Document

Communications herein do not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval with respect to the proposed transaction or otherwise, nor shall there be any sale of securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. Communication herein do not constitute a notice of redemption with respect to or an offer to purchase or sell (or the solicitation of an offer to purchase or sell) any preferred stock of Carrizo Oil & Gas, Inc.

In connection with the proposed transaction, Callon has filed, and the SEC has declared effective, a registration statement on Form S-4 (the “Registration Statement”), which contains a joint proxy statement of Callon and Carrizo that also constitutes a prospectus of Callon. This communication is not a substitute for the joint proxy statement/prospectus or the Registration Statement or for any other document that Callon or Carrizo may file with the SEC and/or send to Callon’s shareholders and/or Carrizo’s shareholders in connection with the proposed transaction. INVESTORS AND SECURITY HOLDERS OF CALLON AND CARRIZO ARE URGED TO READ THE REGISTRATION STATEMENT AND JOINT PROXY STATEMENT/PROSPECTUS, AS EACH MAY BE AMENDED OR SUPPLEMENTED FROM TIME TO TIME, AND OTHER RELEVANT DOCUMENTS FILED BY CALLON AND CARRIZO WITH THE SEC CAREFULLY WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT CALLON, CARRIZO AND THE PROPOSED TRANSACTION.

Investors will be able to obtain free copies of the Registration Statement and joint proxy statement/prospectus, as each may be amended from time to time, and other relevant documents filed by Callon and Carrizo with the SEC (when they become available) through the website maintained by the SEC at www.sec.gov. Copies of documents filed with the SEC by Callon will be available free of charge from Callon’s website at www.callon.com under the “Investors” tab or by contacting Callon’s Investor Relations Department at (281) 589-5200 or IR@callon.com. Copies of documents filed with the SEC by Carrizo will be available free of charge from Carrizo’s website at www.carrizo.com under the “Investor Relations” tab or by contacting Carrizo’s Investor Relations Department at (713) 328-1055 or IR@carrizo.com.

Callon, Carrizo and their respective directors and certain of their executive officers and other members of management and employees may be deemed, under SEC rules, to be participants in the solicitation of proxies from Callon’s shareholders and Carrizo’s shareholders in connection with the proposed transaction. Information regarding the executive officers and directors of Callon is included in its definitive proxy statement for its 2019 annual meeting filed with the SEC on March 27, 2019. Information regarding the executive officers and directors of Carrizo is included in its definitive proxy statement for its 2019 annual meeting filed with the SEC on April 2, 2019. Additional information regarding the persons who may be deemed participants and their direct and indirect interests, by security holdings or otherwise, will be set forth in the Registration Statement and joint proxy statement/prospectus and other materials when they are filed with the SEC in connection with the proposed transaction. Free copies of these documents may be obtained as described in the paragraphs above.

Certain statements in this communication concerning the proposed transaction, including any statements regarding the expected timetable for completing the proposed Carrizo transaction, the results, effects, benefits and synergies of the proposed transaction, future opportunities for the combined company, future financial performance and condition, guidance and any other statements regarding Callon’s or Carrizo’s future expectations, beliefs, plans, objectives, financial conditions, assumptions or future events or performance that are not historical facts are “forward-looking” statements based on assumptions currently believed to be valid. Forward-looking statements are all statements other than statements of historical facts. The words “anticipate,” “believe,” “ensure,”

“expect,” “if,” “intend,” “estimate,” “probable,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “potential,” “may,” “might,” “anticipate,” “likely” “plan,” “positioned,” “strategy,” and similar expressions or other words of similar meaning, and the negatives thereof, are intended to identify forward-looking statements. The forward-looking statements are intended to be subject to the safe harbor provided by Section 27A of the Securities Act of 1933, Section 21E of the Securities Exchange Act of 1934 and the Private Securities Litigation Reform Act of 1995.

