Q2 2019 Earnings Call
Greetings and welcome to eat Cuties corporations Q2 earnings conference call.
At this time all participants are in a listen only mode.
A question and answer session will follow the formal presentation.
If anyone should require operator assistance during the conference. Please press star zero on your telephone keypad.
As a reminder, this conference is being recorded.
I would now like to turn the conference over to your host Kyle Durham. Please go ahead Sir.
Good morning, and thank you for joining today's conference call.
With me today are John Mccartney chairman of the UTI.
Debbie Rice, President and Chief Executive Officer, Derek Rice member of our Evolution Committee, Jimmy Smith, Chief Financial Officer, Blue Jenkins Executive Vice President commercial business development, and safety and Gary Gould Chief operating officer.
The replay for today's call will be available for a seven day period, beginning this evening.
The telephone number for the replay is 20161 to 7415 with a confirmation code of 1368 507 zero.
The replay will be available for seven days on our website.
In a moment, John Toby Jimmy Sue and I will present, our prepared remarks. Following these remarks, we will take your questions you T. published a new investor presentation. This morning, and we will refer to certain slides during our prepared remarks.
I'd like to remind you that todays call may contain forward looking statements actual results and future events may differ possibly materially from those forward looking statements due to a variety of factors, including those described in today's press release and under risk factors in our Form 10-K for the year ended December 30, Onest 2018 as updated by our subsequent Form 10-Q 's, which will also be on file with the SEC and available on our web site.
Today's call May also contain certain non-GAAP financial measures. Please refer to this mornings press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures.
With that I'd like to turn the call over to John .
Thank you Kyle and good morning, everyone.
On behalf of the board I'd like to thank shareholders for entrusting us with the task of overseeing acuities transformation into a world class Energy company.
The shareholder vote was an overwhelming vote of confidence for the new direction, IDIQ UTI and I'm honored to serve as chairman of what I believe is one of the most capable diverse and dedicated set of directors in the energy space.
With more than 80% of the vote supporting the rice team nominees.
Shareholders have clearly expressed their desire for IEC UTI to become a leading edge data driven transparent and socially responsible energy company.
Cobiz transformation plan offers significant value to shareholders and the board is United in supporting and providing accountability for its execution.
Beginning immediately following the shareholders meeting we've had several meetings and updates at the board and committee level.
To facilitate a smooth transition into a new era for IEC UTI.
In the near term we will continue these efforts by collaborating with the evolution Committee and designing a compensation plan that best aligns our stated goals of lowering well costs, improving capital efficiency driving sustainable free cash flow per share.
And enhancing total shareholder return with an emphasis towards absolute return.
Finally, once we've made meaningful progress on the 100 day plan, we intend to engage with shareholders on a more proactive basis to enhance open communications accountability.
And transparency at the board level.
With that I will turn the call over to Toby Rice.
Our newly appointed President and CEO .
Thanks, John and thanks to everyone for joining us today.
I am humbled to have this opportunity to lead and transform.
Into a modern digitally enabled MP company that will create significant value for shareholders.
Leading the largest gas producer in the U.S comes with an inherent responsibility to do what's best for our employees and contractors are land owners, our shareholders and the environment without compromise.
I expect the turnaround that we are executing will lift the company to new heights as it relates to our overall corporate citizenship.
Before I continue I would like to take a moment to recognize and thank our employees.
UTI has undergone a lot of change in recent years, but I I am impressed with our employees enthusiasm and dedication to the company.
Their openness to our new plan is encouraging and their participation will be one of the most important factors in our near and long term success.
Getting back to my remarks, my team and I got to work immediately following the annual meeting and have made great progress and assessing the business.
We've had some quick wins, along the way, but I want to focus my remarks on sharing my vision for IEC UTI.
Let's first start with a snapshot of where it is today.
UTI is the largest gas producer in the US with 660000 core acres in southwestern PA, and Northern West, Virginia, and 64000 core acres in southeastern Ohio.
We believe UTI has a deep inventory of economic locations in the basin.
And with the right leadership and approach, we can deliver superior shareholder returns in any commodity price environment.
Unfortunately, UTI has not yet realize the potential of its asset base.
Throughout the proxy contest, we communicated to our fellow shareholders that we believed he cuties legacy performance was the result of four project planning due to underutilized technology and a disconnected organization.
And our first 72 hours on the job we were able to confirm our diagnosis was accurate.
The employees are working tirelessly tirelessly to improve current operations, but the organization has limited visibility on future development projects.
Planning in Appalachia is extremely difficult and perhaps more difficult than anywhere else in the lower 48.
Our plan is specifically designed to leverage technology to connect the entire organization to improve development planning.
Our well design development schedule planned 36 months in the future is the key to consistent operational execution that will drive lower well costs and more free cash flow.
Before I talk to the details of our plan, let's look at it at an example of that shows the importance of planning.
Please turn to slide five of the presentation, we posted this morning.
What we're looking at here are two sets of pads developed by equity in 2019.
The pads on the left represent a poorly planned development, Ron and on the right a well thought out development Ron.
The example gives us the opportunity to isolate the impact of planning on efficiency and cost.
Since the same drilling team develops both projects in the same service cost environment.
The development Ron on the left is clearly not an efficient setup.
The new wells were squeezed out the pads with multiple existing producing wells our drilling team was forced to use complex while geometries to avoid wellbore collisions, the fractured rock downhole pause mud losses, while drilling and the poorly planned wellhead layouts required time consuming rig maneuvers between wells.
These factors led to inefficient and costly operations.
Add in the fact that these wells had an average lateral length of less than 8000 feet and the result was a drilling costs of $325 per foot, which is 80% higher than our targeted cost.
Further because these new wells were offsetting producing wells approximately 30 million cubic feet of gas per day had to be shut in for an extended period of time, which contributed to equities legacy curtailment issue.
And finally because of parent child relationships. These newly drilled wells are expected to underperform, our type curve by 10% to 15% once they are brought online.
We just hit on many of these legacy issues.
Elevated costs curtailments in wells that underperformed type curves all explained by a poorly designed development project.
