EXCO Resources (XCO) Harold L. Hickey on Q2 2016 Results - Earnings Call Transcript

| About: EXCO Resources, (XCO)

EXCO Resources, Inc. (NYSE:XCO)

Q2 2016 Earnings Call

August 03, 2016 10:00 am ET

Executives

Christopher C. Peracchi - Treasurer, VP-Finance & Head-Investor Relations

Harold L. Hickey - President & Chief Executive Officer

Harold H. Jameson - Chief Operating Officer

Richard Alan Burnett - VP, Chief Financial & Accounting Officer

Analysts

Tarek Hamid - JPMorgan Securities LLC

Sinan Kermen - Drw Securities, L.L.C.

Steven Marc Karpel - Credit Suisse Securities (NYSE:USA) LLC (Broker)

Operator

Good morning. My name is Carol, I will be your conference operator today. At this time, I would like to welcome everyone to the EXCO Resources' Second Quarter Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session.

I would now like to turn the call over Mr. Chris Peracchi, Vice President and Treasurer.

Christopher C. Peracchi - Treasurer, VP-Finance & Head-Investor Relations

Thank you, Carol. Good morning. Thank you for joining EXCO Resources' second quarter 2016 conference call.

Hal Hickey, Chief Executive Officer and President; Harold Jameson, Vice President and Chief Operating Officer; and Ricky Burnett, Vice President and Chief Financial Officer will provide our perspective on EXCO's results followed by Q&A session.

You can access our slides on our website excoresources.com, and we will refer to these during our remarks. Since many of our remarks today will concern our expectations for the future, they are subject to numerous risk factors as elaborated upon in our 10-K, 10-Q and other filings. These comments constitute forward-looking statements within the meanings of the Securities and Exchange Act.

Such forward-looking statements are subject to certain risks and uncertainties as disclosed by EXCO from time-to-time in its filings with the Securities and Exchange Commission. As a result of these factors, our actual results may differ materially from those indicated or implied by such forward-looking statements.

I will now turn the call over to Hal to begin.

Harold L. Hickey - President & Chief Executive Officer

Thanks, Chris. Good morning, and thanks for listening to our second quarter 2016 conference call. I'll discuss our continued efforts and progress on our strategic improvement plan, and our second quarter operational and financial highlights. I'll then turn the call over to Harold to review our operations and assets. Ricky will expand on our liquidity and financial results. And finally, given our tender and consent process, and discussions with gathering, marketing and transportation or GMT counterparties, we'll focus our Q&A session on second quarter operational items, and financial matters that are outside of the context of our ongoing restructuring efforts.

Reviewing the macro trends since our last call, Cal-17 natural gas prices had positive movement, and they're currently trading around $3.15. Above normal temperatures and gas rig counts hovering below 90 rigs have provided support for the curve. Some recent gas supply and demand data points are particularly compelling. Dry shale gas production has been on the decline since February.

Last week's injection was the smallest summer time weekly injection since August 2012. Consumption by electricity generators recently hit a record high above 40 Bcf per day. 20 ships have sailed from the first train at Sabine Pass, as American natural gas is being delivered into South America, the Middle East, Asia and Europe. Train 2 of the Sabine Pass terminal is expected to begin operations in September, with three additional trains coming online in 2017 through 2019, and four additional export terminals are currently under construction.

Finally, exports to Mexico continue to grow and multiple new pipeline projects are underway. The Cal-17 oil has essentially round tripped as the market has reacted to the U.S. oil rig count moving from 316 to 374. Ample global supplies exist, and we have a strengthening dollar. I don't believe, however, that anyone thinks $40 oil will be here long-term as the effects were felt from the massive cancelations of major oil projects across the globe.

Here at the company, we're working through the currently challenging market environment with our high quality asset base that has strong IRR projects. We have a low cost overhead, capital discipline, significant liquidity, continuous improvement drive and a very supportive board of directors and owners.

We remain focused on what we can control, including our balance sheet, organizational structure, cost, capital program, drilling completion designs, and non-core asset sales. But EXCO continues to face significant challenges, including our GMT costs, debt levels, and commodity prices. We're diligently working on these matters that we don't control including the success and timing around the consensual restructuring of our gathering and transportation contracts, noting the significant negative impact these contracts have on our cash flow, borrowing base and liquidity.