These forward-looking statements involve significant risks and uncertainties that could cause actual results to differ materially from those anticipated, including, but not limited to, failure to obtain the required votes of Callon’s shareholders or Carrizo’s shareholders to approve the transaction and related matters; whether any redemption of Carrizo’s preferred stock will be necessary or will occur prior to the closing of the transaction; the risk that a condition to closing of the proposed transaction may not be satisfied, that either party may terminate the merger agreement or that the closing of the proposed transaction might be delayed or not occur at all; potential adverse reactions or changes to business or employee relationships, including those resulting from the announcement or completion of the transaction; the diversion of management time on transaction-related issues; the ultimate timing, outcome and results of integrating the operations of Callon and Carrizo; the effects of the business combination of Callon and Carrizo, including the combined company’s future financial condition, results of operations, strategy and plans; the ability of the combined company to realize anticipated synergies in the timeframe expected or at all; changes in capital markets and the ability of the combined company to finance operations in the manner expected; regulatory approval of the transaction; the effects of commodity prices; and the risks of oil and gas activities. Expectations regarding business outlook, including changes in revenue, pricing, capital expenditures, cash flow generation, strategies for our operations, oil and natural gas market conditions, legal, economic and regulatory conditions, and environmental matters are only forecasts regarding these matters.

Additional factors that could cause results to differ materially from those described above can be found in Callon’s Annual Report on Form 10-K for the year ended December 31, 2018 and in its subsequent Quarterly Reports on Form 10-Q for the quarter ended March 31, 2019, and the quarter ended June 30, 2019, each of which is on file with the SEC and available from Callon’s website at www.callon.com under the “Investors” tab, and in other documents Callon files with the SEC, and in Carrizo’s Annual Report on Form 10-K for the year ended December 31, 2018 and in its subsequent Quarterly Reports on Form 10-Q for the quarter ended March 31, 2019, and the quarter ended June 30, 2019, each of which is on file with the SEC and available from Carrizo’s website at www.carrizo.com under the “Investor Relations” tab, and in other documents Carrizo files with the SEC.

All forward-looking statements speak only as of the date they are made and are based on information available at that time. Neither Callon nor Carrizo assumes any obligation to update forward-looking statements to reflect circumstances or events that occur after the date the forward-looking statements were made or to reflect the occurrence of unanticipated events except as required by federal securities laws. As forward-looking statements involve significant risks and uncertainties, caution should be exercised against placing undue reliance on such statements.

EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define EBITDA as net income (loss) before interest expense, income taxes, depreciation, depletion and amortization, asset retirement obligation accretion expense, (gains) losses on derivative instruments excluding net settled derivative instruments, impairment of oil and natural gas properties, non-cash equity based compensation and other operating expenses. Management believes EBITDA is useful because it allows it to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. EBITDA should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDA. Our presentation of EBITDA should not be construed as an inference that our results will be unaffected by unusual or non-recurring items.

Net Debt to Last Quarter Annualized (“LQA”) Adjusted EBITDA is a non-GAAP measure. The Company defines Net Debt to LQA Adjusted EBITDA as the sum of total long-term debt less unrestricted cash and cash equivalents (as determined under U.S. GAAP), divided by the Company’s current quarter annualized Adjusted EBITDA inclusive of pro-forma results from its disposition completed in the current period. The Company presents these metrics to help evaluate its capital structure, financial leverage, and

Free Cash Flow is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements to assess our liquidity. We define free cash flow as net cash provided by operating activities before changes in working capital less capital expenditures (inclusive of operational capital expenditures, seismic, leasehold and other expenditures, as well as capitalized general and administrative expense and capitalized interest expense). Management believes that free cash flow provides useful information in assessing the impact of our ability to generate cash flow in excess of capital requirements and to return cash to shareholders. Free cash flow should not be considered an alternative to net cash provided by operating activities or any other GAAP measures. We have not provided a reconciliation of projected free cash flow to projected net cash provided by operating activities and capital expenditures used in net cash provided by investing activities, the most comparable financial measures calculated in accordance with GAAP. We are unable to project net cash provided by operating activities for any future period because such metric includes the impact of changes in operating assets and liabilities related to the timing of cash receipts and disbursements that may not relate to the period in which the operating activities occurred. We are unable to project these timing differences with any reasonable degree of accuracy without unreasonable efforts such as predicting the timing of our and our customers' payments, with accuracy to a specific day, months in advance.