So what happens when this team has given a properly designed development project.
On the right side of the page, we're looking at 12 wells developed simultaneously from two adjacent pads.
This development was initially designed by Rice energy back in 2017 as part of what we call combo development.
This project is currently being drilled by MTT today by the same team that executed the development run on the left.
Through the first six wells DQ T has drilled at a rate of 1500 feet per day, a 50% improvement versus the previous Pat.
Drilling costs are trending to around $200 per foot, a 40% reduction in costs versus our prior example.
I'll pause here to make this clear.
When he cuties operational teams are given properly designed development projects. They are nearly at our targeted well cost goals, which for drilling are up $190 per foot.
With some additional leadership improved engineering practices and the right pad layout. These cost goals are well within reach.
Rounding out this development Ron because we plan. These wells so far in advance curtailment issues are minimized and we expect all 12 wells to perform at or above type curve once turned online.
This example is focused on drilling, but we are seeing the same thing on completions.
When our completion teams are given poor projects at the last minute their efficiencies are half of what they are and properly planned projects.
You May ask why would he qt developed a pat on the left.
The answer is simple.
Yes, he did not have a better location descend the rig and the teams were given orders and incentivize the hit production targets. Unfortunately less than 50% of E. Cuties future schedule is currently set up for efficient development as illustrated on the right.
This is why we are here.
Our jobs as leaders of this organization is to align the workforce to March towards these large scale development projects. So our operational teams can execute.
Our vision and path to well cost of $735 per foot ends when 80% of our development looks like what you see on the right. This is what we're simply calling the end state.
The end state is we're all planning tasks are completed at least 12 months before spud, giving our execution teams the opportunity to succeed every time, they step onto a pad to drill and complete a standardized well designed for the lowest possible cost on budget on schedule and for maximum value.
To give you a sense of how achievable. This is by the end of our time at Rice energy, we had definitive and detailed development planning three to five years into the future.
Combo development represented more than 80% of our planned activity.
That type of visibility becomes very powerful for decision, making particularly around capital allocation.
Planning further out in time also provides better provides for better oilfield service contracts lower well costs greater leverage for commercial arrangements ample freshwater pipe to the site for completion operations and sufficient midstream and downstream capacity for new production.
This is how we get well cost of $735 per foot and hit type curve for each and every pad.
I realize the sound simple it is not that said it is our job as leaders of this company to take complex complicated tasks, such as master planning and simplify them for our employees to execute.
Our first step towards the end state was the creation of our evolution Committee.
This committee is comprised of Gtts executive team as well as Danny Rice, Derek Rice and Kyle Durham.
The committee will serve as the primary liaison to the board with respect to the execution of the 100 day plan.
Under the oversight of the evolution Committee, we are going to transform.
To our plan to end state in three key areas.
First.
We're going to restructure the organization to be function based employees will have clear roles and priorities that facilitate efficient project planning and execution.
Over the last 130 years, you tease org structure has morphed into more than 50 departments that has led to a lack of accountability.
We will reorganize the business into 16 departments with rolls that better match, the lifecycle of a well.
Second.
We're going to bring new technology to this organization to foster the level of interest and departmental collaboration and real time decision, making that the end state requires.
The company currently operates in a very solid matter.
Data and workflows are trapped in E mails and each department is acting on Predetermine department goals, even when the goals of the organization may demand adjustments.
The solution here is to implement a digital work environment that has been customized to run in Appalachian MP business. This platform, which we used that rice energy with great success will break down silos and bring transparency to data and workflows to enable more value driven decisions.
Third we have high graded leadership, where needed to execute our vision.
I am happy to report that we have hired all eight evolution leaders mentioned during the campaign.
On the operational side, we've added a VP of operational planning to oversee proper planning and coordination of future development.
Our VP of asset performance to oversee management of the optimal well design for each of our operating areas.
A VP of drilling and a VP of completions to ensure well designs are consistently executed.
On the technology side, we've added a chief information officer, and the VP of digital technology to oversee the buildout of our key digital solutions and change the way we work.
On the organizational side, we've added a chief human resources officer to create a world class culture, and a director of evolution to ensure the transformation remains in compliance with established audit governance and risk controls.
These eight liters previously worked together in the same end state at Rice energy and are currently marching on the 100 day plan we outlined.
And finally, we will achieve the end state by properly aligning valuing and supporting our people.
If you tease employees are motivated and hard working but they have not been allowed to reach their full potential. In addition to the benefits of the operational technological and organizational changes I discussed earlier, we are to challenge our employees with proper goals recognize them in real time and alignment aligned them through incentives.
This will allow them to see how they contribute to the company's mission, achieving the end state and making it a better business for all of its stake holders.
I am committed to making each you'd see the best place to work in Pittsburgh and these steps will get us there.
Stepping back.
How long will it take before SGT is executing at well costs of $735 a foot.
As we've laid out in slide 10, we expect a gradual improvement in well costs as best practices are implemented and efficient development inefficient development is removed from the schedule.
Master planning takes time, but we expect our schedule to be predominantly combo development runs by mid 2020, which will lead to a step change in well costs to $735 per foot around that time.
With that I'd like to turn the call over to Jimmy suit to share our second quarter results.
Thanks, Terry and good morning, everyone. This morning, ATP reported second quarter 2019, net income of $126 million.
49 cents per share and adjusted net income from continuing operations of $22 million or nine cents per share compared to $34 million or 13 cents per share in the second quarter at 28.
For the quarter, we achieved 370 Bcf the sales volume.
In line with expectations and at the high end of our guidance range of 355 to 375 Bcf.
Excluding sales volumes related to the 2018 divestitures.
Sales volumes of natural gas oil and NGL increased 8% over prior year.
Second quarter 2019, adjusted operating revenues were approximately $958 million down 6% compared to the prior year as a result of weaker pricing, partly offset by the higher sales volume.
Average realized sales price for the quarter was $2.59 per Mcf.
22 cents below the average price in the second quarter 2018.