Until we reach resolution on these contracts, we must limit our capital expenditures as we continue executing on our strategic improvement plan, as outlined on slide two. You will note we delivered a 10% sequential improvement in adjusted EBITDA, while spending $80 million (05:21) on development capital expenditures. This spending level is down 40% quarter-to-quarter, and 70% compared to the second quarter of 2015.

We improved our debt structure in the second quarter by reducing our unsecured notes by $24 million, as we captured $90 million of discount. And we reduced the amount outstanding on our credit agreement by 8% quarter-on-quarter.

With our recently announced tender offer and consent offer, we expect to capture a significant amount of discount as we buy back more unsecured notes and importantly, revise the credit facility's definition to enhance our ability to raise secured capital, which is supported by our producing assets.

We're continuing our transformation of EXCO into a low cost producer as we rationalize both corporate and operational overhead. We reduced our LOE cost by 11% and G&A by 17% sequentially. On July 1, we sold our highest unit cost operation, selling our conventional assets in Pennsylvania. We reduced our original field head count by 52%, which will continue to improve our LOE cost. We retain rights to other formations below the conventional depths including the Marcellus and Utica Shales.

In North Louisiana, we achieved record low well cost, despite using approximately 2,700 pounds per lateral foot of proppant loading and we realized greater than 20 million cubic feet per day flow rates. Our ability to increase well deliverability efficiency and reduce operating cost has improved well economics across the portfolio.

Breakeven flat commodity prices where we achieve a 25% rate of return have been reduced to $2.19 in our core North Louisiana Haynesville, about $2.60 in East Texas Haynesville and to the mid-40s in South Texas for our oily projects.

We've executed a liquidity prioritization process for all capital spending as we measure our capital allocation decision to get liquidity intensity benchmarks. For example, in May, we sold some non-core undeveloped acreage in four wells in South Texas for nearly $12 million, and in turn, we redeployed that capital to higher rate of return opportunities to enhance our financial performance.

Another effort to highlight is our recent agreement with our JV partner in the Eagle Ford that provides us with additional flexibility in the development of our higher returning projects in this region and the elimination of the very complicated offer process. The world class institutional sponsorship at our streamlined board represents roughly half of our outstanding shares and holds a significant amount of our debt. We will continue to leverage the restructuring expertise in support of these investors to implement our restructuring programs to drive value for all stakeholders.

Slide three highlights the results of our balance sheet, focused liability management efforts that have improved our debt structure and provided structural liquidity. We've reduced our 2018 senior unsecured notes to $132 million, down $618 million or 82% from issuance. At June 30, we had $246 million of liquidity and we don't have any debt maturities until mid 2018. We remain focused on enhancing our liquidity runway and implementing our improvement plan and we're evaluating additional capital structure initiatives.

Slide four summarizes the gross gathering and transportation commitments in East Texas and North Louisiana. We have a significant amount of above-market rates and unused commitments and we're leading discussions to restructure these contracts. We strongly believe our gathering and transportation providers will prefer consensual solution, as opposed to having their non-competitive gathering and transportation contracts cancelled, which would occur in a more formal restructuring.

Our operating cash flows were insufficient to support both unused and out of market GMT contracts and payments to debt holders. As an example our Q2 EBITDA of $23 million is $6 million below our $29 million of payments to debt holders during the quarter.

Slide five highlights our ongoing focus on reducing LOE and corporate overhead. We've demonstrated consistent quarterly reductions with a 47% reduction in LOE since Q1 of 2015. Our team has done impressive work grinding these costs lower as we focused on enhancing employee productivity, and reducing cost across the organization.

Headcount reductions have been a component of our LOE and G&A savings, and over the past 18 months, we've increased productivity and efficiency by reducing our head count by 60%. However, excluding equity-based comp and severance, our annualized G&A run rate increased to $29 million due to higher professional fees. We expect to average a slightly higher number in the third quarters and fourth quarters due to incremental legal and advisory cost associated with our restructuring efforts and non-core asset sales. Excluding those costs, we forecast a $25 million G&A run rate.

Now, I'll turn the call over to Harold to review our operational successes.

Harold H. Jameson - Chief Operating Officer

Thanks, Hal.

Moving to slide six, we continue to demonstrate operational excellence as we improve our well performance and returns by increasing drilling and completion efficiencies and modifying fracture stimulation designs. The three wells that we turned to sales in the quarter have the largest stimulations and the lowest overall costs in the Haynesville in our history at an average of $5.8 million, approximately $900,000 below budget.