Before we begin, I'd like to remind everyone to review our cautionary statements, disclaimers and important disclosures included on slide 2 and 3 of today's presentation. We will make some forward-looking statements during today's call that refer to estimates and plans, as well as reference our previously announced acquisition of Carrizo Oil & Gas, Inc. Actual results could differ materially due to factors noted on these slides and in our periodic SEC filings. We'll also refer to some non-GAAP financial measures today which we believe help to facilitate comparisons across periods and with our peers. For any non-GAAP measures we reference, we provide a reconciliation to the nearest corresponding GAAP measure. You may find these reconciliations in the appendix to the presentation slides and in our earnings press release, both of which are available on our website. We incorporate those by reference for today's call.

Following our prepared remarks, we will open the call for Q&A. Please note that the topic for this call is our quarterly results, so we appreciate directing any questions on this call to the company's current and previous quarterly results and operational performance. We continue to firmly believe the announced merger with Carrizo is the right strategic move for Callon, but we will defer answering questions relating to the status of the transaction at this time. We are engaging extensively with our shareholders ahead of the special meeting vote on the merger with Carrizo and we look forward to having the opportunity to discuss issues in greater depth and address any questions during those conversations.

Thanks Mark, and we appreciate everyone joining us today. Yesterday afternoon, we released our third quarter results which demonstrated the strength of our operations and progression towards highly efficient scale development, thus producing tangible improvements in capital efficiency. We see unique opportunity to make additional gains in capital efficiency with our pending acquisition of Carrizo which will accelerate our timeline for sustainable free cash flow, improve returns on capital, and further our efforts to strengthen Callon's financial position. We are excited to hit the ground running on our integrated development plan and reap the benefits from the strategic combination of two talented teams and high-quality asset bases.

I'll start on page 4 by revisiting our introductory slide from our February outlook earlier this year. Entering 2019, our message was clear to investors. This year we’d focus on harvesting asset value through increased pad development and cycle time reductions. We would seek to optimize margins and increase our operational flexibility. Through thoughtful capital allocation, we would minimize outspend and moderate growth. And from the longer-term perspective, we would seek to balance the preservation of longer-term reinvestment opportunities with our near-term return profile. This approach would advance our goal to generate sustainable free cash flow from a model-driven by leading capital efficiency coupled with differentiated cash margins in a resilient growth profile supported by strong well productivity and a maturing decline profile. As we look back on our activity and accomplishments during 2019, we've stuck exactly to that road map. Our shift to scale program development while operating within reduced budget relative to 2018 has driven record levels of capital efficiency across the portfolio, as we've expanded our deployment of larger projects from the Midland Basin to the Delaware Basin earlier this year.

Our margins remain among the strongest in the industry and have been furthered by our success in reducing costs on acquired properties in the Delaware Basin and leveraging the infrastructure investments we've made in earlier years. In addition, the optimization of the portfolio through the sale of almost $300 million in assets year-to- date allows for the redemption of high cost preferred stock, reducing our cost to capital and simplifying our capital structure. We firmly believe that the strategic combination of Callon and Carrizo will meaningfully increase the impact of these initiatives through an increased critical mass of development activity and infrastructure in the Delaware Basin, operating in corporate cost reductions and an expanded set of asset optimization and rationalization opportunities. In sum, we will be a stronger company with an advantage cost to supply to improve our competitive position as the unconventional oil and gas business matures. We've honored our promises and delivered exceptional performance as a result. As we look forward to 2020, the opportunities for shareholder value creation are expanded greatly as we continue to execute our strategy across a larger asset base and unlock the benefits of thoughtful, scaled operations.

