Denbury Inc.

Thank you, Lori, and good morning, everyone, and thank you for joining us today. With me 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 Brad Kerr, our Senior Vice President, Development, Technical and Innovation.

Before we begin, 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 disclosure 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 posted on our website at denbury.com. Also, over the course of today's call, we will reference certain non-GAAP measures.

Reconciliations of and disclosures on these measures are provided on today's news release. With that, I'll turn the call over to Phil.

Thank you, Ross. As everyone knows, the precipitous drop in oil price obviously has impacted us as well as the entire industry.

Fortunately, we made quick early adjustments to reduce our spending, and we still currently believe we can fund our projected 2015 capital program and current dividends with the projected cash flow and actually may even generate a little bit of free cash for the year. Further, we reaffirm that we expect the midpoint of our production range to be roughly flat with 2014 production.

We're using the slowdown to our advantage, and we started a process a few months ago to do a complete review of our field and operations with a goal to complete the initial review by mid-year, basically looking for ways to become more efficient and ways to reduce costs. We call these teams the innovation and improvement teams, and I'm pleased to report the process is going very well.

Many potentially rewarding ideas have been presented. We're starting to scrub those, prioritize them and work toward implementation.

We're not quite ready to share the specifics with the public but we will share more about this -- but we believe this process will make us a stronger company. Brad will share more about this in a little bit.

In addition, all of our employees are looking for ways to reduce cost and increase efficiencies in everything we do. And I expect to see additional improvements as we go forward.

We are seeing continuing improvement in cost as one example, evidenced by our fourth consecutive quarterly drop in LOE if you exclude the unusual items relating to Delhi and Riley Ridge. Fourth quarter operating cost averaged $22.64 per barrel, that's 14% lower than the fourth quarter of 2013.

As I mentioned, we expect to fund our capital program and dividends this year with cash flow from operations. And in 2014, we generated approximately $107 million of excess free cash flow, that's defined as cash flow less capital expenditures and dividends.

That demonstrates our disciplined approach to balancing our cash flow and is a result of our ongoing cost saving measures, as both capital and LOE came in under budget for the year. As Mark will share in more detail, our balance sheet is in good shape.

We have the right mix and type of debt in our capital structure, and we're confident we can weather this storm. During 2014, we completed a refinancing of our sub debt and amended our bank credit agreement, both of which gave us maturities that are several years away.

We locked in attractive interest rates and we reduced our out-of-pocket interest costs. In addition, we have extensive hedges in 2015 which will provide us significant incremental cash flow.

In addition to our capital structures and hedges, we do get a direct benefit on our out cost as the cost of CO2 correlates with the price of oil, and we have seen that begin to come down. We are also quite flexible on what we spend and how fast we develop an EOR flood.

Some people think that once you start an EOR flood, you can't stop or slow down development. And that really isn't true, as we can adjust the development pace to almost any rate, which gives us significant flexibility during a period of low prices.

We don't have any lease expiration issues like most of our peers, so our assets will not go away if development has slowed. By reducing our capital development program and focusing on ways to drive margin expansion, we should come out of this difficult time stronger and more prepared to deliver in 2016 and beyond.

So with that introduction, let's look a little bit at operations in a little detail on the fourth quarter. Total company production for the quarter was slightly above our guided range of 74,000 barrels a day.

Our tertiary production averaged just under 41,900, up just slightly sequentially and even after absorbing the lower production related to the reversionary interest at Delhi. The strong growth areas during the quarter were Heidelberg, Oyster Bayou and Tinsley.

At Hastings, sequential production decreased slightly by 100 barrels a day as we slowed the development down slightly in the new Fault Blocks B and C in order to convert them to a series flood and complete plugging and abandonment work. We are pressuring up the new reservoir and expect to start producing from the B and C Fault Blocks within the next couple of months.

Oyster Bayou continues to show solid reservoir response, increasing 1,000 barrels a day, roughly sequentially in Q4. This increase is due to strong response from new patterns in the A-2 Zone, which we have discussed on prior calls.

The development of Oyster Bayou's A-2 Zone was completed at year-end and we expect to see additional production growth in early 2015 as additional patterns respond. But we do expect production to peak this year.

