Denbury Inc.

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

Presenting on today's call from Denbury will be 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 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 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-Q and today's news release, all of which are available to you on our website at denbury.com.

Also, during 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 and on our website.

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

Thanks, Jack. I'm happy to report that our financial and operational results are off to a positive start in 2014.

We had a 3% organic increase in production on a sequential quarter basis, with gains both in tertiary and non-tertiary production. Tertiary reached a new record quarterly high in nearly 40,000 barrels a day on continued response through our expansion of the Gulf Coast and Rocky Mountain CO2 floods.

Non-tertiary also increased as we had fewer weather-related interruptions, and benefited from some of the development work I do on those properties. As we discussed on the last quarter call, we have placed a high emphasis this year on reducing costs throughout the organization.

We have a number of internal initiatives underway focused on this objective. Although we're just getting started and have much more to do, I'm pleased to report that, in general, our overall operating results improved slightly on a sequential quarter basis, at least in part, due to this initiative.

For example, lease operating expenses were down a few percentage points on a per barrel BOE basis, which coupled with a 3% increase in production and increase in our cash flow from operations. However, you may notice that at first glance, our cash flow from operations decreased slightly sequentially, as the reduction in operating costs and higher production were offset primarily by higher G&A interest expense and cash taxes.

If we take a closer look, the increase in G&A was primarily a seasonal increase, as the first quarter is almost always the highest quarter of the year. The apparent increase in interest expense is not an increase in out-of-pocket interest cost at all, as they were essentially flat sequentially, but rather a lower capitalized interest amount due to the completion of projects in 2013.

Or said another way, we simply categorized more of our interest cost as capital this quarter and -- I mean, less, I'm sorry. Less as capital and more was expense.

Lastly, our current tax provision went back to a more normal level in Q1 after the current tax benefit we recorded in Q4, associated with the startup of our Riley Ridge gas processing facility. If you recall, in Q4, we had a negative current tax provision, which kind of distorts the sequential quarterly comparisons.

So if you sort through the numbers, our overall operational results are improving, oil prices have remained strong, and I'm also pleased to announce we were able to improve our cash flow by refinancing $1 billion of sub-debt in April at a 33% lower interest rate. All this means is that we remain on track this year to cover our capital expenditures and dividends with cash flow from operations.

As you know, we officially became an income stock with the payment of our first quarterly dividend in March. And last week, we announced our second quarterly dividend, both of these at an annualized rate at $0.25 per share.

Based on our current outlook, we still expect to grow our dividend to an annualized rate of $0.50 to $0.60 per share in 2015. On the share buyback, we have been active early in the year, but have not purchased much since our last call in February.

We've acquired a total of about 15% of our common shares since we initiated the program in 2011 at an average price of $15.68, and these purchases have significantly improved our per share metrics. I'm not sure the market's totally taking these repurchases into account when they value Denbury.

As an example, on an average diluted per share basis, our quarterly average production actually increased 7% sequentially in Q1, more than double the 3% growth in our absolute average daily production volumes, as a result of these share repurchases early in the year. We believe our stock remains a highly attractive investment and we will continue to use our discretion to purchase stock from time to time, depending on stock price, oil price, free cash flow leverage and other funding sources.

But with that introduction, I'll now turn it over to Mark and Craig to give you more details on the quarter and our current outlook. Mark?

Thanks, Phil. My comments will summarize some of the notable financial items in our release, primarily focusing on the sequential changes from the fourth quarter.

I have also provided some forward-looking estimates to help you in updating your financial models to reflect our current outlook for the second quarter and the remainder of 2014. Our non-GAAP adjusted net income for the first quarter was $89 million, down $11 million from the fourth quarter.

Although oil prices improved from Q4 to Q1, the payments on our hedges offset most of that improvement, and the benefit of higher production and lower lease operating expense this quarter was more than offset by higher seasonal G&A expense, a reduction in capitalized interest, meaning higher interest expense, and a higher tax rate compared to the abnormally low rate in Q4. Our non-GAAP adjusted cash flow from operations, which excludes working capital changes, was $289 million for Q1, also down slightly from the prior quarter for the same reasons.

