Jones Energy, Inc. (OTC:JONE) Q4 2018 Results Earnings Conference Call February 28, 2019 10:30 AM ET
Page Portas - Investor Relations
Carl Giesler - Chief Executive Officer
Kirk Goehring - COO
Thomas Hester - CFO
Ladies and gentlemen, thank you for standing by, and welcome to the Jones Energy 2018 Fourth Quarter and Full-Year Earnings Conference Call. The company’s news release announcing its results was circulated yesterday and is also available in the Investor Relations section of our website at www.jonesenergy.com. During the formal remarks, all participants will be in listen-only mode. [Operator Instructions]. As a reminder, this call is being recorded. The webcast replay and a downloadable audio file will be available shortly following the call through the Investor Relations section of the company’s website.
I would like to remind everyone that today’s conference call contains forward-looking statements. These statements are based on our current views, forecasts and assumptions, which we believe are reasonable. However, several factors could cause actual results to differ materially from what we discuss today. Additional information concerning certain risks and uncertainties relating to the company’s business prospects and results are available in the company’s filings with the SEC.
During the call, management will refer to certain non-GAAP financial measures. Reconciliation to these measures was provided in our 2018 fourth quarter and full-year earnings report released yesterday and will also be provided in our Form 10-K.
Participating with me on today’s call will be Mr. Carl Giesler, Chief Executive Officer of Jones Energy as well as other senior members of the management team. Today’s call will include formal remarks only.
I would now like to turn the call over to Carl Giesler. Carl?
Thank you, Page. Welcome and thank you for your interest in Jones Energy. Joining Page and I are Kirk Goehring, our COO; and Thomas Hester, our CFO.
Yesterday afternoon, we reported our fourth quarter and full-year 2018 financial and operating results, along with our year end 2018 proved results. Today, we will review those results, as well as our recent operations and go forward outlook and initiatives.
Upfront, so, let us address our ongoing liability management assets. As a result of current market conditions, we believe we will require a significant restructuring of our balance sheet. As previously disclosed, the company and its advisors have been engaged in discussions with certain holders of our first lien senior unsecured notes regarding a potential transaction addressing the company's debt and equity. Those discussions remain ongoing. We will provide updates on these efforts, as appropriate.
Still fluid circumstances limit what we can share, and accordingly as Page noted, we will not entertain questions on today's call.
During our ongoing liability management process, we are committed to running the business responsibly, both in safety and economic terms. We recognize the risks and challenges that an over levered the balance sheet can impose on the business, and we're taking steps to limit the impacts through operating team and partners to continue to execute at a high level and drive value.
We anticipate seamless continuity in our operations with no significant impact to our employees, vendor and regulatory partners.
Thomas will now quickly review our financial and operating results.
Thanks, Carl. The company reported fourth quarter and full-year losses attributable to common shareholders of $1.2 billion and $1.3 billion, respectively. These losses were primarily due to non-cash pre-tax impairment charges of $1.3 billion to proved oil and gas properties. This significant impairment was driven predominately by prolonged period of low commodity prices and our current uncertain capital position.
Adjusted non-GAAP earnings for the quarter and full year were net losses attributable to common shareholders of 99 million and 174 million respectively. EBITDAX for the quarter and full year were 17 million and 94 million, respectively. Including realized hedge losses for the periods EBITDAX would have been 30 million and 145 million respectively.
Turning to CapEx our fourth quarter CapEx was $38.5 million at the low end of the $38 million to $43 million guidance we provided in October, about $30 million of that CapEx was related to drilling and completions, of which only $1 million was related to non-op activity. The remainder was primarily related to leasing and workover activity.
Catch-up pooling elections from wells drilled in prior periods had a more modest impact on our fourth quarter CapEx than it had on our third quarter CapEx. We believe that catch-up pooling elections during elections will continue to be a less significant driver of our CapEx going forward.
Now shifting to production. Company exceeded guidance across all three product streams. Fourth quarter 2018 production averaged 22.1 MBoe per day, 11% above the midpoint guidance, with oil 8% above, natural gas 13% above and NGLs 11% above. This outperformance was driven both with our base production which is benefiting from several months of our small ball program as well as from our fourth quarter development wells which meaningfully exceeded expectations. This strong production evidences the effect of the management structure and process improvements initiated during third quarter of 2018.