At Heidelberg, our tertiary production increased nearly 450 barrels per day from Q3, the result of installing additional compression in early Q4 and additional development in the field. We expect continued moderate production growth at Heidelberg for 2015 as the new Tuscaloosa units and Christmas Phase 3 patterns continue to respond.

Successful conformance[ph] work in the Utah is also helping. As mentioned earlier, Tinsley's production increased modestly, adding over 450 barrels per day from Q3, the result of installing additional compression in early Q4; completion of the last phase, which is Phase 8 of development; and modified injections to improve performance in the East Fault Block.

This field continues to perform strongly, although production is believed to be at or near its peak. For our mature area tertiary properties, production decreased just under 1,000 barrels per day due to normal declines after being nearly flat for the prior 3 quarters.

We are reviewing these older fields with the IITs as well as newer, larger floods, and optimistic we can mitigate some of these declines in the future. Production at Conroe increased by over 1,300 barrels a day equivalent on a sequential quarter following the resolution of third party gas processing issues plus additional recompletions and workovers.

Let's now move to the Rockies. Our Cedar Creek Anticline production was flat sequentially during Q4 as the production declined at the Cedar Hills South unit related to water injection facility failure in Q3 was offset by improved waterflood performance in the mature areas.

Bell Creek tertiary production was flat quarter-to-quarter due to temporarily shutting in injectors in our first phase of development to secure some off-lease wellbores. We expect Bell Creek production to continue to grow in 2015 as we restore full injection into Phase 1, and we expect Phase 3 to begin to respond.

Hartzog Draw production was up slightly quarter-to-quarter related to the installation of artificial lift in our new horizontal wells. Looking at CO2 supply and transportation in the Gulf Coast.

We produced approximately 880 million cubic feet of CO2 per day from Jackson Dome, coupled with approximately 70 million cubic feet a day from industrial CO2 supply, meeting the demands of the EOR fields. Our man-made supply is expected to get a boost from the gasification and carbon capture systems at Mississippi Power's Kemper County power plant in the next 12 to 18 months.

We recently completed the only well planned for 2015 at Jackson Dome. We're awaiting completion and flow results, but early indications are that this well will be productive.

We have completed the Webster pipeline from Denbury's Green Pipeline to Denbury's Webster field, and that was completed on time and on budget. In the Rockies, we received over 110 million cubic feet a day of CO2 from our combined sources at LaBarge and Lost Cabin.

Operational challenges at our Lost Cabin facility appear to be rectified with a new piston head design that has been installed and has been running without issue. Our technical teams have been looking at multiple options to permanently solve the issues at Riley Ridge.

Efforts are currently underway to determine solutions for the sulfur deposition in the wellbore. Engineering has engaged several consultants to assist us with this solution.

Based on our current plan, we do not expect natural gas or helium production for the field to resume until 2016. This will not have a significant impact on our near term cash flow as it is only marginally economic with the natural gas and helium.

But long term, of course, Riley Ridge represents the anchor source of CO2 for the Rockies. And with that, I'll turn the call over to Mark to give you financial details for the quarter.

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 guidance to help you in updating your financial models to reflect our current outlook for 2015. Let me start off by saying that we are pleased with our Q4 2014 results, with our adjusted earnings and cash flow coming in ahead of consensus.

Our non-GAAP adjusted net income for the fourth quarter was $93 million or $0.27 per diluted share, that was up $2 million from the third quarter due primarily to higher production and lower costs, offset in part by significantly lower oil prices. However, our hedges buffered most of the drop in oil prices during Q4.

Our GAAP net income was significantly higher than this due mostly to a pretax gain of $451 million on fair value adjustments related to our hedge positions. Turning to cash flow.

Our non-GAAP adjusted cash flow from operations, which excludes working capital changes, was $350 million for Q4, up $34 million from the third quarter, that was due primarily to a $43 million benefit for current income taxes. Lower prices reduced our cash inflows by roughly $161 million this quarter.