Our average realized oil price, excluding derivative settlements, was slightly less than $98 per barrel for the quarter, up from $93 per barrel in the fourth quarter. However, including derivative settlements, our realized oil prices are only up about $0.50 per barrel from the fourth quarter.

Average NYMEX oil prices in Q1 improved by about $1 per barrel from the prior quarter. So you can see that the majority of the increase in our realized oil price was the result of improvements in our oil differentials or the price we receive relative to NYMEX prices.

Last quarter, our NYMEX differential averaged over $4.50 negative to NYMEX, as compared to $1 less than NYMEX, this quarter. Our oil differentials improved across-the-board.

And our Gulf Coast tertiary production, which primarily receives LLS pricing, averaged over $3.50 per barrel above NYMEX, up over $3.25 per barrel from Q4. In the Rocky Mountain region, our Cedar Creek Anticline oil differential improved over $4.50 per barrel, selling at just under $9 per barrel relative to NYMEX this quarter.

We have recently seen both LLS and Rockies differentials weaken somewhat relative to Q1 levels. And therefore, we currently expect that our differentials may remain negative to NYMEX prices by $3 to $4 per barrel in the second quarter.

Moving on to our hedging activity. In an effort to provide more certainty around future cash flows in order to execute our long-term business model, we have converted about 40% of our 2015 collars to fixed-price swaps at a weighted average price of about $92.70.

We have oil hedges in place for a significant portion of our forecasted proven oil production to the third quarter of 2015, including fixed price NYMEX-based swaps for 2014 and a combination of NYMEX and LLS-based swaps and collars for 2015. Full details of our hedging positions are shown on the updated investor presentation that was posted to our website this morning.

On the expense side, our lease operating cost improved from the prior quarter, and excluding the Delhi remediation expense recognized during Q4, our overall lease operating expense per BOE decreased by about 2% sequentially to $25.68 per BOE in Q1. On an absolute dollar basis, our LOE was down slightly due to a decrease in work-over costs, partly offset by higher power costs, due in part to higher natural gas prices.

Q1 LOE per BOE came in essentially where we guided to on last quarter's conference call. For the full year 2014, we continue to expect overall LOE per BOE to be in the mid-20s range, excluding any potential additional Delhi-related remediation expense or insurance reimbursements.

We do not have any incremental charge for Delhi Field remediation costs this quarter. And although our remediation efforts are complete, it is possible we could still have some incremental costs for unknown items.

Also note that the operating cost of our Riley Ridge gas processing plant was primarily recorded in the marketing and plant operating expense line of our income statement, and we expect that expense line to remain relatively consistent going forward. G&A expense was roughly $44 million in Q1, up from about $34 million in the fourth quarter and about $2 million higher than the year ago period.

As mentioned on last quarter's call, we typically see an increase in G&A expense in Q1, primarily due to taxes and other employee costs associated with divesting long-term incentives and bonus payouts in the first quarter. For the first quarter, $7.5 million of G&A was stock-based compensation.

For the remainder of 2014, we expect G&A expense to run in the upper $30 million to mid-$40 million range each quarter, with approximately $7 million to $10 million of this amount being stock-based compensation. Our depletion, depreciation and amortization rate decreased somewhat to about $21.30 per BOE in the first quarter, from just under $22 per BOE in the fourth quarter.

This decrease was due primarily to higher production and decreases in CO2 property and other fixed asset depreciation. Also, we did not have any significant proved reserves changes in the first quarter.

Looking at 2014. We expect our DD&A rate to average between $21 and $22 per BOE, most likely increasing each quarter throughout the year.

Our effective income tax rate for Q1 was slightly below our estimated statutory rate of 38%, and about 13% of our taxes were reported as current this quarter. And that's less than the 20% to 30% in our current taxes that we guided to previously.

That decrease was primarily due to the benefit that we derived from the expensing or refinancing our sub-debt here in the second quarter. For the rest of 2014, we anticipate our effective tax rate will be between 37% and 38%, with current taxes representing between 15% and 20% of total taxes.

