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Penn Virginia Corporation (PVAC) Q4 2018 Earnings Conference Call Transcript

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Penn Virginia Corporation  (NASDAQ: PVAC)
Q4 2018 Earnings Conference Call
Feb. 27, 2019, 11:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the Fourth Quarter and Full Year 2018 Results, 2019 Outlook and Penn Virginia Combination Update. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session, instructions will be given at that time. (Operator Instructions) As a reminder, this conference is being recorded.

I would now like to turn the conference over to your host Denbury, Director of Investor Relations, Mr. John Mayer. Please go ahead.

John Mayer -- Director, Investor Relations

Thank you, Greg. Good morning, everyone and thank you for joining us today. With me on the call are Chris Kendall, our President and Chief Executive Officer; Mark Allen, our Executive Vice President and Chief Financial Officer; Matthew Dahan, our Senior Vice President of Business Development and Technology; David Sheppard, our Senior Vice President of Operations; John Brooks, Penn Virginia's President and Chief Executive Officer and Steve Hartman, Penn Virginia's Senior Vice President and Chief Financial Officer.

Before we begin, I want to point out that we have slides, which will accompany today's discussion. Should you encounter any issues with slides advancing during the webcast portion of the presentation, please refresh your browser. For those of you that are not accessing the call via the webcast, these slides may be found on our homepage at denbury.com by clicking on the quarterly earnings center link under resources.

I would also like to 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 the slides accompanying today's presentation. Our most recent SEC filings and today's news release, all of which are posted on our website at denbury.com. Also, please note that during the course of today's call, we will reference certain non-GAAP measures, reconciliation and disclosure relative to these measures are provided in today's news release as well as on our website.

With that, I will turn the call over to Chris.

Chris Kendall -- Director, President and Chief Executive Officer

Thanks, John. I appreciate all of you joining us today. I'd like to welcome two members of the Penn Virginia leadership team, John Brooks, CEO and President; and Steve Hartman, Senior VP and Chief Financial Officer. They'll be available to address questions during the Q&A portion of our call. Our prepared remarks during the call will initially cover Denbury's 2018 Fourth Quarter and Annual results and 2019 plans. I'll follow that with an updated look at our previously announced acquisition of Penn Virginia, which you'll see continues to be a compelling combination, even at today's lower oil prices. At the conclusion of our prepared remarks, we'll have the Q&A session.

2018 was a great year for Denbury, we set multi-year records for our Company in each health, safety and environmental category. We entered into a merger agreement with Penn Virginia in late October with the vision of combining two complimentary platforms that will be well-positioned strategically and financially to deliver value to both sets of shareholders both exploitation and expansion of existing fields continue to be highly successful and sanctioning of the CCA EOR project laid the groundwork for adding resources, well in excess of Denbury's current total proved reserves. We grew the reserve base adding more reserves and we produced in the year. We generate -- we reduced net G&A by 30% and we generated more than $80 million in free cash for the year, while reducing net debt by over $280 million. We improved our leverage ratio by almost 2.5 turns and we extended our bank line into 2021 finishing the year with the completely undrawn credit facility.

Based on the actions we've already taken, we are well-positioned for success in 2019. Shareholder Meetings for the Penn Virginia merger are planed to be held April 17 and will be reaching out to shareholders of both companies in the meantime, as we seek their approval of this unique and exciting combination. We set our budget around generating positive cash flow at $50 oil, with upside to significantly greater free cash flow at price of above $50. We will continue to raise the bar for HSE performance, seeking to build on the record level set in 2018.

Even with capital well below 2018 levels, we'll be testing promising new exploitation concepts, as well as extending upon the successes we've already achieved, demonstrating the resilient nature of our asset base. We'll continue to invest in our long life fields, notably progressing the CCA EOR project, the 6 Phase at Bell Creek and a new development area at Heidelberg. Finally, we will remain fundamentally focused on improving our financial profile, building on our significant success in achieving a stronger balance sheet over the past few years.

Slide 8 provides a closer look at how we expect to generate free cash flow in 2019, a $50 oil and how that free cash flow is enhanced by higher prices. The significant decline in oil prices from October through the end of December last year was one of the fastest and sharpest declines the industry has ever experienced. And to the first-two months of 2019, oil prices have recovered nicely, but with the recent volatility, we still feel it makes sense to base our 2019 plans around a $50 oil price. We're committed to continuing to invest within the boundaries of our cash flow.