However, the changes in our hedge receipts offset $129 million of this decrease; and higher production increased our cash flow by $9 million, along with other cost reductions. Our Q4 realized oil price, excluding hedges, declined to $70.80 per barrel this quarter, down nearly $24 per barrel from Q3 as oil prices trended down throughout Q4.

Including hedges, our net realized oil price was down only $4.25 per barrel from Q3. Our NYMEX differential improved slightly from Q3 to approximately $2.25 below NYMEX during Q4.

Oil differentials for our Gulf Coast tertiary production, which primarily receive LLS pricing, averaged approximately $1.50 per barrel above NYMEX, down $0.85 per barrel from Q3. In the Rocky Mountain region, our Cedar Creek Anticline oil differential improved by over $2.60 per barrel, selling at around $9 per barrel below NYMEX in Q4.

We currently expect our overall oil differential to average between $2 and $4 per barrel below NYMEX in the first quarter of 2015. Moving on to our hedge positions.

For 2015, we have roughly 75% of our estimated oil volumes hedged, with an average downside price of approximately $85 per barrel on a NYMEX-equivalent basis, which assumes LLS prices are about $3 above NYMEX. Roughly half of our contracts are three-way collars or enhanced swaps, which also have a sold put at around $65, thus capping the benefit that we can receive under those contracts at approximately $25.

We have not added any new hedges since the third quarter of 2014. Full details of our hedged positions are shown in the investor presentation that's available on our website.

On the expense side, LOE per BOE came in better than we expected at $23 per BOE and $22.64 per BOE if we exclude the roughly $3 million in incremental Delhi remediation costs in Q4. On a sequential quarter basis and excluding nonrecurring items, this is approximately $0.50 lower than LOE per BOE in Q3 due primarily to lower CO2 costs, which fluctuate with the price of oil.

This was our lowest LOE per BOE in over a year and we believe we could see further improvements in our LOE if oil prices remain low. During Q4, we also received an enhanced oil recovery project tax exemption for our Oyster Bayou field which resulted in approximately $7 million cumulative reduction in severance taxes during Q4 and will result in lower severance payments going forward.

G&A expense was roughly $35 million in Q4, $5 million lower than Q3 and better than our guidance due, in part, to lower bonus accruals in Q4. For the fourth quarter, $4 million of G&A was related to stock-based compensation.

For the first quarter of 2015, we expect G&A expense to be between $40 million and $45 million, with approximately $7 million to $10 million of this amount being stock-based compensation. Just a reminder that our G&A is generally higher in the first quarter of each year due to incremental payroll taxes and other burdens associated with divesting of long-term incentives during the first quarter.

For the full year 2015, we expect that our G&A will remain relatively consistent or be down slightly from 2014 levels. As Phil mentioned, we are aggressively working on our cost structure, and we believe we can find additional efficiencies.

Our depreciation, depletion and amortization expense increased about $11 million from Q3 to approximately $22.80 per BOE. This increase was primarily due to the increase in capital costs and future development costs in our reserve report.

We had roughly $13 million in asset impairments in Q4. However, we did not have a full cost ceiling write-down at year end.

We believe that if prices remain low, we could have a full cost ceiling write-down in the first or second quarter of 2015. Also because the ceiling test utilizes the first day of the month average price for the last 12 months, the prices used may continue to trend down over the course of the year.

We could also have an impairment of our goodwill at some point, depending on oil price movements and changes in our enterprise value. Interest expense, net of amounts capitalized, was down about $2 million from Q3 due, in part, to capitalized interest being about $1 million higher in Q3 or about $7 million this quarter.

We currently expect that our capitalized interest will be slightly lower in 2015, averaging about $3 million to $5 million per quarter. Our effective income tax rate for Q4 was slightly below our estimated statutory rate of 38%.

In December of 2014, the government extended certain bonus depreciation deductions which allowed us to recognize current income tax benefit of approximately $43 million for tax losses that we plan to carry back to prior periods. For 2015, we anticipate our effective tax rate will be between 38% and 39%, with the current tax representing around 5% or less of total taxes.

Moving on to our capital structure. Total long-term debt at December 31 was approximately $3.5 billion, which was down about $24 million from Q3.