Moving to our capital structure. Total debt at March 31 was approximately $3.5 billion, which was up about $250 million from December 31.

We had $600 million drawn on our $1.6 billion bank credit facility at March 31, up from $340 million at the end of Q4. The increase on borrowings in the quarter was largely related to our share repurchases, and the remainder was to fund additional working capital needs that we had in the first quarter.

Just a few weeks ago, we refinanced our roughly $1 billion of 8 1/4% senior subordinated notes, with $1.25 billion or 5.5% senior subordinated notes. It costs us roughly $100 million to cover the early redemption of the notes, and the remaining excess funds went to reduce our bank debt.

Phil mentioned the savings that this provides us, but it also better aligns our capital structure, with our $2.85 billion of senior sub-notes now at a weighted average interest rate of about 5.25%, and our first significant maturity not until 2021. Based on our current assumptions for cash flows and capital expenditures for 2014 and the dividend payments, we anticipate ending the year with bank debt of between $400 million and $500 million, excluding the impact of any remaining incremental share repurchases in 2014.

Interest expense, net of capitalized interest, is $49 million in Q1, an increase from $40 million in Q4. That increase is almost entirely due to a $9 million reduction in capitalized interest, but a small portion due to the increase in borrowings under our credit facility.

The decrease in capitalized interest was primarily the result of placing Riley Ridge into service near the end of Q4. And going forward, we expect our capitalized interest to range between $5 million and $7 million per quarter, with that amount being at the lower end earlier in the year, and increasing slightly as we go throughout the year.

Our capitalization metrics remain solid. Our debt-to-capital was up slightly this quarter to 41%, primarily due to the impact of the share repurchases.

And our debt to trailing month EBITDA was right around 2.5x, and probably around 2.3x if you exclude the Delhi incident. Our 2014 capital budget remains at $1 billion, plus an estimated $125 million for other items, including capitalized acquisition, exploration and development costs, capitalized interest and pre-production EOR startup costs.

We actively purchased our common stock, as Phil mentioned, during the first quarter, repurchasing about $200 million. With these purchases, we have now spent about $940 million since October 2011 when we started the program, and we have about $220 million remaining authorized under this program.

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

Okay. Thank you, Mark.

Total company production for the quarter was slightly below 74,000 barrels of oil equivalent per day. Our tertiary operations performed in line with our estimates in the first quarter, while production averaging just below 40,000 barrels per day.

Our tertiary oil production increased on a sequential quarterly basis, as continued growth at Hastings, Heidelberg, Oyster Bayou and Tinsley Field in the Gulf Coast region, and Bell Creek Field and the Rocky Mountain region, combined, with relatively flat production at a mature tertiary properties in Delhi. At Hastings Field, sequential production increased by about 350 barrels per day as the newest patterns of the flood responded well to CO2 injections.

We expect to see continued growth at this field throughout the remainder of 2014, as additional patterns continue to respond to CO2 injection. Oyster Bayou continues to show steady growth, increasing by about 190,000 barrels per day sequentially in the first quarter.

We are currently developing the A-2 Zone and optimizing the existing A-1 Zone in Oyster Bayou. As a result, we expect additional production growth in the second half of 2014.

Heidelberg Field's tertiary production increased about 120 barrels per day from Q4 levels. We expect continued production of growth at Heidelberg for the remainder of 2014, as the Christmas zone in West Heidelberg and the Utah Zone in East Heidelberg respond to CO2 injection.

At Tinsley Field, sequential production increased by 620 barrels per day, primarily due to increased CO2 injection rates. For mature area tertiary properties, production declined by 2.4% sequentially, which was about in line with our expected decline of approximately 10% per year.

We have various capital projects underway in several of our mature properties that we anticipate will reduce this decline rate even further. Moving now to Rocky Mountain region.

Bell Creek's tertiary production increased during the first quarter, as they still -- is responding well to the increase in CO2 injections since the completion of the Greencore Pipeline interconnect in late January. Bell Creek's net tertiary production recently exceeded 900 barrels per day, and we expect this yield to be a key driver of our anticipated 2014 tertiary production growth.