Yesterday, we issued first quarter 2019 production guidance of 18 to 20 MBoe per day. Anticipated decline from our 4Q ‘18 actual daily production reflects, in addition to natural PDP declines, recent non-core asset sales and the lack of any completions materially contributing first quarter numbers.
Our third Marmaton well in process at year end will likely come online late March. We will continue to issue production guidance on a prompt quarter basis until we have further clarity on our long-term development path.
On to reserves, the company year end 2018 proved reserves or 1P was 68 MMBoe, down significantly from 105 MMBoe at year end 2017. Potentially all this reduction was in proved undeveloped or PUD reserves which fell 84% from 43 MMBoe a year ago to just 7 MMBoe.
Our uncertain capital position among other factors limits our ability to drill all technical PUD wells within the prescribed window, pushing those wells out to proved reserve category. Without these limitations we would've been able to book approximately 40 MMBoe, more PUDs, taking our year end 2018 1P reserves from 68 to 107 MMBoe.
Notably, our proved developed reserves at year end was 61 MMBoe, essentially flat to 62 MMBoe at year end 2017.
With SEC pricing of approximately $66 oil and $3 gas, our year end 2018 1P PV-10 was 570 million, down 9% from 627 million at year-end 2017. Without the capital and other limitations our year-end 2018 1P PV-10 would have been 715 million, up 14% year-over-year.
Kirk will review our recent operations now.
Thanks, Thomas. Our tightened focus and more disciplined teamwork is showing the company's results. Since October 1st we have placed five operated wells online. Collectively and individually, with one exception of the Western Anadarko Basin or WAB, they're performing well above high curve.
In the Merge after some inconsistent HBP drilling results in the first-half 2018, we have refocused on demonstrating reservoir capability. Our three wells in that basin since changing our operating structure and protocols have outperformed the respected type curves of 40%.
Specifically, our Marmaton well achieved a peak IP30 of 420 barrels of oil per day and 3.9 million cubic feet of gas per day, combined to just over 1,000 Boe per day. Our Margaret well achieved a peak IP30 of 675 barrels of oil per day and 2.4 million cubic feet of gas per day, also combining to over 1,000 BOE per day. Both wells were single section laterals.
Our Tomahawk well, our first long lateral in quite some time achieved a peak IP30 of 730 barrels of oil per day, and 5.8 million cubic feet of gas per day, combining to just over 1,700 Boe per day. Notably, these wells completed our HBP initiative in the Merge. Today, all of our operated Merge acreage is held by production.
In the WAB our new structure and protocols yielded similar success. We completed our second Marmaton well and it’s been in course. Our Malinda 1HR achieved a peak IP30 of 860 barrels of oil per day and 1.7 million cubic feet of gas per day. With gas rates still increasing, making it the second best Jones oil well ever drilled at this point in its life. We are now two for two with above expectation wells targeting the Marmaton formation in Ochiltree County.
While our optimism is tempered by the small two-well sample size, we are nonetheless excited as we believe these early results speak to the stacked pay potential throughout our WAB footprint.
In addition to our operated Marmaton success in Ochiltree County, we had a significant working interest in a strong non-op Marmaton well in Ellis County. We are excited about that development too as we have substantial operating running room in that area.
I previously talked that WAB small ball program continues to generate positive results. Perhaps most notably, we were able to acquire two saltwater disposal or SWD wells that will handle about 70% Jones disposal needs with an aggregate cost of less than that for drilling one SWD well, we expect a less than 12 month payback. Beyond the SWD wells we have implemented dewatering workover, refrac and automation initiatives that involve minimum capital and have similar high returns and sub 12-month paybacks.
Also in the WAB we are in the process of selling two small asset packages for approximately $11 million. These sales will allow sharpened focus as they will substantially clean up our footprint and lessen our administrative burden, factors with a high number of low working interest, margin economic, predominantly non-op wells in non-core areas away from our main operated positions.
Finally, we should note that we had no material health, safety or environmental issues during the quarter.
Turning to our go forward plan, we have implemented an operating strategy that preserves the company's organic and strategic value, growth potential and optionality. The strategy has five key elements.
The first element was installation in the third quarter of 2018, the management structure and operating protocols to optimize the productive impact of the development in a safe, efficient process-driven manner. The second element has been to prioritize our drilling locations based on empirically defined relative economic productivity trends, particularly in the Merge. Our development approach has evolved from purely geologic and geophysical-driven definitions of “top tier” to an expanded definition that also incorporates empirical data on relative cash returns that account for all relevant factors, cost, productivity and the relative pricing of the gas and liquids extracted.