Thanks, Joe. Execution during the third quarter continued to exceed expectations with our capital efficiency benefiting from two significant large pad developments, one each in the Delaware and Midland basins. We saw lower operating costs as the optimization project that we kicked off in the first quarter of this year was completed during the early portion of the third quarter.

We also saw additional benefits from the increased utilization of our recycling facilities and changes to our chemical treatment programs. Alongside these operational accomplishments, we continue to grow production per share and lower our lease operating expense per share versus the same period of 2018, while maintaining robust operating margins. At the bottom of the slide, you can see that cost reduction efforts in both the Delaware and Midland basins benefited significantly from the execution of larger pad development projects.

We utilized a slightly more conservative choke methodology with this pad, which you can see in the upper right- hand chart. This is something we expect to employ more broadly with future concepts of this size in the Delaware. We believe that, while it slightly reduces the peak IP rates, it better manages pressures and results in better productivity for the wells from about six months through the end-of-the-life of the well.

It's important to understand that much of what we've been able to accomplish this year has come from the transition to a more optimal development methodology that derives benefits from greater scale and continuous deployment of drilling and completion teams to more concentrated projects. The efficiency gains have resulted in faster drilling cycle times and increased completion stages per day both of which save significant capital dollars. The less visible benefit to shareholders is the preservation of future drilling locations and approved project level returns as a result of optimal development timing, well design and leveraging of our infrastructure investments that we've done for the past few years.

Our methodical approach to hedging which we have consistently employed over time as allowed us to secure the great majority of our current oil production volumes in 2020 at very attractive prices with additional protection for our limited gas volumes as well. With recent spikes in the commodity we were able to act quickly and add some attractive positions in the fourth quarter of this year as well, which should come in handy given some of the market volatility as of late.

You can see in the table in the upper right portion of the slide that we have diversified our crude oil pricing through marketing and transport agreements that provide us the opportunity to better control physical movements and improve realizations in an increasingly complex oil market. We will continue to evaluate opportunities like these across the entire commodity portfolio.

On slide 8, I think it's important to revisit the strategic financial objectives that we laid out for the market earlier this year. There were four key areas that we felt would advance value for shareholders as we saw progress in each relative area, and those were fairly straightforward. Number one, increase our cash flow - or excuse me, our cash return on invested capital. Number two, begin generating free cash flow. Three, reduce our leverage. And four, focus on long-term sustainable returns.

Each of these critical points is well supported by our strategic acquisition of Carrizo and ultimately results in a more investable, credit-worthy and robust economic vehicle for shareholders of both companies. We will benefit from the stronger field level economics available from a more capital-efficient development plan, from shedding non-core assets, and unlocking additional value through other monetization along with accelerating absolute debt reduction while still retaining the scale necessary to receive the credit market benefits and lower our overall cost of capital for the company. We feel strongly that these benefits are what can make Callon a highly differentiated investment option amongst the current peer companies.

Turning to slide 9, there's good reason to believe that our team can execute this strategy and create those financial outcomes. We have exhibited a history of acquiring assets and employing our operational expertise to reduce costs, improve well results and create value for shareholders. With this particular transaction, we are already starting off with high quality assets in the Eagle Ford and Delaware which is part a broader program that will benefit from increased scale and can be optimized within a capital allocation program that utilizes SIMPOS consistently throughout the Delaware.

Data sharing and employing best practices will only further enhance well results, something that we have seen and the positive impact we have made on the acreage acquired in May of last year from the prior operator. We've already seen an uptick in wealth productivity as exhibited on the upper right-hand graph but more importantly, we have utilized our field level practices and high-quality infrastructure investments to drive down operating costs, resulting in much improved EBITAX margins versus the prior operator.