Our drilling program at Hartzog Draw continues. We have 3 wells producing, having just finished completing the third well.

Overall, results are in line with our plan. Production from our non-tertiary assets increased to just under 34,000 barrels of oil equivalent per day during the first quarter from just under 33,000 in the fourth quarter.

That's primarily due to production increases at Conroe Field in Texas and Cedar Creek Anticline, Hartzog Draw and Riley Ridge and the Rockies. Production at Conroe Field has increased by over 450 barrels of oil equivalent per day on a sequential quarter basis.

This is a result of successful recompletion and improved run times at the third-party gas plants, which processes the fields methane and NGLs. Our Cedar Creek Anticline production was just above 19,000 barrels of oil per day in the first quarter, and that's compared to about 18,600 in the fourth quarter of last year as we experienced less downtime, implemented efforts to improve water handling and completed several new wells.

Our team continues to look for opportunities to enhance production on our non-tertiary assets in advance of the planned CO2 floods. Natural gas production from our Riley Ridge natural gas processing facility, which we placed in service in late December 2013, averaged approximately 1.6 million net cubic feet per day during the first quarter.

We are still in the startup phase of this first-of-its-kind plant, and thus far, Riley Ridge's run time has been lower than expected. Our team is working to improve both planned uptime and inlet volumes feeding the plant.

Also note that Riley Ridge was shut in starting late last month due to an outage at Williams gas plant in Opal, Wyoming. We are just now starting our Riley Ridge plant back up, and expect to start selling gas later this week.

While still too early to predict, the lower Riley Ridge natural gas production and Williams related downtime could negatively impact our annual corporate non-tertiary production estimates. Although because it is natural gas, this likely would not have a significant impact on our cash flow.

So overall, looking at our company-wide production, we continue to expect both tertiary and total production to be in the lower half of the estimated production ranges we provided back in November. Let's move now to lease operating expenses.

Our lease operating expense per barrel of equivalent production decreased by 2% from the fourth quarter level, when excluding Delhi remediation expenses. Operating costs for our tertiary properties averaged $27.21 per barrel in the first quarter, and that's a decrease of over $1.50 per barrel from the prior quarter level, when we exclude Delhi remediation expenses.

The sequential decrease in quarterly LOE per BOE primarily reflects increased production and the reduction in well work-over activity in both of our operating regions, partially offset by higher power cost. While down sequentially, our work-over expenses did remain elevated in the first quarter, due to a continued emphasis on well integrity and performance work, and a relatively high number of well repairs.

We expect some of these work to be non-recurring and anticipate our overall 2014 per BOE operating cost to be in the mid-20s. As Phil mentioned, we do have various initiatives underway across the company to reduce both our operating cost and the cost of our capital projects.

We expect these initiatives to mitigate the escalation in our operating and capital cost that we have experienced over the past 2 years. Let me give you some color at some of these initiatives.

We have a team looking at different designs of our future CO2 facilities to reduce the cost to build and install them. This includes moving to modular construction and standardizing our facility design.

We're spending more time evaluating multiple scenarios to find the optimum development plan before we commence construction. We're placing more emphasis on improving the run times of our compression through improved maintenance and reliability.

We're also focused on optimizing our large electricity usage. We employ the use of root cause failure analysis to understand each equipment or well failure, and why it occurs so that we can fix the root cause, which should prevent this failure from being repeated.

Our objective overall is to continue Denbury's tradition of moving quickly, while also challenging ourselves to optimize each component of our business and look for new ideas. Let's move now to our CO2 supply and transportation operations which, in general, are performing well and fulfilling our growing demand.

In the Gulf Coast region, we produced slightly under 970 million cubic feet per day of CO2 from Jackson Dome during the quarter. In the Rocky Mountain region, we received roughly 90 million cubic feet per day of CO2 from our combined sources at LaBarge and Lost Cabin for our EOR operations.

We purchased an average of approximately 60 million cubic feet per day of CO2 that was captured from industrial sources in the Gulf Coast region for use in our operators fields during the quarter. Our man-made CO2 supply is expected to get a boost from Mississippi power plant, if complete.