The decrease in average realized price was primarily due to a decrease in higher priced liquid sales and beating you up lift as a result of the 2018 divestitures.
And lower Nymex net of cash settled derivatives.
Total operating revenues for the quarter were approximately $1.3 billion up roughly 360 million as the second quarter of 2019 included $408 million of gains on derivatives not designated as hedges compared to a $54 million loss last year.
This reflects the increase in the fair market value of our non next swaps and options due to declines in forward prices during the quarter.
Now moving on to operating expenses.
Second quarter operating expenses were down approximately 5% as a 118 million dollar impairment charge recorded in the second quarter of 2018 and lower production expenses in 2019 as a result of the 2018 divestitures more than offset increases in SDN proxy costs and lease impairments in the period.
The increase in US DNA was a result of royalty and litigation reserves of $38 million recorded during the quarter.
The lease impairments, primarily relate to acreage exploration, mostly outside of our current development plan.
At the unit cost level second quarter 2019, total cash unit costs for two cents higher than the second quarter of 2018.
Of note ITC transmission cost per unit was 54 cents per Mcf.
Which was two cents higher than the second quarter of 2018, and three cents above the high end of our guidance range.
This increase was primarily due to higher unruly, Tennessee gas pipeline capacity.
As a reminder, we have unused capacity on this pipeline in northern Pennsylvania.
We typically either release this capacity to others.
Or depending on market conditions purchased gas to sell off the pipeline.
When released the cost of this capacity is netted against every lease revenue and net marketing services.
When we move gas on the pipeline, our das or third party gas the cost is reported in transmission expense.
We have increased our guidance range for transmission cost for the year to reflect our current expectation for the use of this capacity in 2019.
As noted above SDMA was impacted by royalty and litigation reserves this quarter.
Adjusting for these items SDMA was 13 cents per Mcf.
Which is within our annual guidance range.
Now moving to cash flow items second quarter, adjusted operating cash flow was $386 million compared to 529 million in 2018.
As noted in our press release second quarter, adjusted operating cash flow and adjusted free cash flow include the impact of approximately $38 million of royalty in litigation reserve and $22 million of proxy transaction and reorganization related expenses.
Excluding these two items.
Operating cash flow would have been 445 million and adjusted free cash flow would have been a negative 21 million, which is slightly better than the favorable end of the range that we provided in June .
Our second quarter capital expenditures of $466 million or better than internal expectations for the quarter, primarily due to continued efficiency gains.
Looking forward, we are guiding to third quarter volumes at 365 to 385 Bcf at an average differential of negative 55 cents to negative 35 cents.
And we reiterate our full year capital expenditure guidance of 1.825 to 1.925 billion.
From a timing perspective, we expect threeq capex to be slightly higher than fourth quarter.
With respect to free cash flow, we have updated our annual guidance for the strip price as of June Thirtyth.
At these prices, we anticipate adjusted free cash flow of $25 million to $125 million for the year.
With negative cash flow in the third quarter being offset by positive cash flow in the fourth quarter.
Lastly, I will briefly discuss our cash flow and liquidity position.
On May 31, Qt entered into a 1 billion dollar term loan agreement and use the proceeds to repay $700 million in senior notes that matured on June onest.
And to repay outstanding credit facility borrowings.
We ended the quarter with no funds drawn on our $2.5 billion revolver and approximately $30 million in cash.
This leaves our net debt at approximately 4.97 billion.
At this level, our net debt to trailing 12 month adjusted EBITDA leverage is at 2.1 times.
When reduced for the value of our investment in Equitrans midstream using quarter end pricing is 1.7 times.
With that I will pass the call to Kyle.
Thanks, Jimmy soon.
I've had a chance to get to know many of our investors over the last few months.
I'm currently a member of the evolution Committee and I'm working alongside the team to execute certain finance corporate development and Investor relations initiatives as well as helping form our general capital allocation strategy.
To help set expectations I would like to lay out our guidance plan for the next few months.
Jimmy to walk through some of the changes to 2019 guidance, but we are suspending our outlook in 2020 and beyond as we develop a revised plan.
We expect to come back to the street with longer term guidance in the next 60 to 90 days, but I will spend a few minutes, providing some directional color on where we expect things to shake out.
We will be taking a different approach to capital allocation to many of our peers.
In today's commodity price environment, there is a high bar to allocate capital to the drill bit, especially given the opportunity to improve our leverage profile and buyback stock at 10 year lows.
We believe LPG trades at a significant discount to its intrinsic value and while we recognize many MPS share. This trade today net asset value will always be an anchor for us to make the right capital allocation decisions.
Fortunately for shareholders equity also has the potential to generate substantial near term free cash flow per share even at current strip pricing and that will be our focus going forward.
As Tony mentioned in his comments in Q2 s legacy capital inefficiency was a function of four development planning.
Our near term strategy will be to remove high cost development from the schedule and focus our land permitting and planning teams to transform that development into a combo development run that we can drill in 12 to 24 months.
This disciplined approach to development has several benefits first the capital efficiency of our program improves because we are only deploying development dollars. When we know we can execute highly economic projects.
Second we generate more near term free cash flow that can be used to repay debt and buy back stock.
Third we put less near term supply on a soft gas market.
And lastly, we give our midstream service provider a chance to catch its breath and provide water and gathering services at the lowest cost possible greatly improving their capital efficiency and free cash flow.
The ultimate level of our development capital spend will be determined by the number of economic projects, we have to drill measured against the opportunity to buy back shares and achieve our leverage targets.
Production growth, if any will be an output of that decision not a target.
We will be driven by growing free cash flow per share, which we believe is the key to driving shareholder value.
In making these near term decisions, we have maximum flexibility as all ddgs rig contracts roll off by the end of the year and we have minimal long term commitments to other services, we will use that flexibility designed the most efficient program possible with services procured and a soft service cost environment.
Stepping back over the last three months the forward gas strip has weakened bringing significant pressure to the balance sheets of both public and private gas Liberty MPS.
There are approximately 75 rigs running in Appalachian today, and 50 in the Haynesville. We believe the vast majority of these rigs are sub economic at strip pricing.