Thanks, Jim. In our previous presentations regarding the Carrizo acquisition we outlined many of the statistics on page 10 but I wanted to take the opportunity to reiterate just how differentiated our future is after the combination of these two companies. The doubling of the core Delaware footprint and combined total Permian inventory of high-quality locations that are well-suited for our mega pad development model, provide an enviable runway of opportunity for any Permian operator. We also more than double our production base while preserving a high oil content and a leading cash margin profile. In addition to supporting immediate free cash flow generation in 2020, this cash flow base will enable us to overlay large scale development in a more meaningful way especially in the Delaware basin. And benefit from the undeniable capital efficiencies that accompany repeated activities in

economies of scale and manufacturing mode. Sustained scale development will build upon itself over time and lead to a steadily improving free cash flow profile, driving a step-change in our ability to drive shareholder value from near-term leverage reduction, and other opportunities for capital returns in the future. And looking at the aggregation of these metrics and what it means for Callon as a commodity producer, our corporate break even has reduced from $55 on a standalone basis to $50 in 2020, with further improvement into 2021 as our development model matures.

I've talked through several benefits of our pending transaction and wanted to summarize how these are manifested in terms of real dollars and ultimately improve free cash flow generation. We've clearly identified $100 million to $230 million annual run rate cash synergies from two primary buckets. Cash G&A, which accounts for approximately one-third of that total amount, and the efficiencies generated from increased large project development with simultaneous operations in the Permian Basin which comprise the balance.

The cash G&A synergies alone represent over 25% of our current equity value, providing a solid base for immediate per share accretion. On top of that, we have a demonstrated capital - we have demonstrated capital efficiencies from larger projects sizes combined with reduced cycle times, starting with our Delaware program in 2020, and expanding to the broader Permian over time. This is an incremental $400 million of NPV, that’s not dependent on improvements in well productivity or the ability to lengthen laterals on a combined footprint. These opportunities are real as we have proven in prior acquisitions, as are benefits from shared water infrastructure and refinancing savings. But these aren't captured in our primary synergy buckets and provide upside to our estimates.

Slide 12 breaks out the operational synergies in more detail. The key takeaways here are clear. Our base level synergies are not about direct acreage overlap. While you do need contiguous footprints to overlay scale development and leverage centralized infrastructure, which both of our companies possess in the combined Delaware business, we're unlocking incremental value from an expanded capital program that reaches the critical mass to run multiple rigs and frac crews on a sustained, repeatable basis.

After similar projects in the Midland Basin over the last several quarters, we demonstrate the D&C capital savings component in our recent Rag Run project in the Delaware Basin that developed six wells using two frac crews in simultaneous operation, a decrease of over 15% per lateral foot from where we started the year. This is relative to the 5% to 8% level we needed to hit our target operational synergies for this bucket of savings. Another key benefit is reduced production downtime with more wells drilled as parents in larger project sizes, future production disruptions from offsetting frac operations are eliminated and revenue isn't deferred. The key to our future and that of our industry's developing organizations that have the operational flexibility and financial strength to manage commodity price volatility and generate consistent results over time. Our pending combination with Carrizo more than doubles our proved reserves and production base and provides a the tremendous amount of operational flexibility on a footprint of 200,000 net acres and two premier shale plays.

On slide 13, we've highlighted the elements of our resulting financial strength. The clear advantages of being a larger, stronger entity have already been recognized by the credit agencies in their recent comments. We've also provided some comparative credit statistics in the appendix that illustrate the improvements in our credit profile. We are combining entities with similar leverage metrics as we stand here today and clearing a path for meaningful pro forma improvement on that front through absolute debt reduction driven by dramatically improved free cash flow profile. With this improved credit outlook, we will have the ability to improve our cost of capital through opportunistic refinancing.