And our combination of natural and man-made CO2 sources gives us the ability to manage our CO2 supply to help ensure our plants receive the needed supply. And with that, I'll turn the call back to Jack.

Okay. Thank you, Craig.

Stacy, that concludes management's prepared remarks. Can you please open the call up for questions?

Just curious, it sounded good about Delhi as far as no more cost there. Could you just talk about what you're seeing as far as the response now you've gotten back to flooding the field and what do you see going forward there?

This is Craig. The production continues in line with our expectations.

The areas that we're flooding continue to respond nicely. The area that we're isolating, where we had last year, the isolation is effective.

And in fact, we're putting in some commercial pumps to enhance the production the kind of primary -- secondary production out of that. That's going to be, basically, a waterflood and it's not going to be a CO2 flood.

But we're on track relative to what expect.

Okay. And at Riley Ridge, obviously, the Williams thing is just kind of starting the plant back up.

Obviously, it's just been a little bit of just slow going as you kind of learn that. Does that do anything as far as what the plans are going forward and obviously, turning it into what it's ultimately going to be as far as the CO2 plant?

Is that still going to be -- that time line still stay pretty stable, it's just the, for lack of a better word, getting the bugs out of it in the near term as we'd look to do that in the future?

Yes. It does.

This is Bill. It doesn't affect long-term glance at all.

I mean, it affects the potential -- our production numbers. But as Craig mentioned, on a cash flow basis, it's actually kind of a low-margin property.

Of course, that -- again, it's not the primary purpose of it long term. The purpose is to produce CO2, and we really won't start capturing the CO2 until we get the pipeline there, so that's late this decade.

Had a couple of quick ones for you. First, on the CapEx side.

You're running a little below kind of your guidance for the year. Can you talk to kind of the cadence of spending throughout the rest of the year?

I think we're pretty close to being on track. I mean, we still expect to spend $1 billion.

And I think it came in at, what, 20%, 21%. So no change.

It should be pretty consistent throughout the year.

Okay. And then on the repurchases front.

Phil, I believe you said you stopped repurchases in February. I just wonder if you could confirm that and kind of what you'd be looking for in the marketplace?

I know shares have had a bit of a bump here. Is there a specific price or how do you think about that with the remaining authorization that you have?

We have some specific prices in our mind, but I can't tell you. So the prices has firmed up a little bit, and we've been hanging in the 16s, 17s.

And so yes, we have purchased, at least, nothing material since the last conference call. But we still have $220 million authorized, and so ready to spend on kind of the factors we said.

It is subjective and depends on the stock price, the oil price, how we fund it and so forth. So we're happy that our stock has firmed up a little bit and expect that to continue.

Okay. Quickly on the dividend.

How can you kind of give -- what are the odds maybe if oil continues to strengthen that you may accelerate the dividend bump to that $0.50 to $0.60 range? Can you put a percent chance on that?

Do you need to see $110-plus oil for that to happen this year or are you pretty set in making that a 2015 item?

I think that dividend for 2015 is pretty certain. Actually, in our budget, we used an assumed price of $90.

So we don't need $110 oil to achieve that $0.50. If oil was $110, potentially, we can do a little better than that.

But no, we are fine where our prices are today, we should be able to hit that.

Okay. But the odds of maybe hitting that level later this year, is that something that's on the table?

Well, it probably -- potentially, I guess, it could be a consideration and would depend on prices. It's both the oil prices and differentials.

If you noticed, Mark said that our differentials probably have deteriorated just a little bit from Q1. So that also has a pretty big impact on our net realized price.

So we're continuing to monitor it. I wouldn't necessarily want you to assume any change in '14.

But '15, we're pretty confident that we can get to the higher number.

Okay. And then I just had one last one.

Craig had briefly mentioned some of the drilling at Hartzog Draw. I was wondering if you can confirm, you mentioned there were wells produced in line with expectations.

Are those the horizontal Sussex wells that you've been drilling? And if that's not, can you give an update on that program?

You're correct. This is the horizontal Sussex program.

It is performing in line with expectations. We just finished our third well there.