The equity in gas markets are sending a clear message the operators to cut growth to maintenance levels and some will need to go further than that while we have started to see a pullback in activity more is needed to balance the market.
We believe the marginal cost of supply is well above strip and the market will work itself out over the long term that said all of our efforts are geared towards transforming you could see in the lowest cost operator in the basin to whether what could be a challenging 2020 and position the business for long term success when prices normalize.
Turning to the balance sheet in general our policy will be to target forward leverage of less than two times net debt to EBITDA at the lower of strip gas prices or $2.50.
Free cash flow and any potential divestiture proceeds will be used to achieve this leverage profile and any additional cash flow will largely be returned to shareholders via stock buybacks.
We are committed to the investment grade rating and believe access to low cost financing will be a strategic advantage over the next several years.
We believe this policy will allow us to maintain investment grade metrics and we look forward to engaging with the agencies over the coming months. After we have finalized our long term development plan.
One lever, we can pull to manage that as our retained interest in equitrans, which is worth approximately $900 million as of today.
While we are evaluating a divestiture it is not part of our immediate plans any potential exit will be done responsibly and we have several options at our disposal for now we are benefiting from the 10% dividend yield and see several positive catalyst for Equitrans as we transform UTI.
First while there may be a reduction in our volume forecast in the near to medium term, we expect that our ability to hand equitrans of fully big schedule. The plans combo development 12 to 36 months in advance will greatly reduce their capital needs and boost free cash flow.
We saw this happen in 2017 at Rice Midstream partners following rice Energy's upstream transformation and we expected to happen for Equitrans as early as 2020.
Second we are working together to simplify our services contracts, while we all recognize the gathering fees are on the high end of market. Our strategy allows for other levers to be pulled that will be a win win for both parties, including increasing utilization of fresh water systems and the construction of produced water disposal systems.
These opportunities should lower our overall cost mix, while providing incremental revenue sources for equitrans.
We have already engaged with macro trends management in both sides are thrilled to start working together to develop this world class resource and deliver gas to market at the lowest cost possible.
Regarding asset sales, we're in the process of reviewing all of these assets and we remain open to divesting acreage or production if it fits within our capital allocation framework of maximizing free cash flow per share and NAV.
To summarize we are taking a differentiated approach to capital allocation. We are in the process of rationalizing ABTS development schedule and we will come back to the street with revised long term outlook that reflects the potential of this world class asset while also respecting the current commodity price environment.
With that I'd like to open up the call for Q and a operator.
Thank you.
At this time, we'll be conducting a question and answer session.
If you would like to ask a question. Please press star one on your telephone keypad.
A confirmation tone will indicate your line is in the question queue.
You May press Star two if you would like to remove your question from the Q.
For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys.
Our first question today is from Holly Stewart of Scotia, Howard Weil. Please go ahead.
Good morning, gentlemen.
Me too.
Maybe just first touch on a few of the the midstream thing and Carl I think you hit on.
Certainly a couple of them seem to be some sentiment out there in the marketplace today around your commitment to NBP. So I was just hoping maybe you could sort of clearing the waters a little bit there.
Holly This is blue I'll take that one so a couple of things on MVP won we're confident that it will get built and we are utilizing the most recent.
Most likely scenario used by each train which is mid 2020 in terms of the conversation of you can we walk away would we get out there isn't a reasonable scenario in which we would walk away from that project without a massive penalty and so that's just not how we look at it this is not a reasonable outcome.
Okay.
That was what we thought but just wanted to clear that up.
Carl you mentioned some thoughts around the green shares maybe you could just provide a little bit of color I know theres.
Some timing issues with.
With that equity being public and and the files that have to be.
The forms that have to be filed if you decide to divest of that before a year. So you can maybe provide a little bit of color on on that process.
Yes, no. It's we're really focused on the business for now I think clearly that's a divestiture candidate for us over the longer term, but it's not part of the immediate plans.
We're not going to guide to any timing expectations around when that might happen.
Okay Thats, great and then maybe just one last one from me it looks like.
Moody's recently moves you down too.
Your outlook down from stable to negative.
Can we just talk there seems to be several maturity coming up in the next few years to Toby just wanted to kind of get your.
Your thoughts on how those maturities Eric address in sort of general.
General outlook.
On the leverage profile.
Sure. Yeah. This this is Kyle I'll take that one.
Yes, the the leverage targets again going to be below two times and when we say that we include our gas price assumption for that which to US is the lower of strip and $2.50 and I think that positions us very well.
From an investment grade rating metrics perspective in terms of the maturities dearnley. They are on our radar.
It's it's not something we're ignoring right now, but want to sort of improve the cost structure of the business before assessing that but it's certainly on our radar.
All right. Thanks Jay.
The next question is from Brian singer of Goldman Sachs. Please go ahead.
Thank you good morning.
In in your opening remarks, you mentioned you see the benefits of your plan maximized when you're planning 36 months in the future and I think you said when you complete the planning 12 months ahead of schedule.
Good.
In slide 10 at your expectation seems that you will see the greatest step change in value creation over the course of the second half of 2020.
Can you just add more color for what drives that step change in 2020, and then how lower commodity prices and lower activity could if at all impacted the scale you are trying to achieve.
Sure Brian This is Toby.
To.
When looking at our $735 per foot cost target I think it's important I understand there's really four main drivers behind us achieving that level. The first being operational efficiencies that we are able to achieve in the fields. How fast can we drill how many stages per day can we can we complete.
Feel very confident after looking at the teams that we are going to be able to achieve the operational efficiencies needed to hit that 735, a foot on the second thing we look at is the procurement.
And the oilfield service, we have some we have flexibility.
With our oilfield service contracts in place right now.
So we have.
We feel pretty good about our ability to to acquire the right services and at the right cost to achieve our cost targets. The third is is comes to well design and we are deploying our proven well design, we feel really confident.
And the cost to execute and the type curve that we will receive in the fourth thing we look at is our schedule.
And this is really where we are going to be doing a lot of the heavy lifting and is to get a schedule that allows for common development, starting with multiple wells per pad meeting on minimum horizontal well lengths.