As you can see here, even by reducing our capital budget to a range of $240 million to $260 million, we are still able to generate significant free cash flow with oil at $50, increasing nicely at higher prices. For example, a $50 oil, we estimate that we will generate free cash flow of $50 million to $100 million and at $60 oil, we expect that to increase to a range of $120 million to $170 million.

Turning our attention to the right side of this Slide, we lay out in more detail the 2019 estimated sources and uses of cash. Assuming a $50 oil price, we expect to generate operating cash flow of $420 million to $470 million in 2019, which assumes $30 million to $40 million of interest being capitalized. Due to the accounting for the debt exchanges, we completed over the last couple of years approximately $85 million of interest we pay on our bonds is reflected as a reduction of debt in our financial statements, instead of interest expense. So we backed that amount out of operating cash flow to show the actual level of cash we have available.

Walking down the numbers, and assuming the mid-points of our development capital and capitalized interest, we end up in the free cash flow range of $50 million to $100 million. One other thing, I'd like to point out on this Slide is that generally an unhedged $5 moving oil prices would create an approximate $100 million change in cash flow. As shown here, our level of free cash is not increasing at that same level, as we step up in oil price, as the floor prices on our hedges are set at levels averaging higher than $55 oil.

Even at these reduced capital budget levels, we are able to invest in important projects, including the completion of Phase 6 development at Bell Creek, additional development at Heidelberg after four exploitation wells at CCA, testing a new exploitation concept at Conroe and flow testing our recently drilled Cotton Valley well at Tinsley. We've also extended much of the plan 2019 investment in the CCA EOR project into 2020 and we'll be procuring the line pipe for the CO2 pipeline in 2019.

Production for the fourth quarter 2018 was about 700 BOE per day above the third quarter reaching 59,900 BOE per day and resulting in full year production of just over 60,300 BOE per day, in line with our recent guidance and up slightly from 2017. Production from Bell Creek continues to grow with high performance from Phase 5. Field production there reached a record 44,00 BOE per day in the fourth quarter with gains expected to continue into 2019. As a result of reducing our capital investments by as much as 25% from 2018, we expect slightly lower production in 2019 and projecting full year production between 56,000 and 60,000 BOE per day.

Similar to 2018, we expect the quarterly production profile to be seasonally lower mid-year, increasing into the fourth quarter. Operating costs of 22, 24 (ph) per BOE for the full year were in line with our prior guidance. Total LOE was $128 million, up about $5 million from the third quarter, primarily due to increased CO2 costs and higher workover activity levels. The increase in CO2 costs from the third quarter was primarily due to the planned maintenance on part of our Gulf Coast pipeline system, as well as higher non-operated CO2 costs associated with higher purchase volumes in the fourth quarter of 2018. We expect both workover activity and non-operated CO2 cost to moderate with lower oil prices in 2019.

Our operations teams are highly focused on managing and reducing LOE and this is evidenced through holding our power, labor, repair and maintenance, and chemical costs flat since the fourth quarter of 2017. Well, I'm confident that our teams will be successful in reducing the total LOE, just as we've had success in reducing costs in other areas, producing fewer barrels in the year could apply upward pressure to the per BOE LOE metric. So at this point in the year, we're guiding to a fairly broad full year range of $22 to $24 per BOE.

We grew reserves of the company in 2018 more than replacing production to reach $262 million BOE. Strong SEC oil pricing up over $14 year-on-year increase the company's PV-10 value by about $1.5 billion to reach $4 billion at year end 2018. When considering the effect of oil price on Denbury's PV-10, a good rule of thumb is that a $10 oil price change results in about a $1 billion PV-10 change and the 2018 results are right in line with that concept.

As we planned our 2019 capital budget with the backdrop of lower oil prices in the fourth quarter of 2018, our development team found a solution that could spread much of the CCA EOR projects spend outside 2019, completing the pipeline installation in 2020 and minimizing our 2019 capital exposure in this uncertain oil price environment. Because, the availability of CO2, to flood CCA will be quite a bit greater in 2021 than in 2020, we expect the production build up should be minimally impacted by the timing of shift and Phase 1 should reach the same peak production level right about the same time as before the capital shift.