We had $395 million drawn on our bank credit facility at December 31, down $15 million from Q3. In December of 2014, we refinanced our bank credit facility, which extended the maturity of our facility from 2016 out to 2019.

We've set the initial borrowing base at $3 billion but left the bank's commitment amount unchanged at $1.6 billion, leaving significant cushion between the borrowing base and what we have asked the banks to commit to. In addition, we were able to reduce the interest margin on our borrowings by roughly 25 basis points.

Our next scheduled borrowing base redetermination will be around May 1, utilizing price decks as set by the banks. Unless price decks change significantly from current decks, we would expect to still have significant cushion between our borrowing base and the bank's commitment level.

Based on our current -- based on current future oil prices, we would not expect to have an issue with our bank covenants in 2015. However, once we get into 2016, we are significantly less hedged so we could have issues with our debt-to-EBITDA covenant of 4.25x if oil prices remain at depressed levels.

As such, we anticipate working with our bank group in the near term to restructure our covenant to accommodate a potentially lower oil price environment. Based on our current future prices and assumptions for cash flows, capital expenditures and dividends for 2015, we anticipate ending the year with bank debt of between $200 million and $300 million.

And now I'll turn it over to Brad for an update on reserves and our innovation and improvement teams.

Thank you, Mark. Denbury's total preserved -- total estimated proved oil and gas reserves at December 31, 2014, were 438 million barrels of oil equivalent.

Most of this is liquids, 83%; and 77% are in proved developed category. Denbury's CO2 tertiary operations account for 49% of these proved reserves.

The 438 million barrels equivalent is a net reduction during 2014 of 30 million barrels. This is primarily due to the 27 million barrels that was actually produced in 2014.

Other minor revisions and additions accounted for a small amount of 3% net reduction. Denbury's proved reserves normally go up in larger steps when the new CO2 floods are started and our response to CO2 is demonstrated as per SEC rules.

As planned, in 2014, we didn't start any new floods. Although additional phases of existing CO2 floods were implemented, including proved undeveloped reserves into proved developed reserves, lowering our PUD percentage from 38% of the total reserves at December 31, 2013, to only 23% this year end.

An example of this is implementing the last phase of Tinsley, which allowed us to reach new record production in that field. Denbury has a number of new CO2 floods that are planned in future years, including Webster, Conroe and a number of the fields in the Cedar Creek Anticline.

We are working, particularly on these fields with our innovation and improvement teams to enhance -- further enhance the profitability of these fields. The estimated discounted net present value of Denbury's proved reserves at December 31, 2014, before projected income taxes and using a 10% per annum discount rate, was $8.7 billion.

This compares to $10.6 billion at December 31, 2013. Of course, the main reason for this reduction was the lower oil prices and oil differentials.

This accounted for $1.4 billion of the reduction or 74%. As per SEC rules, the estimated proved reserves and PV-10 Values were computed using the first day of the month, 12-month average prices.

Compared to the year end 2013, the 2014 average NYMEX oil prices were lower by a little less than $2 a barrel and the 2014 oil price differentials decreased by approximately $6.50 per barrel. The 2014 average Henry Hub natural gas prices were up by $0.63 per MMBtu compared to 2013.

The majority of the remaining PV-10 Value reduction was the result of our lower capital spending plans for 2015. This resulted in the deferral of certain projects to future years, which had a lower present value.

I think that the exciting part of my message is that Denbury is taking the opportunity during this period of reduced capital expenditures to invest our manpower in a program of initiatives to improve its operational efficiency and the profitability of Denbury's existing assets and future projects. We're using innovation and improvement teams consisting of about 8 experts and people from the teams to take a deep dive into each of the fields or our process in over a course of a few weeks.

And during this time, they will generate ideas for improving value. The plan is to complete innovation and improvement team reviews on every field and on several key processes by middle of 2015.

Denbury is on schedule with this program of initiatives. 9 reviews have been completed and we have identified several promising opportunities.

More specifically, we have completed 7 reviews of fields. These fields account for 38% of our proved reserves.

These teams have identified several opportunities for increasing CO2 flood recovery efficiency, for reducing CO2 purchase requirements, for developing additional areas and horizons, for optimizing field development plans and reducing operating cost. We have already begun to implement the highest value opportunities.