I'll finish up by turning to slide 14. To summarize, we have continued to execute the plan we provided to investors at the outset of the year. Callon has evolved over the past few years from a prudent acquirer of top tier acreage positions to a capital efficient operator that can effectively turn those top tier assets into cash flow and corporate level returns. We understand that to compete with other investable opportunities both within and outside our sector we must create durable returns that exceed our cost of capital. To that end, we have taken action to optimize our capital structure, protect our cash flows from commodity fluctuations and continue to proactively align our executive compensation programs with investor focus areas as our company matures.

We've been clear in our strategy and our focus as evidenced by several examples on this page. We've also been clear over the last two years that consolidation was coming and we were going to evaluate our options from a position of strength to maximize shareholder value. Our board and management team firmly believes that our pending acquisition advances all of our stated objectives

and positions Callon as a stronger company for the future We also believe that shareholders recognize that the Carrizo transaction represents a unique opportunity to unlock additional value from our Permian asset base and improve our all-in cost of supply as a commodity producer. Despite a challenged equity market’s sentiment, that this casts a negative shadow on our industry, we ask all of you, our shareholders, to acknowledge the compelling strategic logic of this transaction and vote your support in the coming days.

Question - Neil Dingmann: Morning all, good color. Joe, just looking at that slide 6, particularly the bottom right there that shows the Midland large pad outperformance. Given the continued outperformance you're seeing, I see that Wolfcamp 7 well pad as well as the 5, really what's interesting is the outperformance versus the parent-child offset. Could you talk about maybe multi-zone pads and kind of what size pads you're targeting there?

Answer - Jeffrey S. Balmer, PHD: Yeah. One of the nice things about that is that was a multi-zone pad, so there was a three-well development kind of on the left-hand side of the section with a four-well development on the right-hand of the section. Each bucket of those, the three and the four, had an existing well drilled back in 2015, if memory serves me correctly.

And those parent wells are in the primary zone of the Wolfcamp A. So, we offset two wells off of that primary zone and then also went above it to the Lower Spraberry. And so, you see a multi-zone stack development program that's more efficient, and eliminates the use or the creation of future child wells. We did do a little bit of a different completion design on them where the interior wells were a little softer in their design, a little bit less water. So, we wouldn't negatively affect the existing parent well and then kind of got after the wells on the outside.

Answer - Jeffrey S. Balmer, PHD: Sure. We - the main thing that we're trying to do is just maintain focus. I really do like the progress that the team has made throughout 2019. There's a whole number of things that have contributed to our performance, and I think these are - without going into a specific detail on any of them, the things that we've done very well we can continue to do better. So, whether it is - we mentioned the chemical program with getting improvements on it ESP run time, so our submersible pumps, the longer that they're in the wells and the better that they perform, the lower the cost is from having to go in and pull those. We've had fewer work overs on our historic vertical wells which are tending to be the lower producers but are still reasonably costly to go in and work over and pull the tubing. We've performed items on power reliability with the two substations that we put in play, one in the Delaware Basin and then one in Howard County. That gives us repeatable cheap power especially when there's fluctuations due to weather or from the overall service company that's providing that. So, those are the focus areas for us going forward to continue to hit the high-ticket items. And we continue to see opportunities while I'm still very proud of what we've accomplished so far this year.

Question - Gabriel J. Daoud: Hey, good morning, everyone. I guess starting with the rig cadence on the Cowen legacy footprint you have four rigs today and I think for 2020 you’re anticipating picking up a couple. Could you maybe just talk about timing on those rig additions and if depending on when you add them and just the cadence today if that's enough to grow volume sequentially in 1Q 2020?

Answer - Joseph C. Gatto: Yeah. And we've provided some guidance Gabe around our combined 2020 profile that still stands out there in terms of target production growth over the next couple of years, what that means for free cash flow. So, while we had previously provided some guidance around Callon on a stand-alone basis early in the year, we obviously have an integrated plan that we'll be putting in place towards the end of this year. So, it's not really an apples-to- apples discussion.