We've plan to procure the line pipe for the pipeline in 2019 and hit the ground running for the installation in 2020. We're still analyzing financing options, including self funding or a JV structure for this investment. We continue to have very good results with exploitation at CCA. We've drilled seven successful Mission Canyon wells to-date with an average 30 day initial rate of over 800 barrels per day. We now have successful Mission Canyon wells as far as South as Little Beaver and as far north as Cabin Creek, extending over 40 miles. We believe we had as many as 14 additional locations and we plan to drill up to four wells in 2019 as we continue the program.

In our last update, we mentioned water influx encountered in two Mission Canyon delineation wells.In the fourth corner, we encountered a similar issue on the down-dip Pennel extension. In December 2018, we have reentered two of the three wells and isolated portions of the well bores and we're able to initiate relatively low volumes of oil production from these wells and are evaluating sidetrack options for the third. Our learnings from these wells have been incorporated into our plans for additional drilling.

On the whole, the Mission Canyon program has been highly successful, generating greater than 50% return at $50 oil on our total investment to-date. We are successful with our first Charles B well in Cabin Creek. If you see in the inset map, the Charles limestone interval just about 250 feet above the Mission Canyon, where the Mission Canyon has a strong aquifer drive, and Charles B has a weak aquifer, and we expect Charles B wells to flow at a lower initial rate, but at a sustained oil cut. This was the case in our first well, where the oil cut has remained in the 75% range, given a great upside for secondary or tertiary development. We think we have up to 14 wells in the prospective range for the Charles, which runs in the Northern part of CCA, beginning at Cabin Creek and extending all the way north to Glendive.

We're excited about taking the successful concepts we've proven in CCA using today's off the shelf horizontal well technology to place long laterals and oil bearing reservoir that are too thin or that don't have the reservoir qualities to support the economic vertical wells. And applying that technology to unswept reservoirs in several of our Great Gulf Coast fields. These unswept reservoirs are typically lower quality rocks in the historic producing intervals and as a result, they were not effectively produced during early field life, and we're not significantly impacted by aquifer movement in the field.

We plan to start this exploitation program in our Conroe field and Horizon called the 2A sand. The first well will be fairly simple, low cost and horizontal estimated at $3 million to drill and complete. We plan to drill the well in the second quarter of 2019. With success, we think we have more than 20 possible well locations in the Conroe 2A sand and we see additional potential in the 1A and 3D sand in Conroe as well. And as I mentioned, we think this concept can be applied at multiple Denbury Gulf Coast fields. We finished drilling our Cotton Valley Haynesville test well in the first quarter and logged about a 100 feet of net Cotton Valley pay as well as about a 100 feet of net pay above the Cotton Valley, that could be oil bearing. No pay was logged in the higher-risk Haynesville target just below the Cotton Valley.

Our next steps sort of flow test in the second quarter to determine well productivity and plan potential future development. Also in the Tinsley field, we completed our second Perry well in the fourth quarter of 2018. Peak production of under 200 barrels a day was below our target threshold to continue Perry investment. We plan to deploy this program where we shift focus to higher value Gulf Coast opportunities.

And now, I'll turn it over to Mark for a financial update.

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

Thank you, Chris. In addition to the normal financial update, I'll provide certain 2019 guidance information that will address Denbury's business on a stand-alone basis. Little later in the call, we will also review updated summary projection information on a combined basis with Penn Virginia.

On Slide 19, we provide a summary of our 2018 cash flow from operations and a reconciliation of our free cash in excess of capital expenditures. As shown on the top portion of this slide, cash flow from operations in 2018 before changes in assets and liabilities and adjusted for special items was $527 million. After reducing that amount by $86 million for interest that's reflected in our financial statements as repayment of debt, we generated net cash flow of $441 million and free cash of $81 million after development capital and capitalized interest. This free cash allowed us to build a small cash position ending the year with $39 million of cash on hand.

Moving to Slide 20, our leverage profile and debt reduction continue to be top priorities for us. We are extremely pleased with the progress we've made during 2018, reducing our net debt by over $280 million for repaying our bank line and extending its maturity to 2021. As our plans put Denbury in very position to generate meaningful free cash in 2019, we will continue to evaluate options for improving the balance sheet and weigh those against other uses or accumulating cash for future development capital.