Some of these will contribute to proved -- improved business performance during 2015 while others will improve the profitability of future projects for years to come. One example is the Hastings CO2 flood.

This was done in the fourth quarter of last year, 2013. We are implementing the CO2 floods in Fault Block B and C, and converting this into a more efficient development concept that we call the series flood.

Injection began in January 2015 and production is expected to begin in Quarter 2 2015. Denbury has also completed reviews of 2 key processes; one is production forecasting and the other is reservoir management.

What I mean by reservoir management is this is how we monitor the CO2 flood in the reservoir and make adjustments to optimize recovery during the CO2 flood process. These teams identified several improvement opportunities which are now being implemented, with completions planned by Quarter 2 2015.

These improvements will increase the productivity of our staff, improve forecasting accuracy and give Denbury competitive advantage in managing CO2 floods. 4 additional processes are being reviewed by innovation and improvement teams, including one on facility modernization that is aimed at reducing facility development costs.

So with that, I'll now turn it back to Ross.

Thank you, Brad. That concludes the management's prepared remarks.

Lori, can you please open up the call for questions?

Phil, I wanted to talk to you about the strategy movement going forward. Obviously, you were -- you adopted kind of a growth in income strategy and we've had a sharp pullback in oil prices, but let's just say that commodity prices were to normalize in the mid- to low-70s, what kind of strategy would you see Denbury adopting under that kind of price outlook?

Well, we obviously need to adjust to that environment. We're focused on reducing cost and improving efficiencies.

It's hard to know exactly where that will come out. But we think we're going to definitely improve those metrics.

And so if prices were normalized in the 70s, which I guess is probably where most of Wall Street's consensus is, I think we can resume our growth in income strategy. The pace at which we grow and the pace at which we grow dividends, of course, will depend somewhat on -- well, not somewhat, but quite a bit on the oil price environment.

But we're also working on the cost side. I think we'll see significant improvements there.

Okay. And just to follow up, you guys have always managed the business pretty conservatively.

You talked a little bit about the covenant potential next year. I'm just wondering about ways that you can proactively manage the balance sheet to improve some of your liquidity and debt metrics going forward.

Yes. I mean, I think we -- obviously, what we've done is try to manage our bank debt at a pretty conservative level, and we've turned out a good chunk of our overall debt to a sub debt that does -- its maturity is out past 2020.

So at, we think, pretty attractive rates. So we had just under $400 million drawn on our bank line year-end.

We see that going down between $200 million to $300 million -- to between $200 million to $300 million by the end of next year. And so that doesn't leave a whole lot of flexibility in terms of how much more you can reduce your debt levels.

So obviously, we've seen other people do some transactions, but a big chunk of our debt is sub debt. So we'll work with the banks, I mean, I think we're in relatively good shape relative to some people.

We still have hedges going out into 2016, but at a much lesser degree. And we're just looking and looking forward to different possibilities and different oil price scenarios, and we want to make sure that our debt position with the banks, which is a primary source of our liquidity, is not jeopardized.

And we continue to stay as -- in compliant with our bank agreements. So I think from where we sit, we feel good about where we are, and I think we'll continue to work with our bank group and manage that going forward just fine.

I'm sorry if I missed this, Mark. What was the actual CO2 cost per barrel in the fourth quarter?

Keep looking.

See if I can...

And while you're looking, I could continue on if you like.

Sure. Go on to the next question, go ahead.

Yes. And so CO2, directly correlated with oil.

What's the potential on some of the other costs that you incur at the OpEx level, such as fuel and chemicals that, I guess, are partially correlated with oil. They've been running maybe in the $8 per barrel range combined the past several quarters.

Are you seeing declines there? Or do you anticipate those declining?

Well, we have -- one, we're going back to virtually every vendor that we have and looking for cost reductions. We're starting to see some of that.

The supply group is actively pushing our suppliers to help us in this downturn. So I think you'll see -- generally, you'll see cost savings in almost every category.

It may vary a bit depending on who the vendor is and what it is. Secondly, as Brad mentioned, we see ways to improve the efficiency of the CO2 and use less CO2, improve -- there's cost saving ideas on the plants, and so forth.