On balance, that program is looking like what we hope it would.

Okay. And then can you refresh my memory on what that -- the activity levels you're planning this year?

We want to keep one well -- one rig drilling throughout the year. So we've drilled on our fourth well.

We'll probably drill another several wells out [ph]. So another 7 or 8 wells.

I was hoping that you could give some thoughts on CO2 costs versus price realizations over the next couple of quarters. CO2 costs is linked to WTI, and much of your production is linked to LLS, which is looking like it might come under further pressure as those crude stocks rise in the Gulf Coast.

So can you talk a little bit more in detail about what steps you can take or maybe you are taking to not get pinched on CO2 if the LLS differential continues lower?

Well, a large portion of our CO2 cost is directly tied to the price we received at field. So that'll take care of itself.

Some of the other ones are tied to a little bit different pricing. So I don't think -- I think it'll pretty much balance itself out, so we're not too concerned about that at this time.

I just wanted to see if you guys could comment on the differential guidance for the year. I think you highlighted, Mark, how you may be a little bit below WTI, $3 to $4.

Do you anticipate that continuing for the balance of the year or is that more of a Q2 event?

Well, right now, Q2. I mean, I do think we're seeing a general softening, I mean, although differentials can change at any time and we've seen that historically here.

So at this point, I would say I would expect it to stay a little bit softer than maybe what we are anticipating. But I don't know if I expect it to stay exactly where it is or as rough as it is, but I think it's just -- it'll continue to change with the flow of crude and into the various locations.

And that's what we've seen. So our best estimate now is just kind of what we see for Q2, and then maybe getting a little bit better throughout the year.

But it's just tough to say at this point.

Shifting gears back to Hartzog Draw. Do you have any other potential zones that you see could be perspective horizontal, I know EOG [ph] and Anadarko were highlighting Rockies a little bit today in their calls.

We're looking at all the horizons we've got at Hartzog. We're not ready to talk about any additional upside, let's just leave -- you can look at the whole column there.

We're happy with the primary development we got sharing right now, and we'll be looking for more.

Phil, just one question maybe on the longer-term hedging strategy as you're shifting towards the dividend, higher dividend levels. Could you talk about that?

Any changes to your hedging strategy?

Well, no. We haven't -- we have pretty well hedged out through the third quarter of '15.

We haven't put anything in place for the fourth quarter or 2016 thus far. And it's really just because of the curve is so steeply backward dated.

We went to largely all swaps in '14, and 2015, we have a combination of swaps and collars. And I think that's probably the approach we'll take going forward, maybe a combination of both.

We are trying to get a little more certainty in our cash flow since we're paying dividends. But we also like to have little bit of optionality with the collars.

And obviously, we can absorb a little bit of downside, of course, and you get a little bit of the upside. So we've been watching, late '15 and '16, but we have not pulled the trigger yet.

It seems to gradually get better if we just wait a little longer.

Okay. And my final question, I know there's a been little bit of a delay at the Mississippi -- for one of the Mississippi power plants which is going to provide some man-made CO2 for you.

Can you update on that? And does that have any impact in terms of your expected volumes going forward?

And your knock-out [ph] effect there?

We have the expectation that's entirely based on those conversations, our planning and assumptions haven't changed. We still anticipate we'll get CO2 from them in the fourth quarter.

It could be -- I mean, there's a chance it could be delayed, there's a chance it could be sporadic. If that happens, we have the option of accelerating our drilling program to get the needed CO2 supply.

So we continue to talk with them regularly. And if those plans change, we've got a provision to get the supply we need.

So bottom line is, we're covered on our CO2 supply needs for next year.

Okay. Then just to clarify, so if there was a quarter or 2 delay in that project, you wouldn't anticipate any impact as you could add some incremental volumes from Jackson Dome.

Is that -- am I understanding that correctly?

We would likely to drill an additional well at Jackson Dome. And that's the $15 million of CapEx to do that.

So that probably would be our response to a material delay in that being a few quarters delay from Mississippi time.

Sorry, I hopped on late, so my apologies if you touched on this already. I had looked at the gas production for the quarter.