Slide 21 shows the improvement we have made in our leverage metrics. Our trailing 12 months debt to EBITDAX ratio improved significantly from 2017. Coming down to 4.2 times at year end 2018 and if you exclude hedging impacts, our trailing 12 months ratio was 3.3 times. For 2019 based on recent oil price futures, we would expect our leverage ratio on a stand-alone basis to remain relatively stable, and the 4 times -- 4 times range.

Slide 22 provides a summary of our oil price differentials. Excluding any impact from hedges, for the fifth consecutive quarter, our realized oil price was higher than NYMEX prices averaging $1.69 above NYMEX. Our differential in Q4 was slightly better than we guided last quarter, as the LLS premium for our Gulf Coast production strengthened in the fourth quarter helping to offset the weaker differentials for our Rocky's production. Based on our expectation for differentials in Q1, we currently estimate an overall positive differential, similar to what we realized in Q4.

Moving to the next slide, I'll review some of our expense line items. Chris already covered LOE, so I'll start with G&A expense, which was $10 million for the fourth quarter, down significantly from $22 million in the third quarter. The significant decrease from Q3 was due primarily to downward adjustments and estimated performance based compensation, which was impacted by the negative move in oil price and our stock price during the fourth quarter.

On a full year basis, our G&A expense was down over $30 million or 30% from 2017, due to continued focus on costs, as well as -- for a workforce reduction in 2017. Our net G&A related to stock-based compensation was approximately $3 million in the fourth quarter. On a stand-alone basis, we expect our 2019 annual G&A expense to be relatively consistent with 2018. Generally in the upper teens to $20 million per quarter with Q1 typically a bit higher than the other quarters. We expect stock-based compensation to represent roughly $15 million of our 2019 expense.

Net interest expense was $18 million in Q4, essentially flat with the third quarter. On the bottom portion of this slide, there is a more detailed breakout of the components of interest expense and you will see the cash interest continues to remain steady. Capitalized interest was also flat at $10 million for the fourth quarter and we currently expect our capitalized interest for each quarter in 2019 to be in the $7 million to $10 million range. Our depletion, depreciation expense in the fourth quarter was $60 million, larger than expected increase from last quarter due to incremental cost subject to depletion and the acceleration of depreciation of certain costs in Q4. For 2019, we currently expect average in the $60 million range for each quarter.

Slide 24, provides a current summary of our oil price hedges. Since our last update in Q4, we have added more LLS swaps to both 2019 and 2020. We currently have hedges approaching 70% of estimated 2019 production. And as shown on the bottom portion of the slide, our hedges are providing some nice quarter levels to protect our cash flow in 2019, while still providing significant upside participation if prices move higher.

And now, I'll turn it back to Chris.

Charles Meade -- Johnson Rice & Company -- Analyst

Thanks, Mark. Many of our investor conversations over the past few months have been regarding the Penn Virginia merger. Most investors see the logic of the combination and the tremendous opportunity that it presents for both companies. We continue to believe that this combination will create a company that is distinctly resilient, sustainable and valuable. Let me take a few minutes to reiterate the reasons why we entered into this transaction and address some of the questions, we're hearing from investors. Denbury and Penn Virginia are two complementary businesses and we think combining the strengths of our respective assets and capabilities creates a unique opportunity to deliver value.

For Denbury adding scale in the Eagle Ford, provides a platform for the next generation of enhanced oil recovery. At the same time, Penn Virginia will be benefiting from Denbury's industry leading EOR expertise, and access to our extraordinary CO2 resource providing a step change to EOR. As we outlined earlier, Denbury have a highly resilient set of long-lived, low-decline assets, which creates a stable production base with strong cash flow. At the same time, remaining primary development on Penn Virginia's acreage provides opportunistic, high return flexible investment optionality.

The combined operating model is flexible, growing and sustainable. Even before considering incremental EOR production, we expect that the combination will provide 5% to 10% annual production growth, remaining heavily oil weighted and generating strong operating margins and free cash flow. The financial profile of the combined company is strong with total liquidity over $600 million and improved access to capital, as well as a lower overall cost of capital for the combination. And as we look ahead, our shared discipline around managing CapEx within cash flow combined with the strength of that cash flow should put us on a path to reduce total leverage to at or below 2.5 times by the end of 2021.