And that's really where the focus is going to be I'd say the benefits you're going to get when you get the common development are going to be largely driven on the logistics front and also on bulk materials.
Procurement.
Yes, and just to just to jump and Ryan I think.
With respect to timing ill.
The biggest impediment to setting up combo development right is on the land and permitting side and so thats, where we will be focusing our resources and those realistically take about 12 months. This to set up and so thats why you see that step change in well cost on that that graphic on slide 10.
And so once those are set up and they start hitting the schedule, you'll really see the benefits and start to see 735 a foot.
Got it ended the benefits change.
If you're running at a lower activity level on that in response to come out of the lower commodity prices or you think the same the same per foot benefits can be achieved kind of regardless of regardless of activity.
Yes, we think we are going to be operating at a level of activity that allows us achieve economies of scale necessary to reach the 735 a foot.
Great. Thanks, and then just one follow up on the midstream discussion earlier, you highlighted within the existing contracts some opportunities that could potentially come up where you can to restructure and added and add new business can you just give us just a little bit more of a sense of what that could mean, either from a cost perspective or from a free cash flow perspective.
Yes sure. This is Kyle don't want to give any specific guidance with respect to rates reductions or anything like that but.
The new business for Equitrans that could be is expanding.
The utilization of the freshwater systems they are actually.
Largely built by Rice Midstream partners, a few years ago, and then obviously the water disposal options getting trucks off the road, allowing equitrans to build a system to move water.
Those are the incremental revenue sources that we think would offset any potential rate reduction on the midstream gathering side.
Thank you.
The next question is from room Jerome of JP Morgan. Please go ahead.
Yes, good morning.
Tobey Kyle the rice team had identified call it 500 million.
Of free cash flow uplift relative to Q2 prior plan.
Ill when implemented I was wondering if you could maybe help us walk through.
The $500 million that you previously cited between the DNC cost savings and other initiatives just trying to better understand.
How you get to that number.
Yes, sure so the $500 million, we talked about in the campaign I was a couple of things that we're driving driving.
I was getting to 500 million first being a assumed activity level.
And that activity level would would assume would assume that we were growing at 5%.
And the second being the cost difference between executing well costs at $1100 a foot or.
Compared to our $735 per foot target so.
Some things have changed obviously, the we are resetting expectations and coming up with.
Active in that amount of activity that is based on economic projects to develop so.
What we're really focused on it and want to be comparing ourselves against going forward in the future is going to be.
How close we are to our $735 per foot cost target.
Because that's irrespective of activity levels.
Okay fair enough and just a follow up.
You guys.
Expressed a strong commitment to the MVP pipeline, but just better at trying to understand.
Is if the project is delayed call. It past the mid year next year is there any recourse for four key.
In terms of the tolling agreements are the fees on that to just given that the project is.
Beyond its original timeline.
Yes. So this is blue around so the short answer is no. What we have is a contract that caps our rate based on time and based on cost and Thats, where we sit so if it happens to slide lets say its Q4 instead of Q2, so that wouldn't change anything.
We have plans in place to manage should that should that be the case and are prepared for that but no. The contract is fairly set at this point and we still expect as I mentioned that it will be completed and we don't have any financial incentive to walk away from that.
Great. Thanks, a lot.
The next question is from David Deckelbaum of Cowen and company. Please go ahead.
Hi, Thanks, guys, it's David from Cowen just and congrats coming back into the public fold guys.
Thanks.
I did want to ask you commented earlier thanks.
And then at the 2020 vision and beyond this is suspended for the time being.
When I think about half of the.
Half of the development programs moving forward right now are not set up optimally.
I know like in slide five where you highlighted hi, hey sort of.
Deal here and the game pad.
Versus something that was recently drilled.
No that wasn't necessarily just not seim ops. It was also a shorter laterals or perhaps the project that wouldn't be trialed I guess.
What percentage of projects that exists right now would you just not drill that are on the current schedule.
Yes, David this is Derek so.
We're currently going through the schedule and assessing good projects versus bad projects and obviously the bad projects, we would like to pull those from the schedule and I don't think it makes sense.
Drilling $1100 per foot type wells at this gas price environment, so before pulling those off of the schedule.
We're running those through the traps whenever you make any change to the scheduled there is a ripple effect, where do you send that rig is now going to the.
Propose site.
And so I think over the next call it 30 to 60 days.
We'll have a better assessment of what exactly we can pull up the schedule.
An ideal situation, we pull those four development projects off the schedule replace them with.
Correct projects that are planned appropriately.
Whether or not we can do that again thats just going to be part of the assessments from within the first few weeks we've identified some inefficiencies in the in the program and now we're just going to evaluate whether or not we can pull those through yes, I would just just just make one point I mean.
We've identified these projects and these are projects that can be improved and our job is to align the workforce and focus our resources to.
Make these projects more economic lengthen laterals add wells per pad see if we can make turned them into combos.
So we're not just taking stuff off the schedule, we are focusing resources to make them.
And stayed like.
Sure I mean, but given that can you affect those changes by the first half of next year and that drilling program or is this more a second half of 2000 program and you might just be willing to kind of lesser economics in the beginning of next year.
Yes, I think we're going to have a better understanding on timing.
If we get a little bit more time here I mean, it's been 10 days I think we've we've done a good job in identifying some of the issues now it's.
What's what's our confidence in being able to.
Align the scheduled to meet to meet our minimum development.
Criteria and that's something we'll we'll report back to you guys win.
When we have better better clarity on that.
In the future.
I appreciate that.
I think Carla Thank you remarked that the most difficult impediment.
To the future plan is sort of around land in permitting and I can kind of take 12 months to set that up.
I guess what else needs to be done on the midstream side and just in terms of facilities to be able to turn in that many wells in these locations I know you talked about the waters opportunity that's out there.
I guess logistically what needs to happen on the midstream side. So you can execute this plan.
Yes, I would say this is toby it does a couple of things outside Atlanta permanent rather long lead time items. As you identified is is gathering takeaway.
