good bit higher than what the guidance was for fourth quarter. Is that a trend that'll continue?

Mark C. Allen

No, I think it was around $15 million, down from $20 million in the prior quarter, and we see that dropping between $5 million and $10 here per quarter in 2014 with the first quarter being on the lower end of the range. With Bell Creek being on and also with Riley Ridge going into service in late Q4, those were 2 of the items that we had capitalized interest on that will not be there going forward, so it'll drop a fair a bit of early in the year.

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

And one other line in the income statement that trend a little differently was, I saw in the revenues, the CO2 sales and transportation fees were, I think, higher than they had been before. Is that related to the man-made CO2?

Mark C. Allen

Not the man-made. That really relates to just our CO2 sales and transportation fees through pipelines and such. So yes, it was maybe up $1 million from a year ago. So it just has to do with amount of CO2 we're moving through.

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

And just one other thing. On Delhi, if I understood the comments right, pretty much it looks like the remediation costs that are anticipated have essentially been set aside. But I think you did mention something about -- it's not impossible, that there could be some other charges. Do you have any idea of sort of what the nature and maybe the size of those might be sort of worst-case scenario?

Phil Rykhoek

No. A lot -- most of the surface that we remediated -- it was work pretty much done with our cleanup at this point now. We do still have some potential claims from third parties for various things and we've tried to kind of estimate those. But those obviously could vary, and I think that's where you might see the variability going forward.

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

Okay. Do think it'll take most of the rest of the year to get those third-party items cleaned up, or do you think they'll get wrapped up more quickly?

Phil Rykhoek

It depends on how nice to us they are. I mean, it's -- it could get solved very quickly or it could even be litigated. Kind of the same thing with the insurance proceeds. We're working on that. But that could obviously take us a couple of years to settle those numbers, because we'll have to negotiate it and potentially even litigate it.

Operator

Our next question in queue will come from Hsulin Peng with Robert Baird.

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

Just one quick question. I was wondering if you can help us a bit more with the production ramp in 2014. Just thinking that -- it seems like first quarter production with the -- most of the impact on the lower guidance range is coming from the -- is going to impact 1Q. So is that a fair -- so 1Q -- I'm just trying to understand better the ramp of production in '14?

Phil Rykhoek

It's really pretty steady, I think that January is going to be a bit light because of some of the weather and some of those issues, and also Riley Ridge was still kind of starting and stopping and making adjustments. Riley Ridge is now producing, what was the number, 9 million a day?

Kenneth Craig McPherson

Yes.

Phil Rykhoek

So it's kind of on forecast right at the moment. But we kind of have -- I mean, we generally have pretty steady growth throughout the year.

Operator

Thank you very much. At this time, there is no additional questions in queue. Please continue.

Jack T. Collins

Okay. Before you all go, let me cover a few housekeeping items on the conference front. Several members of our management team will be participating in Investor conferences over the next few months. Please check the Investor Relations section of our website for the details on these presentations, including the webcast and the slides for them. Also please note on your calendars that we plan to report our first quarter 2014 results on Thursday, May 1, conference call that day at our usual time of 10 a.m. Central.

Thanks again for joining us today, and don't hesitate to contact any of us with follow-up questions.

Operator

Thank you very much. And, ladies and gentlemen, this conference will be available for replay after 12:30 p.m. Central Time today running through May 20 at midnight. You may access the AT&T Executive playback service at any time by dialing (800) 475-6701 and using the access code of 260593. International participants may dial (320) 365-3844.

That does conclude your conference call for today. We do thank you for your participation and for using AT&T Executive Teleconference. You may now disconnect.

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