As we've continued our preparations for the merger, our conviction in the potential has grown. EOR production in the Eagle Ford is still growing significantly and I'll touch on that in more detail in a few slides. Taking into account the decline in oil prices, we updated the preliminary combined pro forma estimates that we initially provided back in early November. Market conditions at that time were such that we prepared those predictions based around the $60 to $70 oil price range. Over the last several months, we've reworked those projections for both companies at much lower levels and the information here now assumes an oil price range of $55 to $60 over the next few years, which is representative of recent oil prices and future strip prices.

As we stated before, we believe this combined company can produce attractive organic growth while generating a significant amount of free cash at current oil prices, a shift that many companies are currently trying to achieve. The biggest changes made to the model are adjusting capital expenditures to fit the current price environment and the resulting production growth in cash flow and we have also provided another year of projections beyond what we showed previously. Capital expenditures have been moderated for both stand-alone companies and the current estimates assume a two-rig program in the Eagle Ford for 2019 and '20, shifting back to a three-rig program in 2021.

For Denbury, we assume the same development plan for 2019, as we presented earlier and the continued development of CCA on par with our current plan. As you can see, development capital remains well within operating cash flow while production is expected to grow 5% to 10% on a compound annual level over this time period. The positive attributes around high oil mix and top tier operating margins have not changed. And although, our deleveraging plan is adjusted slightly in the revised plan. We still believe achieving a very respectable 2.5 times by 2021 is a great place to be and we believe there will be opportunities to improve upon that and drive it even lower over the longer term.

The next slide revisits the transaction, consideration and subsequent ownership of the combined company. The shareholder meetings have been scheduled for April 17 and we expect the proxy information to be mailed to shareholders in the near future. We have updated the numbers on the bottom of this slide to reflect the most recent information around reserves, production and cash flow, and CapEx numbers for 2018, which also helps illustrate the increased size and scale of the combined company. The cash and stock transaction provides immediate liquidity and the potential to realize upside value, given the unique strengths of the combined business.

Slide 29 is a review of the financing, we have in place for the transaction and the pro forma view of the combined company's capital structure. Just a reminder that we have fully committed financing from JP Morgan to cover $400 million senior secured second-lien bridge loan and the new $1.2 billion senior secured bank credit facility. This will allow us to cover the $400 million cash payment and resources to refinance Penn Virginia's existing debt as needed. We would expect to have over $600 million of liquidity available upon closing the transaction, which will be immediately accretive to Denbury's debt metrics and will provide a solid foundation from which to continue to improve the combined company's leverage profile and sustainability.

Turning to Slide 30, we've shown most of the slide before, but we are included again here to highlight the strong growth in the Eagle Ford EOR opportunity. The number of wells on EOR has grown by 100, since our last count to 300. And total EOR production in the Eagle Ford reached 18,000 barrels of oil per day in 2018. We see that number continuing to grow as the play gains momentum. We also see unique advantages in using CO2 compared to rich hydrocarbon gas, including greater oil recovery and applicability in areas where rich hydrocarbon gas is not effective.

And importantly using CO2 provides the potential for large quantities of man-made CO2 be stored underground providing much needed capability for industrial generators of CO2 to reduce their emissions. The key difference between CO2 and rich hydrocarbon gas, is that CO2 is miscible and not as able to combine with the oil into one fluid at a much lower pressure than rich hydrocarbon gas. This helps in a couple of ways.

First, there is a larger pressure range to work with before reaching a wells fracture pressure; and second, the surface injection transfer can be much lower, reducing the cost and complexity of surface facilities equipment. The bottom line is that we see CO2 is having unique benefits for use in the Eagle Ford, including superior access to parts of the play that may not be floodable with rich hydrocarbon gas injection.

That concludes our prepared remarks and I'll turn it back over to John.

John Mayer -- Director, Investor Relations

Thank you, Chris. That concludes our prepared remarks. Greg, can you please open the call up for questions.

Questions and Answers:

Operator

Thank you. (Operator Instructions) Your first question comes from the line of Charles Meade from Johnson Rice. Please go ahead.

Charles Meade -- Johnson Rice & Company -- Analyst

Good morning, Chris -- you and the Penn Virginia guys and the rest of the team there. Well, I want to thank you for putting that Slide 31. I'm not going to ask question about it, because I already have asked a question about that, but I think it's a really helpful one. But I wanted to start actually with a big picture question about your CapEx really as a stand-alone Denbury for 2019. I get the idea of setting a CapEx budget as consistent with $50 oil. What's a little more difficult -- what's not as obvious to me is why you would choose to run or choose $50 million to $100 million of free cash flow at $50 rather than invest that in projects? My kind of back in the envelope math says that actually your debt metrics would be better, if you actually spent that $50 million to $100 million rather than just let it pile up on the balance sheet. So can you talk about your thought process in that regard?