And having access to fresh water.
We have that be piped to locations.
So I mean, we're going through an analysis right now.
Understanding the.
Gathering systems and the capacity forecast combined with our schedule to make sure that everything is set up so we don't have.
We can minimize any curtailment issues and the same thing with a good schedule, we understand when we're going to be fracking.
We can pair that up with water needs and make sure that the midstream team can service our water needs.
When we need it when we need to complete. So this is the type of work. In addition to this theres theres. Another 40 constraints that we are maneuvering into our optimum schedule.
And this is the work that we're doing and we're we'll be looking forward to updating people.
When we have a more complete picture of what the development schedule look like in the future.
All right fair enough. Thank you guys best of luck.
Thanks.
The next question is from Michael Hall of Heikkinen Energy Advisors. Please go ahead.
Good morning, and welcome back to the.
To the public told.
Yes, just I guess I wanted to talk to a couple of the slides.
On slide five I was just thinking as you walk through that.
Obviously, there is some risk may be that the legacy the legacy activity will have kind of cannibalize the opportunity to move forward in a more.
In that kind of properly planned development case, how confident are you in.
In the past.
<unk> ability to move forward with that properly plan case and fully achieve that end state goal.
Yes, how much more work to think remains to be done in terms of understanding that.
The potential impacts of legacy development on the ability to to optimize things going forward.
This is Toby real quick then I'll pass it over to Derek I would say that the thing that we're excited about is the fact that.
You know, we have such a large inventory of undeveloped.
Leasehold.
You look at where we're going to be focusing our development in southern Green.
There's not a lot of producing wells, we have to dance around so our inventory is pretty version.
And so but it does take work to get that to get that leasehold ready to develop and that's where we're going to be focusing our teams.
Any other color you want to add on that there.
Yes, I mean, just want them and just looking at the asset base and this is what gets us comfortable saying, we're going to get there is because the issues that we're seeing with you today.
To be Frank this is what we dealt with at Rice energy in 2014 and 2015, when we had the same vision. It's we know what end state we'd like to get to.
What are the steps needed to get there.
It's essentially the same asset base, primarily in Greene County in Washington County, a lot of the sites that we plan to develop going forward, our rice energy sites. So we have a clear picture of of what we need to do to get there and I think we've done it before and we think we can get there again.
All right makes sense and then I mean, sorry go ahead Jim.
No that was it.
Okay.
Yes in that context I guess.
Okay help a local west, Virginia, and think that theres quite a bit of potential for optimizing that land.
Position and.
And potentially helping build out that inventory into something more.
More ready for optimal development wells, what's the kind of game plan on that timelines and thought process as to when that will.
Kind of compete internally if you will.
Yes. This is toby.
Yes, so we are.
Working.
To develop west, Virginia, and make that drill ready and we have the resources. So were prepared were going to start preparing that right now.
The game plan is we've got a couple of years.
While we are focusing our development and Greene and Washington counties to get West, Virginia, ready, obviously, it's a little bit more challenging in west Virginia, just because terrain is a little bit more difficult make site selection.
A little bit harder.
And putting together contiguous leasehold position.
Is something that's important and with the fractured.
Lease lease position in West, Virginia makes a little bit more challenging, but I will say.
The IGI team does have some trades currently going on so we are focused on building contiguous leasehold position that will support combo development.
Okay.
Thanks, and then last one of mine is just if you had any sort of estimate yet for what you would think about it as a kind of breakeven gas price in the context of.
Driving corporate level free cash flow.
Going forward.
Yes, no let me.
Let us get back to you and 60 to 90 days.
And we'll be able to better run some sensitivities you can kind of see free cash flow at different price decks.
All right.
Thanks, very much guys.
Welcome back.
Thanks.
The next question is from Josh Silverstein of Wolfe Research. Please go ahead.
Yeah. Thanks, Good morning, guys just following up on some of the questions before.
There definitely seems to be.
Much bigger emphasis on free cash flow generation and over growth.
Are you guys willing to go to two maintenance mode or even decline as you are implementing the strategy.
Into next year.
Yes, Josh this is Toby I mean, I would say that the driver of activity levels is going to be.
The set up on economic projects that we have to develop.
So I mean, that's really where it all starts I mean, when you think about I mean, just bringing this business back to fundamentals and making investments in good projects.
And the the production growth targets with the production targets that we set are going to be the outcome of.
Fundamentally sound investment decisions on the drill bit.
Got you I mean, Ken I guess once once implemented assuming were in a 250 environment. Ken can you TTB the sub two times levered.
Grow, 5% and generate a significant amount of free cash flow.
At 250, Yeah, I mean, Josh I think it's realistic.
But.
Again it at 250, it's not really where we're going to be growing production volumes into that type of environment. So thats not really the scenario we're talking about.
But we'll get back to you. After we spent some time with the development schedule to really forecast this out and give you the granularity you need.
Got you okay.
I mean as the biggest gas producer out there certainly sitting tone around 250 would would help there.
And then just to understand you talked about this massive penalties potentially for getting out of the MVP pipeline can you put some context around that is it a $100 million is at $500 million like what is massive in terms of getting out of of MVP.
Yes, yes. This is Bluetooth the short answer is we're not going to walk from the project I think thats probably.
However, the short answer.
Fair enough.
The next question is from Jeffrey Campbell of Tuohy Brothers. Please go ahead.
Good morning.
My first question was that going back to slide five, but just looking at something else. There. It says that greater than 80% of the remaining inventory you can look like the good pad the illustrated.
I was just wondering is it reasonable to assume that some of that other less than 20% could either be sold or impaired.
Yes. This is Derek so the majority of that sort of.
Quarterly plan development that remain it's largely within equities.
Producing well footprint.
So very similar to.
What you're seeing on the left there.
Not exactly something that anybody wants to buy.
The way that we look at it is.
That's stuff that we'd like to develop in the year 2030, plus.
So as much as we can push that back you know that the better.
Yes, I mean in.