Question - Gabriel J. Daoud: Okay. Got it, Joe. Thanks. And then just a follow-up, I guess it's back to the Howard County, two-coal development projects. Can you just remind us of both the 7- and the 5-well projects or space at 10 wells per section in the Wolfcamp A? And then overall, how you think about spacing in Howard amongst the three zones, the Wolfcamp A, the B and the Lower Spraberry?

Answer - Jeffrey S. Balmer, PHD: Sure. The wells spacing was a little tighter than 660 on these, but not in full development, which is a little unusual in that - in my mind you’d start with 660 and tend to be a little bit wider than that going forward, especially when you have an existing parent well. We - this is good rock and good geology. And I think in rare instances, you can close in and go a little bit tighter in certain circumstances. We took advantage of this. And I think you can see it in the early well results. However, in normal practice, when you're in a situation, where you have parent wells in place and you're trying to optimize the development program, that's probably a little tighter than you would want to go.

But a lot of it depends on the density of the well system that you're putting in, so every well matters. If you're in a stack development program, you’ll want to be thoughtful about that. But if you have great geology and you're really only targeting one zone and you're doing it all at first in a kind of virgin rock to maximize the recovery and the value of the well as you would contemplate going a little bit tighter.

Question - Derrick Whitfield: Perhaps for Jeff, from a bigger picture perspective, I know you have experience with large scale development based on your time at Encana. If I recall correctly, the Rag Run represents one of the first set of Callon wells was controlled flow back. Do you have a view on the potential EUR uplift associated with controlled flow back in general? And separately, is this a concept that would apply in the Midland Basin?

Answer - Jeffrey S. Balmer, PHD: Yeah. That's a great question. I do believe that there's a lot of things that roll into the EUR, the question in there. Generally speaking, what our data would suggest is you get a crossover at about six months, so that the slower back or more conservative choke methodology, while by the way also, it decreases the erosional degradation of sand cutting

It does provide an opportunity for greater EUR, post kind of the six months. What that number is, I don't have a clear vision of that. It's fairly substantial, the data would suggest as you go through time. But I don't want to apply a percentage to it at this point in time. There are applications within the Midland Basin, it tends to be lower pressure and your water effects have a little bit more of a strong effect on the preliminary flowback. So within the Midland Basin, for instance, if you put a lot of water into the system, generally speaking you're going to want to try to remove that a little more quickly than you would in the Delaware, which already has a lot of water in it. So, while there definitely could be some benefits within the Midland Basin, it really depends on the fluid system that you're in, how much depletion and voidage has already occurred within that system from the existing parent wells, and then what your design is. If you’ve put a lot of water into a system, you’ll want to, roughly speaking, remove it a little more quickly because it's a lower pressure system.

Answer - Jeffrey S. Balmer, PHD: I'm just catching up with you - there's a number of things to think about it from a design change perspective. What we're trying to do is look at what we think is going to give us the best well for the least amount of money. And when we can go in and make changes to the design profile, whether it's our stage length, the number of perf clusters per stage, the type of sand we're using, the volumes of how much water we're putting down on a barrels-per-minute standpoint - all of that, utilizing some data analytics and modeling, we have a proprietary predictive model that's allowed us to have well performance that's amongst the best in the basin.

Question - Brian Downey: Good morning and thanks for taking the questions. One for perhaps Jeff or Joe, looking back at slide 5, clearly impressive reductions on well cost per foot as you transition into larger pads. I'm just wondering how should we think about further runway into 2020 on the well cost, whether that's on well design and efficiency or maybe if there's anything to capture on the service pricing side?

As you've seen and we had mentioned and highlighted a Midland Basin system where we had record-setting performance on the number of stages per day, and part of that is processes, part of that is consistent crews which is again a benefit of having a larger operation with the Callon and Carrizo merger gives us the opportunity to have both of those. But there is also some opportunity from - on the side of working with people who you get win-win situations with from a contractual standpoint, where if we're more efficient as a partnership, we both benefit from that.