Chris Kendall -- Director, President and Chief Executive Officer

Sure. I'll start and then I'll ask Mark to jump in after I say a few words, but when we are preparing the budget for this year in the backdrop of that collapse in oil that we saw in the fourth quarter, just tremendous volatility and what you see with oil and we wanted -- number one, be confident that we were coming into this year and the position that could put us into a strong position. When we found the opportunity to move CCA pipeline installation into 2020 without really impacting the project, which I think is a remarkable achievement by our technical teams. We also saw that -- that would put some additional capital needs on 2020 and so building some cash as we come into the year is not necessarily a bad thing when we look at 2020. Then the flip side is that we also have the opportunity to continue to use some of that cash to work on the balance sheet as we see opportunities come up in the course of the year.

Charles Meade -- Johnson Rice & Company -- Analyst

Okay. Chris, just to make sure I understand you right. So by -- once you saw this opportunity to shift to CCA CapEx into -- some of it from '19 into '20, you kind of just left the rest of the capital budget as it was? And you're just accumulating the cash. Is that a fair read?

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

Not exactly, Charles. We took a pretty hard scrub through all of our project portfolio and high graded projects that we really wanted to get done, whether they're just foundational projects like what we're doing at Bell Creek or Heidelberg or their opportunistic projects like this exploitation test at CCA that is -- I'm sorry, at Conroe that if successful opens a whole new world of exploitation along the Gulf Coast, but even with that we pulled back. Just an example, we've pulled our CCA exploitation down to four wells from the number 10 or so that we drilled in 2018. We're holding those by production, we have the opportunities there. Just when we looked at what we wanted to do pulling some of that back and high grading the projects maintenance costs.

Charles Meade -- Johnson Rice & Company -- Analyst

Got it. That's helpful to understand. Your process of thinking there. And then, if I could just pick up on that exploitation, in particular the CCA and your -- this Charles B zone. I think you did a good job addressing what's going on there -- in your prepared comments. But I find myself wondering, you got this Charles B zone -- you got your real stratigraphic stack on that same slide, are there more? I mean, so you did this with the Mission Canyon, now you've done it with the Charles B. Should -- is it going too far to say that we should look for similar things in the Lodgepole, Interlake, Stony Mountain and Red River?

Chris Kendall -- Director, President and Chief Executive Officer

Certainly, Charles, we think there could be more. And Charles -- the Charles Interval has the several benches in it. Charles B is one of those. And so we think there is potential there as well, of course, as we go down into the Lodgepole, Red River and so on. Those are -- those get to be reservoirs have been historically produced. So, the opportunities we're seeing are in these upper intervals at least right now, but certainly we see more than what we've tapped into so far, I think there is very interesting potential in that Charles as we look across CCA and -- at those different benches that we have there.

Charles Meade -- Johnson Rice & Company -- Analyst

Great. Thanks for the color, Chris.

Chris Kendall -- Director, President and Chief Executive Officer

Yeah. Thanks, Charles. Take care.

Operator

Your next question comes from the line of Tim Rezvan from Oppenheimer. Please go ahead.

Joe Beninati -- Oppenheimer -- Analyst

Hi, folks. Joe Beninati on for Tim, this morning.

Chris Kendall -- Director, President and Chief Executive Officer

Hi, Joe.

Joe Beninati -- Oppenheimer -- Analyst

My question is on the LOE front, I know Chris, you gave some color on your prepared remarks, but just looking at the broad range of 2019 guidance. Could you maybe talk a little bit more specifically on how some of the exploitation projects would potentially move the needle on bringing that back down?

Chris Kendall -- Director, President and Chief Executive Officer

Sure, Joe. And when I think about the LOE and what some of these incremental opportunities can do for us. They tend to be lower LOE type of projects and so the more of those that we can pull into the mix, the better impact will have on those -- on that per barrel metric for LOE and that's something that we don't just look at in exploitation other areas where we can enhance production in our existing fields. Just with the fixed cost that you have there anything that we can do to improve that is going to help. That's why we put a pretty big range around it. I see a lot of opportunity to move that to the positive either through doing better with our production, then we have in the range there or saving money through adding production that's lower cost like you mentioned.