And I had thought it might be a little higher sequentially because of Riley Ridge coming on. Can you just give me a sense of what the increase was and whether the ramp-up was going on through the quarter, and are we going to see higher volumes later in the year?

Specifically to Riley Ridge. We have had lower run times at Riley Ridge than we had planned on.

And frankly, we also had a lower inlet feed volume than we anticipated. We know the issues that are and it's just kind of started issues associated with the first-of-its-kind plant.

So a little more detail, we've got the scale instituting that, we've got to get out with some sulfur depositing in the tubing. So we'll address that, we're addressing that.

And there are some deep bottlenecking to other plant facilities. And so that's what's causing the lower production volumes of natural gas in the first quarter.

We're working through those issues. So we do anticipate that our natural gas line will increase as the year progresses.

So just working through those issues.

Okay. And is that basically within what you have budgeted for the project or is there going to be any bit of an uptick there for some of this activity?

At the moment, we don't anticipate there's any significant additional spending to address the issues I've mentioned. We're basically talking to the whole tubing works [ph] as we build out scale, and possibly an additional tanker vessel.

And some relatively modest response needed to address these issues. I would kind of characterize them as not that unexpected and just sorting out a new plan.

Fine. And just one other housekeeping thing.

The stock compensation number for the quarter was a little lower than I expected. Was it any different from the expectations you guys talked about on the fourth quarter call?

No. I don't think so.

We just typically have a lot of impacts running through in the first quarter, payroll taxes and such, as not just executive, but the whole company's long-term incentives and such. And so as that rolls through that has to drive up our first quarter numbers.

But I don't think there's anything unusual about other compensation.

Okay. Actually, the number was somewhat lower than I expected.

But this was -- I might have just been off in my estimate then. Okay.

Great. I think that's all...

[indiscernible] guided to basically low-40, up -- mid-$40 million range is kind of where we're targeting there.

I apologize if I missed this, because I jumped on late. But are you still targeting downtime this summer at Riley Ridge?

It's still on our plan. We are kind of looking at, can we move that turnaround.

It will be determined at some point this year, and we're just trying to figure out that schedule as we learn more about how the plant is operating. Bottom line is, our current plant is still is for one month turnaround.

Great. And then my follow-up.

Phil, given that you're now a growth and income company focused on dividends, dividends growth, does that dampen your interest in the near term to consider bolt-on acquisitions that you've historically looked at, whereby you can increase your inventory of fields to eventually flood?

Not at all. One, we still need additional inventory long term, although we are pretty well set for the next several years with projects we have in place.

So we don't feel like there's a lot of pressure to buy something, but would love to add to the inventory. That just extends the growth curve out several more years.

Secondly, it depends on what you buy. I mean, most things would also probably be accretive to cash flow in the short term.

We do look for projects that have upside. We're not really into just buying PDP because we just can't make much money buying PDP.

But the current production actually does help the short-term metrics. So we'd love to do some acquisitions.

And we've looked at some this year, we just haven't been successful or pulled the trigger.

When you mentioned you looked at some this year, is it still that the sellers are reluctant to part with their assets at a reasonable price?

Well, we haven't found the ones we really, really want. And so we -- the ones we've looked at probably have been -- we've been kind of lukewarm about it.

And we're just [indiscernible].

On the Delhi Field, when do you expect the reversionary interest to take effect?

We stated that we expect it to go in effect later this year. I think we had targeted late third quarter, early fourth quarter, was our best estimate for now.

Okay. Before we end the call today, let me just quickly cover a few housekeeping items.

We will be holding our Annual Meeting on Tuesday, May 20, Marriott at Legacy Town Center here at Plano. All shareholders are welcome to attend the meeting, and we encourage you to vote on the items in this year's proxies.

On the conference front, several members of our management team will be participating in investor conferences over the next 2 months. As always, you can check the Investor Relations section of our website with details on each presentation, including the webcast and slides.

Lastly, we plan to report our second quarter 2014 results on Wednesday, August 6, and hold our conference call at that day, our usual time of 10:00 a.m. Central.

Thanks again for joining us, and I hope you all have a great day.