So I think those will also add to the savings. So I think we're optimistic we can drive LOE down a little bit more.

Of course, it helps that the CO2 cost comes down with the price of oil, and that's been probably the biggest immediate change. Mark, do you have that CO2 number [ph]...

Yes. So for the fourth quarter, just for -- across our tertiary properties, it was $6.18 versus $6.55 in Q3.

And if you extrapolate it across the whole company's production, it's $3.43 for the quarter versus $3.72 last quarter.

Okay. That's very helpful.

Continuing with some of the OpEx components. So workover cost per barrel are down pretty significantly the last several quarters.

Do you see a situation where that has to tick back up sometime in the next year so to fully maximize field production?

Well, 2 things -- or 1 thing in particular has happened there. We're trying to do root cause analysis and really look at trends and so forth.

And I know at CCA and several other fields, they worked very hard to avoid the repeat failures and try new things, monitor that. And I think that's part of the reason you've seen workover costs come down.

There will always be some level of workover costs, it's never going to go completely away. So I don't know, probably to get it down much lower, we need a little help from the vendors, which we may get some help on that side, too.

But you are correct, there will be some base level of -- it's basically maintenance to keep the fields producing.

Okay. And then just lastly, so you provided the PV-10 at year-end '14 based on, I guess, around $92 oil at the field level.

Did you happen to have a PV-10 estimate based on current oil futures at that time as well as costs at that time?

No, we don't. I mean, we have some -- we don't -- we've got it, I just don't want to disclose it.

The hard part of that is, of course, adjusting the costs side to the current environment. I mean, of course, the SEC price deck is at $90-plus and uses costs based on historic cost levels.

So I don't think we're far enough along yet to see what a real number would be in this price environment.

You guys historically have done a great job on hedging. And I was curious how you're approaching that now.

I know you've got some good hedges in place for '16, but you do like to hedge on a rolling basis. So how are you approaching that now?

Well, Pearce, can you tell me what oil is going to do and then you could help me with that decision? I mean, the problem is, as you know, oil price is probably, what, low $60s or $60-there-ish in 2016, and we've just been hesitant to lock that in.

So I guess we're kind of taking a little bit of approach and kind of wait and see. But it gets to be a little bit of a judgment call.

Are prices going to be better or worse than that or do we expect them to -- and so should we lock that in? We've just been hesitant; to be straight with you, we've just been hesitant to lock in $60.

Understand. And then, my follow-up.

At the Analyst Day back in November, you had mentioned that you might need to increase CapEx in 2016 to keep production flat. I think I've got that right.

And so is that still true? And if so, by what magnitude would you need to do that to kind of keep production flat '16 versus '15?

Well, yes. Based on our historical costs and so forth, we -- to hold production flat, did need just a little bit more.

It wasn't significant. We're hoping we can get enough efficiencies and so forth that we could keep it flat or close to flat with current spending levels.

So that's what we're shooting for.

I wanted to follow up on the same hedging strategy. If you could share a little more on your decision framework for -- or when, how much to hedge.

So I understand your answer to the last caller, hesitant to lock $60, but how do you think about it as, hopefully, costs are coming down and there might be an opportunity to hedge at higher levels, call it, $65 or $70?

Well, obviously, the higher numbers are more attractive. I mean, if you look at -- if you back up and look at our historic hedging philosophy, we've always kind of hedged from like 12 to 24 months out.

So actually, we're still within those guidelines. We do have hedges going out into the first part of '16.

it's not quite as high a percent in the first quarter and even less in the second, but we actually do have hedges through June 30. So we feel like we're still within our kind of current band of -- or our current operating philosophy.

It's a, I think, an item that we discuss with the board at every meeting, and so the hard part has been kind of figuring out where the low is and where prices are going. Is it going to stabilize?

So I think we'll have ongoing discussions about when and what to hedge. We just haven't done anything in the last few months and are waiting for things to stabilize.

Obviously, if prices get a little higher, I think that would be much more interesting.

I guess what I'm trying to get at is do you have a current decision framework so that if those price hedging opportunities came available, you would take them? Or are you saying, "We're still waiting.