Joe Beninati -- Oppenheimer -- Analyst

Okay. That sounds great. That's all for me. Thanks.

Chris Kendall -- Director, President and Chief Executive Officer

Thanks, Joe.

Operator

Your next question comes from the line of Jacob Gomolinski from Morgan Stanley. Please go ahead.

Jacob Alexander Gomolinski-Ekel -- Morgan Stanley -- Analyst

Hi. Good morning and thanks for taking the questions.

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

Good morning, Jacob.

Jacob Alexander Gomolinski-Ekel -- Morgan Stanley -- Analyst

Can you just talk to some of the JV options at CCA that you're considering?

Chris Kendall -- Director, President and Chief Executive Officer

Sure. A bit preliminary, but in general, what we're thinking about is bringing a partner in to help us with the pipeline costs and we'd be looking at something that would represent a payment over time, as opposed to us incurring all the expense upfront and so, we think there is several parties that would be interested in doing that with us. And so that's the, actually the, the primary scenario.

Jacob Alexander Gomolinski-Ekel -- Morgan Stanley -- Analyst

Okay. And then, I guess, just as you think about sort of the CapEx level, it looks like ex-capitalize items or another items you add about $200 million of CapEx for the year, with a fairly slightly declining production. I think you had mentioned in the past $275 million of maintenance CapEx or in that ballpark. So just trying to get a sense of where that maintenance figure might be now? And what might be driving any potential changes, if there are any?

Chris Kendall -- Director, President and Chief Executive Officer

I think what we've said recently Jacob, as we thought about it and looked at that exact same question is that we're probably in the 300 or somewhere north of 300 where that maintenance capital level goes, it's a little bit hard to pin down because in any given year of course, we have investments that generate returns in that year, like these exploitation wells. We have investments that generate returns -- years down the road, like at CCA and then we have some in-between, like what we're doing at Bell Creek.

And so you're going to always have an overlapping of the term of when those investments make an impact, but when we try to boil it down and we look at where we've been with capital over the past few years, as low as -- the low 200s and then as high, what really is high as just in this range where we are in 2018, 300 or a bit north of 300 to me feels like the right ballpark, but again, we need to look at any given year and see how much of that capital is actually applied to production in that year and balance that.

Jacob Alexander Gomolinski-Ekel -- Morgan Stanley -- Analyst

Okay. And then, I guess, just one last housekeeping question. I know you had mentioned that at the time the RBL draw to finance that acquisition I guess at the end of 2017, would

be able to kind of pay that down with the Houston surface acreage sale. Just curious if there was any potential updates on that sale process, if it's so going to be sold sort of one big package or if you're thinking about breaking up or just really any updates on that front?

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

Thanks for asking that Jacob and we wanted to update you on that process and so as we communicated last, we still feel very confident in the value of the acreage that we're selling, it's generated great interest and we see that moving forward positively. At the same time, the complexity of selling such large positions is just causing it to take a bit more time than we expected. So we -- to-date, we had sent about $5 million across to the other side. Recently, we have signed contracts probably in the $9 million or $10 million range that we expect to close here in the next quarter or two. And we're going to keep a pretty cautious look at 2019 of how much we think will achieve from that and that's probably in the $10 million to $15 million range with the bulk of the remaining sales to be outside of 2019. Like I said, it's just a work in progress its going to take some time to bring all of that across the finish line.

Jacob Alexander Gomolinski-Ekel -- Morgan Stanley -- Analyst

Okay. That's it from me. Thanks very much. Appreciate it.

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

Thanks, Jacob.

Operator

Your next question comes from the line of Eric Seeve from GoldenTree. Please go ahead.

Eric Seeve -- GoldenTree -- Analyst

Hi, guys. Jake just asked my questions. But can you just kind of just to repeat the numbers you just said regarding the timing of the Houston land sale, did you say, you signed contracts for an incremental roughly $10 million that could close the next few quarters and what was the comment about the remainder of the year?

Chris Kendall -- Director, President and Chief Executive Officer

You bet, Eric. So, right now that's all we're saying for the remainder for the year. We of course, we're working that right now and more could come in the course of the year. We still believe the overall value is at least as great as we originally talked about and it's just that we expect good part of that to fall outside of 2019. So, when we think about 2019, we're thinking as it's $10 million to $15 million range for what we'll actually realize cash in hand and we continue to work the process we'll see more in the coming time after 2019.