We have seen the fruit of these first two elements through our strategy in our strong fourth quarter production as well as our recent well results.
The third element to our strategy is a more strictly return-centered capital allocation process. Regarding operated drilling and completion given sub $60 oil, as well as our current capital uncertainty, we plan to drill only wells that meet approximately 30% cash-on-cash return threshold, and provide exogenous benefits to the company. Accordingly, we will focus are operated D&C capital only on activity that preserves or extends the HBP and/or operated status of our top tier sections in the Merge or preserves our strategic format agreement with ExxonMobil in the WAB.
Additionally, in the Merge, as our other operators, we are looking to tactically use long lateral wells to block up further our operated position.
Regarding non-operated drilling and completion, we are pivoting from a just keep-the-footprint approach to a broader economic decision process. Including non-op maintenance and minimal leasing, we have budgeted 60 million CapEx for 2019.
The fourth element to our strategy is costs. On AFEs, we are, as I say, going Western, with rigorous bidding processes and more fit-for-rock, tailoring of the well and completion designs, et cetera. We expect these initiatives to reduce the AFE on our next Merge well by as much as 20% versus comparable wells drilled in fourth quarter 2018.
On G&A, we reduced our run rate non-liability management related cash G&A to just about $20 million compared to the $23.5 million that had been budgeted for 2018. We have assessed every position for relevance in our current situation and for those positions calibrated the skill set required and staffed accordingly.
We've been able to tap unused team capability, leveraging career motivations and drawing more broadly on institutional knowledge.
During 2018, we had about 30 departures, with about half of those replace and all but two of the replacements at lower cost. This new team is more pointedly incentivized and sharply focused. This dynamic is showing in our recent results.
Beyond personnel, we've implemented back-office small ball initiatives such as relinquishing the company's interest in a claim, and revisiting the scope of our tax, legal and insurance benefits and other consultants and running RFPs for those needs, We have a line of sight for further reductions such as more appropriately sized office space.
On LOE, we are working on ways to reduce the fixed nature of that cost by pilot testing well monitoring automation, among other initiatives.
The fifth and final element to our strategy is culture. We work to inculcate a focus on in language of cash returns throughout the organization from the field up. As we see it, yes, we are in the E&P business. At the bottom we are really in the cash generation business. Our entire organization needs to understand how cost and oil prices impact returns, so that knowledge of that dynamic can inform our decision-making not just in the board room but in the field.
We’re optimistic that our liability management process results in a more sustainable capital structure with expanded liquidity options. To the extent it does, we believe our returns focus will allow us to be flexible and opportunistic in pursuing consolidation opportunities in both of our current basins.
The culture of cash returns element helps inform the recent deployment of Kirk Goehring to COO. Kirk has had a leadership role in our operations for the last year plus. In late 2017, he led a team that implemented a new processes in our Cleveland development program driving a remarkable approximately 1.5 times uplift in results relative to prior year averages.
Kirk also was responsible for initiating our Marmaton development program in the first half of 2018, and more recently has played a central role in our improved Merge results.
In addition to these operating roles Kirk has been point on several of Jones' past acquisition and divestiture efforts. While he does not have an engineering background, perhaps more importantly, Kirk gets cash on cash returns. He is implementing operating processes and structural checks and balances ensuring the appropriate technical team constitution to drive returns in a safe manner.
In our view, there's been a recent market shift in how capital providers demand that E&P companies generate returns. Cash profitability, return on capital deployed, free cash flow generation, rather than production growth or prospective drilling inventory delineation is how E&P companies will be judged going forward.
We believe that the market today is demanding the returns need to be driven through ongoing operations, disciplined capital investment on new projects and production as post flipping acreage or incorporating inventory growth into IR presentations.
Kirk’s return focus coupled with his demonstrated operational leadership suits his paradigm well. The recent deployment of Thomas Hester to CFO requires less explanation. Thomas combines discipline and detail orientation with thoughtfulness and creativity. He has a deep transaction led background in finance and accounting. With few exceptions Thomas has forgotten more about Jones' financials and accounting than most know.
To our employees we thank you for the continued hard work, focus and perseverance. Your efforts show in our results. To our investor stakeholder community we appreciate your time for today's call and your continued patience with us during this transition. That includes our formal remarks. Operator, you may now bring this call to the close.
And that does conclude today's conference call. You may now disconnect.
End of Q&A