We take it to the board and think about it?"

I don't know that we have a specific number. And so I don't know the that I can answer that with that much specificity.

Because obviously, here in the first half of '15, you'll be rolling over that 12-month outlook or framework. And as you said, the hedge book in the first half of '16 isn't at that 75% level.

So is there a percent of '16 that you'd expect to have hedged as we exit the first quarter here of '15?

I don't think I'd expect to at the end of the first quarter of '15. Again, I think it's just -- I can't give you specifics because I don't know for sure what our threshold is and that is also, as I said, a board discussion.

So we will look at it, and we have hedged at various levels, sometimes, as high as 75%, which is where we are in the next 3 quarters. But other times, we don't go quite that high.

So it's just something we'll have -- we're going to look at. I don't -- I really don't know for sure and can't share a specific number.

And then another line of decision framework. What would cause you to further reduce CapEx here in '15?

And if so, how much do you think you would or could reduce it by?

Well, we don't anticipate -- I guess the answer -- short answer is, if oil prices were to drop significantly, then, we'd re-look at that. We actually have probably a little bit of a cushion right at this moment and think that based on current strip prices, we'll generate maybe a little bit of free cash flow.

Mark, as you noted, had bank [ph]] actually going down just a little bit. So we have a little room.

If prices drop precipitously, then I think we'll look at CapEx and we'll make that decision when we get there. We are continually monitoring our projects.

We generally, at this point, are still staying with the $550 million budget, but we are moving things around, depending on which things are more economic. And we're trying to high-grade and, for instance, we're probably not going to drill the wells at Hartzog but we may shift that drilling to CCA, where it's more economic, et cetera.

So we are continually doing that. I don't think there are major shifts in the capital budget, but we're continuing to monitor what's economic at today's price and we'll keep doing that.

And is there a way you could separate that $550 million into maintenance CapEx versus growth CapEx?

Well, I guess it depends on how you define that question. Most people would define -- or a lot of people, anyway, define maintenance CapEx as what it takes to keep production flat.

So I guess in that sense, we need to spend most of that to keep production flat. Part of the only exception that's in there is there is some spending for Webster in the budget, that really doesn't do anything for 2015; and there's a little bit of spending also at Delhi for a future NGL plant, which also doesn't do anything really for 2015.

They both would benefit future periods. So in theory, you could take those 2 off, I guess, and still stay -- and get down your spending level that keeps production flat in '15.

It just -- it will cost you later on.

Phil, a question on reserves. Will the capital program in 2015 result in any new reserve bookings?

And how does that factor into your thinking about where the borrowing base could be headed if commodity prices don't change dramatically in 2014 and '15 -- I'm sorry, '15 and '16?

I think it's probably doubtful at this point that we have meaningful reserve adds [ph] in '15. The one possible exception I guess would be Webster, depending on what we do there.

But it's probably at least questionable at this point. Probably, it could be a '16 event instead of '15.

As to the borrowing base, as Mark indicated, we have a $3 billion borrowing base and just a few hundred million drawn, and a $1.6 billion commitment. So we have a lot of flexibility there.

We do believe that the borrowing base may come down a little bit with price adjustments, but actually for the banks, as Brad mentioned, they focus heavily on PDP. And actually, our PDP percentage improved significantly in '14, and the PUD percentage went down.

So as far as banks are concerned, I think other than the price effect, I think they're quite happy with it.

Will PDPs in '15 go up from conversion of PUDs as you all get more experienced with some of these floods?

Yes, you should have a little bit more conversion. I mean, we're basically -- the money we're spending for the most part is continued development of existing floods.

So you may have a little bit more of an adjustment in '15.

And then lastly, Phil, is there anything significant or I guess markedly that, as you've done some of these field level evaluations, that you would either have done differently on the fields where you've put floods in or at least will, as you look at implementing new floods in the future, that will cause you all to do anything dramatically different operationally than what you've done in the past on these assets?

Yes. Let me take that.

It is -- we have the advantage of -- we've done several floods in the past and every field is a little bit different. And so when you have a look at the performance, you do learn.