Answer - Joseph C. Gatto: Yeah. And if you think about 2020, and like I said, we put out some directional guidance on that on a combined basis that was relatively a flat CapEx guide, adding together our 2019 program. It doesn't reflect any deflation in the market. It does not reflect continued improvement that Jeff had said. It does reflect, obviously, a structural change in our development that we benefit from a capital efficiency standpoint, but there are going to be more opportunities for us to drive down costs here as we move forward.

We've shown it in this quarter, and Carrizo's announcement last night, you should have seen that they highlighted that as well. So, you take a lot of momentum from the combined companies, put them together, you have best practices and then overlay a larger development model to even get incremental savings, it's pretty powerful and that's excluding any of the potential deflation.

Question - Brian Downey: Got it. That's helpful. And then as my follow-up, you touched on the spacing on the larger pads, but just curious has anything changed on your go-forward approach on codevelopment from a flow unit selection itself over time, particularly in the Delaware, is it still A's and B's for now or anything else you plan on adding to that stack?

Question - William Thompson: Hey. Good morning. Joe or Jeff, as it's been noted, the Rag Run D&C efficiencies are ahead of pro forma expectations despite this being your first Delaware mega-pad to--date. What specifically drove the outperformance? How repeatable is that and how much of the benefit came from cost inflation which has been a consistent theme so far this earning season?

Answer - Jeffrey S. Balmer: Sure. The cost inflation really wasn't a large component of it. Any time that we can do the same thing for a better deal, we're certainly going to take advantage of it. But really the well performance on the larger, the larger pads in this one specific it was a, it was a combination of having the repeatable crews, applying learnings both from the drilling and completion side, making design changes to the completion crews to make them more efficient, working process improvement. So, the physical movement of our operations on location were well coordinated with consistent crews and once you get running in that that set up it just builds on it on the day before everybody wants to do a little bit better. And really the group got in a wonderful groove regarding that.

Outside of just the D&C cost per foot we pick up the benefits of cycle times right to do a six-well pad with one frac crews or longer cash conversion cycle. So, that's a benefit outside of the incremental CapEx you can pick up but certainly the cycle times and that impact on returns and that will be highlighted on page 12 also in terms of the production profile, deploying more of the mega pad concept is going to reduce or eliminate the amount of children that you have to come back and frac and not good parent wells off line.

Question - William Thompson: That's helpful. Thank you. And then, it was mentioned the redemption of Callon's preferred stock reducing cost of capital and plans for opportunistic refinancing. Remind me, is it fair to assume that the priority would be to redeem Carrizo's preferred shares? Would that - would you look to use the revolver to refinance those? Any color there would be helpful. Thank you.

Answer - James P. Ulm: Sure. I think we've said from the beginning that the current intention is a voting agreement, and that to the extent that we're unable to get a voting agreement, we have plenty of capacity underneath a newly completed RBL. There's obviously cost of capital savings when you're using a little over 3% debt relative to the 8.875% of the preferred. But we've not changed our thinking in terms of where we stand on that right now.

Question - Duncan McIntosh: Hey. Good morning, Jeff. On slide 9, you highlight a pretty strong improvement on the Ward County acquisition. I was wondering if you could - are those co-developed wells and kind of what's in order the driver to that up with particularly on those assets? Is it targeting? Is it more in the engineering standpoint? Any color there would be good.

Answer - Joseph C. Gatto: And I think Jeff had addressed some of this a little earlier in terms of, there's been a lot of things that we've done differently. We've changed some completion designs, refine some targeting, the dataset that is represented by the previous operator average, I think it's about nine wells over four or five years. So, there was some tweaking going on. We were in a position given that the learnings that we had stepping into the Delaware in 2017, the overlay, what we've been - what we were learning because we were very focused on that area. So out of the box, we are over - able to overlay some learnings and then enhance that with some completion design tweaks. We've done some subsurface modeling that helped with some of the performance as well.