Yes, the developer has not set up for economic development today, but I mean gas prices change, that's where that stuff can can can make economic sense, but we're going to be disciplined to develop that when it when it does make sense.
Okay, and I guess it could also be a decision between because you can always so.
Producing reserves, but then if you sell them than it might raise your corporate decline rate. So there might be a reason to want to keep on just as part of.
A good base decline I mean is that reasonable as well.
Yes, that's correct.
Okay and I was wondering I thought this is really interesting in your earlier remarks I was wondering how much time do you think is going to be required to digitize you could see along the lines of the former rice energy because it sounds like it's not just a software shift, but it's actually a different way of working.
Thats enhanced by technology.
Yes, I think I think we think about digital transformation as sort of what we're going through I mean, it's it's not just bringing technology when organization, it's it's bringing a cultural change as well.
Do you think about what we're what we're going to be doing here with technology, it's going to bring massive transparency to the business.
People need to be comfortable with that type of transparency.
And.
What's exciting about that is once we have that transparency then we're going to start having the opportunity to start collaborating more and when people start collaborating them where to start having some more ideas and innovation is going to start bubbling up and if we can focus that innovation on the things that matter the bottlenecks and the opportunities within our business. Then we can start generating value for shareholders and Thats evolution and so it all starts with technology.
But it is it is really going to change the culture here at Q3, and we're excited about.
That opportunity going forward.
Okay and last question was I'm, just kind of structural I guess, you mentioned that the evolution Committee is the main liaison to the board of Directors I was just wondering how does the.
Evolution Committee interface with operational leaders to facilitate the changes that you enumerated.
Sure. So it's.
It's a transparent.
Plan that we're executing you know part of our when we talk about transforming cdti into a modern company what modern means to us is coming up with a good strategy and leveraging technology to execute to the strategy. In this case is our 100 day plan and the technology that we're implementing is in our digital work environment and that will be.
Available for all the employees to see the tasks that were doing.
To take us one step to take us closer to an evolved state.
We have.
The.
Thank you see executives are on this evolution committee, we have a feedback channel set up for employees to speak up and tell us what do they want to change what do they want to keep the same.
And.
These employees are speaking up we've got over 400 responses to this survey.
So we're currently assessing the feedback and implement in implementing that into our into our task list that we're doing so.
That's it everybody here is going to be engaged.
Okay, great. Thanks, I appreciate the color and best of luck.
Thanks.
The next question is from Jane Transco of Stifel. Please go ahead.
Good morning.
I have a question regarding dogs and how they fit into the current Oh, let's say future give out and plan.
I think that the data, although 200 docs in Marseilles and I'm just curious how do they compete versus let's say drilling new wells are using this compound you combine development.
Yeah, Jamie this is Toby.
So I think the way that we wrote that is just the way that weve categorized the 209 is wells that have been drilled in some some form or fashion I think 92 of those are actually drill to total depth. So that was what would be what we would call a true duck.
Okay.
So the other way, saying is is that you guys plan to conclude the existing 96 dogs right and.
I would say that we should expect that the sounds like you are just because they have been done using a below the old Dan approach right.
No I wouldn't I wouldn't say that that we would.
Change the the production that we said we're going to receive from these wells I mean, we've reaffirmed our production yet.
Production guidance for this year.
Okay, Okay, and then the remaining.
Although 100 docs those I, just kind of top hole I guess.
Yes, that's correct.
Okay got it and then I have a question for <unk> do you Miss you regarding this download a term loan agreement.
If you guys can kind of explain the logic for entering into this agreement for 1 billion.
And the term loan agreement you know.
We've been very clear that the proceeds from each year end state will be used to reduce our leverage but that we were gonna be disciplined about when we did that sale. We had a 700 dollar maturity coming up on our revolver and the term loan was available at rates lower than our room, I'm, sorry, seven and our maturity with long term bonds, we could have put it on the revolver, but the term loan was available and the interest rate on the term loan are lower than those on our current revolver.
Okay got it and the last question if I could a regarding the production mix I'm going for it a isn't going to remain roughly the same in terms of southwest, Pennsylvania, Ohio, and West Virginia completions.
Yes. This is Kyle I think it'll be similar for the rest of the year.
As we've outlined I think it's possible as we go through this review that we have a little more activity focused and Washington, and Greene County, Pennsylvania, and a little less in West Virginia, as we're putting that land position together to set it up for combo development. So it's possible in 2020, maybe 2021, you see a little more.
In Pennsylvania than West, Virginia, then and then 2019.
Thanks, a lot guys.
The next question is from drew Venker of Morgan Stanley . Please go ahead.
Hi, guys I just wanted to follow up on a question earlier about capex.
Thank you you had said Im sure you had said that through Capex, you expect to be a bit higher than two Q, but did I also hear you right in saying that you would likely be slowing down DNC spending in the near term.
No I think we well we reaffirmed our capex guidance for the year I think what I said was if you take what we spent year to date you look at the midpoint of the guidance and if you want to try to get the cadence of that third quarter fourth quarter third quarter will be higher than the fourth quarter.
Okay.
And I guess one for for Tobey is.
On the land spending as you guys are spending more time, there and on permitting.
Do you think the lower land spending rate at least per year is still a realistic goal from <unk>.
$200 million a year, so that he could he had been running out.
Yeah, So I mean I think.
The way, we look at land, we've got a large asset base.
And one of the things that we're going to bring to this organization is focused and that operation schedule that we put out is going to allow our land teams to focus.
Their resources on preparing for that operation schedule.
So so this is part of the understanding what are what are.
The land spend that we need is is going to be some that were focusing our assessment on right now.
And have better color for you in the future when we get through that assessment.
Okay. Thanks for that Debbie one one on the midstream contracts as well.
Do you expect to start negotiations to amend extend those I think it particularly gathering contracts. It sounds like you guys already had some conversations with the folks at him.
Yes, no. We're just continuing the discussions that had started earlier this year.
And so yes, we're.
We're excited about working with them and excited about handing them you know a fully baked development schedule to make their lives easier. So.
Well, we'll keep the group updated on how things go.