You learn more about the geology, you learn more about the compressor performances, you learn several things. And so we see opportunities for improving our existing fields and ways we'll do things differently in our future fields.

The series floods is one example. We looked at the performance of using some other development techniques and when we look at the series flood, we see those being superior.

One in particular that we're excited about is the NGL plants, actually. We talked about reducing power cost.

Let me just tell you this example of one, where the NGL plant isn't just benefiting us from additional NGL revenue. When you take out the NGLs and methane from the CO2 that you're reinjecting, you actually increase its density, and that makes it easier to inject, requiring less power in your compressors to inject it.

You also lower the minimum miscibility pressure so you can operate the floods at a lower pressure. And then you get additional benefit as well of you take that methane and we can use that to generate our own power at much less cost than we're getting from the external supplies.

And so we're looking at a lot of opportunities for these NGL plants, not just at Delhi but also other fields as a way to be reducing our cost of development on several fronts.

So that'll give you a purer stream of CO2 as you recycle it into the field?

That's right, because we're currently getting about 10% methane in there and that 10% actually has a pretty large impact on your density and on your minimum miscibility pressure. And so in the future floods, I can see we actually should be putting these NGL plants in upfront and earlier because it just makes business sense to do it.

I was just -- briefly, I wanted to just-- as I look at the tertiary OpEx and nontertiary OpEx, and the different category of those areas, how would you characterize that kind of going through 2015? And can that come down if you're focused more on maintenance capital?

Or is it -- is that -- a lot of the maintenance capital work would be CapEx versus OpEx?

Well, I mean, we've got -- actually, tertiary in total was not too dissimilar at this point. Our total LOE is a little bit lower than our tertiary, but it's only a couple of dollars -- it's less than a couple of dollars a barrel difference.

But they kind of interchange and one helps the other. I mean, I think we're focused on every line item.

CO2 will come down a little bit more if prices stay low further, I think we'll optimize it. Power and fuel were, as Brad said, we're looking at ways to reduce power costs.

The NGL plants, other ways to maybe make our own power from natural gas or whatever or ways to potentially help that. Labor, we're trying to manage that.

Repairs and maintenance, that probably will be largely what can we get out of the vendors. Chemicals, we're working on the vendors.

Also, some of the IITs have shown ways of maybe we can do a little bit more predictive use of the chemicals and, therefore, use a little bit less in addition to lowering the cost per unit. So we're focused on all of those.

I think LOE has continued to trend down over the last year and I think we have some more room to get that a little bit lower. But capital, we -- it's just -- we had to focus on capital too much, it's a little harder nature [ph], but we did come in under budget in 2014, and that was part of the reason we generated free cash flow.

And so we're continuing to monitor capital very closely and look for ways to improve that. For instance, at CCA, we're changing the well design a bit and we're going to drill a vertical well with 2 horizontal legs.

We get a little bit more bang for the buck, and it's still very economic at these prices. So continually, we're working for ways to improve our efficiencies.

Okay, all right. And then, did you say -- I heard part of the initial comments, I had to jump off for a minute, but did you guys give a comment in terms of how many conversions -- how many producers to injectors or new injectors will be drilled in 2015 to expand the patterns and keep moving the PDPs along?

No, we didn't. I don't know that I know that number, either.

We are expanding patterns at Bell Creek. Well, all of the fields that are growing generally are having expanding, but Hastings, Bell Creek are the 2 biggest.

Delhi, potentially, is pretty much fully developed. And Oyster Bayou is pretty much fully developed.

Thank you, Lori. Before you go, let me cover a few housekeeping items.

On the conference front, Mark Allen will be giving a presentation at the JPMorgan Global High Yield & Leveraged Finance Conference in Miami, and Phil will be presenting at the Crédit Suisse 20th Annual Energy Summit, both of which will occur on February 24. The webcast for Phil's presentation will be accessible through the Investor Relations website.

Lastly, for your calendars, we plan to report first quarter 2015 results on Wednesday, May 6, 2015, and hold our conference call that day at our usual time of 10:00 a.m. Central.

Thank you again for joining us on today's call, and we look forward to keeping you updated as our progress continues.