Eric Seeve -- GoldenTree -- Analyst

Okay. Thanks guys.

Chris Kendall -- Director, President and Chief Executive Officer

All right. Thanks, Eric.

Operator

Your next question comes from the line of David Meats from Morningstar. Please go ahead.

David Meats -- Morningstar Inc. -- Analyst

Hi, guys. Just wanted to chiming on and find out about the scope of the EOR in the Eagle Ford. I'm looking at your Slide 31 and it looks like you have kind of a range of CO2 applicability. And I'm just wondering the numbers you gave on the prior slide about the projected EOR increases. Does that applied like a particular area here like maybe where it's more applicable or is that just kind of an average over the position. And are all those 300 wells that you guys identified, do they are they all viable for further kind of development in the oil price environment that we're looking at?

Chris Kendall -- Director, President and Chief Executive Officer

Well, David, a couple of things. First the 300 wells identified or across the Eagle Ford, so those are operated by other operators at this point and they are in various areas. And we show them on the prior slide in the purple dots across that Eagle Fort trend. So, that's an area where you just -- you see the viability of rich hydrocarbon gas and that's all that's being currently used in the Eagle Ford for EOR.

As you look at the slide that you referenced, as we move to the northwest to the lower GOR, the more black oil window of the Eagle Ford. That's an area where we steadily see increasing promise for CO2, just because of the nature of the injectant and how we see that behaving. So, that's what we're portraying there, but the 300 is across the Eagle Ford and that's the amount of the number of well that you see right now.

David Meats -- Morningstar Inc. -- Analyst

Okay. That's super interesting. Thanks for clearing that up. And just one more from me on the CapEx. It just kind of stands out on the Slide 25 where you have the projections that we got, decreasing capital and increasing production in 2019 and not really the other years. And I guess that shifting that the CCA capital in this 2020 is a big part of that. But can you just give some more color on kind of the different direction of the capital in the production?

Chris Kendall -- Director, President and Chief Executive Officer

Okay, David. We're trying to catch up with you on Slide 27, you said?

David Meats -- Morningstar Inc. -- Analyst

Yes, 27 basically just in 2019 you got decreasing capital versus 2018, it's our pro forma, and that the production is going up, so obviously diverging direction. Just kind of stands out a little bit. I'm guessing that that's mainly the CCA pipeline being differed.

Chris Kendall -- Director, President and Chief Executive Officer

That's absolutely correct is just that shifting is the bulk of spends from 2019 into 2020, David.

David Meats -- Morningstar Inc. -- Analyst

Okay. And so were that not changing we'd be looking at probably an extra $100 million $150 million in '19?

Chris Kendall -- Director, President and Chief Executive Officer

Yes, if we were spending it in '19, yes.

David Meats -- Morningstar Inc. -- Analyst

All right. That makes sense. Thank you, guys.

Chris Kendall -- Director, President and Chief Executive Officer

Yes. And that's the way it was shown before in the previous model, that's correct.

Operator

And at this time, there are no further questions. Mr. Mayer, please continue.

John Mayer -- Director, Investor Relations

Before you go, for your calendars we currently plan to report our first quarter 2019 results on Tuesday May 7, and more about the conference call that day at 10 a.m. central. Thank you again for joining us on today's call.

Operator

Ladies and gentlemen, this conference will be available for replay after 12:30 central time today through March 27. You may access the AT&T Teleconference Replay System at any by dialing (1) 800-475-6701 and entering the access code 426562. International participants dial 320-365-3844. Those numbers once again are (1) 800-475-6701 or 320-365-3844 with the access code 426562. That does conclude your conference for today. Thank you for your participation and for using AT&T Executive Teleconference. You may now disconnect.

Duration: 45 minutes

Call participants:

John Mayer -- Director, Investor Relations

Chris Kendall -- Director, President and Chief Executive Officer

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

Charles Meade -- Johnson Rice & Company -- Analyst

Joe Beninati -- Oppenheimer -- Analyst

Jacob Alexander Gomolinski-Ekel -- Morgan Stanley -- Analyst

Eric Seeve -- GoldenTree -- Analyst

David Meats -- Morningstar Inc. -- Analyst

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