Okay. Thanks, one last one could you just tell us a bit about the happiness campaign.
Yeah, you know.
The whole point here is where we are we want to do two things we want to create great results for shareholders and we want to create a great working environment for our employees and I believe that those two things go together.
And part of Us being.
Creating a great work environment for our employees is having a happy workforce.
And we believe the keys behind driving happy employees is creating employees that are increasing there are that are productive employees that are challenged recognized and have fun at work.
Fortunately our plan everything that we talk about focusing and aligning our employees on the things that matter that fits largely into making our employees more productive challenging I think we were doing were asking employees to.
Hit some goals that that I think would be optimistic from where they're at today, but as we've shown they have that they have the capability of doing it so we're going to be challenging the employees.
And then the digital work environment. The transparency that's going to bring is also going to bring allow us as leaders and managers of this business to recognize the performance of the employees and then the last part having fun at work.
Really what we're going to be focusing on there is winning and winning is setting goals and hitting goals.
And that's going to be that that's going to be the fund that we have is by doing those things. So that's that's that in a nutshell.
Like the idea thanks Toby.
The next question is from Welles Fitzpatrick of Suntrust. Please go ahead.
Hey, good morning, Thanks for all the detail on getting costs down the efficiencies in midstream, but can you can you talk a little bit more to how much would there is to chop on on the drilling and completion contracts and is it fair to assume that those legacy contracts generally roll off in 2020.
Yes. This is this is toby so the drilling contracts the horizontal rigs are rolling off by the end of this year.
The Frac crews we have are currently rolling month to month with our with our.
Frac suppliers. So we're looking to continue relationships we have.
And also making sure that we're acquiring services at the costs that we need to hit our hit our targets.
We are after seeing that where we were we were one of the things I was pleased to see is that we have the flexibility.
And don't see procurement as an impediment to us reaching our 735.
Cost per foot goal.
Okay Perfect and then just one follow up on the G and H side I guess, it's fair to assume it will be a little bit choppy through year end as you're bringing in new people and whatnot do you see do you expect that to stabilize pretty early in 2020 or even later this year.
Yes, we would.
We're planning to continue to go through our assessments of the departments right now, but we know we're looking for.
And we would expect that to be through that through 19 for sure.
Perfect. That's all I have congrats on congrats on getting back at it.
Thanks.
The next question is from some Meritage Wanni of Tudor Pickering Holt. Please go ahead.
Hey, guys good morning.
First off on Capex I wanted to see if it's possible to realize some of the savings in 2019 as you as you try to high grade the program or are we just too far along for that to be meaningful at this point.
Yes. So this is Derek so I mean I'll be honest in the first two weeks.
Our primary focus has been to stabilize the business, we've largely been in listen only mode.
I will say there has been a couple of things we've come across that we felt as though we need to change in the near term.
One thing on the completion design front when you walk in the door.
They were 30 different completion designs, we look at all the data with the teams and we can't conclusion that.
Reducing that to one design one proven design was efficient.
What that allows us to do is not only predict to the performance of our wells going forward.
But it also gives our completions team the ability to to procure the appropriate amount of materials on a go forward basis.
On the drilling front.
We briefly looked at there.
Drilling parameters, we noticed there were some self imposed limitations.
Little bit technical I won't go into it.
We lifted those limitations and saw immediate gains in drilling performance.
To put some color on that the previous single day 24 hour rate.
In the second quarter was 6600 feet and a 24 hour period and just last week. This drilling team surpassed 7800 feet in a 24 hour period. So.
Again, largely in listen only mode for the first two weeks, but we think that as we get more hands on going forward, we will start seeing more efficiency gains and continued operational improvement.
Okay. Okay, that's good to hear.
And then next.
There was a question earlier about the potential to kind of move to a maintenance program next year I know you guys haven't decided icing yet but.
Would it be too early to ask you what a maintenance budget what look like next year kind of given that transition period, we are still going to be realizing some of the savings and how you expect a maintenance budget to look longer term once you're fully at that 735 profile.
Yes, let us start upon but we're going to have to get back to you on that after we go through our assessment.
Yes, yes, no worries and then.
I guess last question.
You talked a little bit about potential noncore asset sales wants to see if you had any interest in following one of your peers through just monetize some and our I mean I think historically Q2 has a has had a fairly high in our eyes. So just what are your thoughts on potentially taking advantage of the valuation spread between those assets and the equity today.
Yes. This is Kyle.
That's really not something we're evaluating currently.
Okay. Thanks.
Yeah.
The next question is from Betty Zhang of Credit Suisse. Please go ahead.
Good morning can you talk about the levers you have to reduce leverage leveraging the near term to get yourself. Two times. If you try to stake is not in the immediate plan, our noncore asset sales being prioritized as tools to de lever or maybe just give some color on where you guys consider to be non core.
Yeah, No I mean, like we said everything sort of on the table.
Obviously selling for just PDP PV 10 is a tough way to delever and there aren't a ton of buyers who want to buy noncore assets for more than that so asset sales are difficult way to de lever I think what we're looking at is delevering organically.
And then we do that by lowering well costs and rationalizing the development plan. So.
That that's kind of our path towards two times or less.
Got it and and just to clarify what's your view on balancing between debt reduction and share buyback and.
Is the goal to get to two times leverage first before you do buy back.
Yeah, that's correct Betty.
Got it okay, and lasting was a a potentially lower volumes on loss activity do you see reduce production constraint those loss estimate a roughly 10% of the current production.
Yeah.
Yeah the.
That that could be a result right.
We know the prior team characterized about 10% of the production base is curtailed.
After assessing that that's not really the way we are going to talk about it going forward.
But yes, any any potential curtailments would be alleviated by a reduced capital spend and less production volumes.
Great. Thank you.
That concludes the question and answer period, I will turn the call back over to Toby Rice for closing remarks.
Thanks, everyone for joining us we appreciate your support.
In this campaign and we are looking forward to continued continuing the work weve.
We've laid out and excited about sharing our progress with you in the future. Thank you.
This concludes today's conference you may now disconnect your lines. Thank you for your participation.