On panel one, our drilling performance in North Louisiana has continued to deliver results. The three yellow curves are standard lateral length wells that were the fastest three drilled in our history, averaging 25 days from spud to rig release, or six days faster than AFE. The three green curves are 7,500-foot long lateral wells that averaged 20,250 feet measured depth. One of these wells took longer to drill than planned due to multiple MWD failures and specific well geometries. We will be applying lessons learned on the next long wells we drilled in North Louisiana and are currently planning a 10,000-foot lateral in the future.

Panel two is a cumulative gas versus time plot comparing the well vintages in the Holly field. The blue curve represents standard lateral lengths and smaller completion size, the green curve highlights the impact of larger completions on standard lateral lengths, and the red curve is our most recent long lateral design with larger completions that have been online since late July.

The new long laterals are in the flow-back phase and initial gas rates and pressures are averaging approximately 21 million cubic feet per day with 7,900 psi flowing pressure. This is a step change in performance in the play and also the larger designs are positively impacting the original unit wells as you can see in panel three. This shows a 3x gas rate improvement and a 5x flowing pressure improvement on those existing wells. We're encouraged by this additional uplift, and we'll be managing the rate and pressure declines with our choke management process, just like we do with a new well.

Panel four summarizes the main points in our drilling and completions program in North Louisiana that are reenergizing our focus on this core asset. The larger stimulations are performing as evidenced by the cumulative gas versus time plot, the larger designs are having a positive impact on existing well performance, and our well construction cost to implement and deliver the wells are at record lows for the company. The new longer lateral wells with larger stimulations were the more efficient cost per foot developments that we've realized in the Haynesville play to date.

On slide seven, panel one provides an overview of our capital investments for 2016. We've cut CapEx 69% to preserve liquidity and defer developments. The recent settlement with our South Texas JV partner presents the opportunity to reengage in drilling high-quality Eagle Ford wells, and the current economic returns from drilling projects in our portfolio provide EXCO with sound investment options. When the rig and service markets improve, we expect to scale our operations and continue to realize non-price related capital efficiencies.

Now I'll turn the discussion over to Ricky for more details on our recent financial activity and results.

Richard Alan Burnett - VP, Chief Financial & Accounting Officer

Thank you, Harold. Turning to slide eight, which highlights our debt and liquidity profile. During the second quarter of 2016, our cash flows from operations, the reduction in our development program along with proceeds from the sale of non-core assets allowed us to reduce the principal amount of indebtedness by $35 million. This included an $11 million repayment of the revolver and $24 million in purchases of 2018's Notes and 2022 Notes be it for $5 million in cash. The pending tender offer will allow us to further reduce indebtedness at significant discounts to principal.

The purchases will be funded from borrowings under the revolver, which in turn will reduce our near-term liquidity. Deleveraging, as part of the consent and tender process, is a coordinated step in addressing our capital structure. As Hal noted earlier, we're currently in discussions with our gathering and transportation providers and view them as unsecured creditors. In light of the possible alternatives, we believe they should be highly incentivized to reach a deal that is mutually beneficial for both sides.

As Harold just spoke to in his comments, we are well positioned to create value through the drill bit if, and I want to stress if, we're in a position to secure capital after the restructuring of our gathering and transportation contracts.

Throughout this downturn, we continue to show we can do more with less. Our initiatives will provide sustainable benefits regardless of what price environment we find ourselves in the future. This includes driving costs out of all aspects of the organization and the continuous improvements as we optimize well performance. We're not done yet. We continue to challenge ourselves and our employees to improve in all areas.

Turning to slide nine. Slide nine highlights our financial and operational results compared to the prior periods. Adjusted EBITDA increased 10% from the prior quarter, going from $21 million to $23 million. This is a result of we realized a 43% higher oil price as oil rebounded from prior quarters. As you're all aware, oil has pulled back a little of late off the second quarter highs, average still meaningfully higher than the average market price we saw in the first quarter which was $33 a barrel.

In addition to that, we saw the spot price of natural gas improve sharply in late June. However, most of our gas is sold on the first of the month contracts, so the impact was minimal for the second quarter. We will see the benefits of this in July in which the first of the month price was $2.96, which is 74% higher than the low point of a $1.70 in March. We're encouraged by the run up in pricing. However, we're exercising caution given the inherent volatility. We've added hedges as outlined on page 11 to protect our downside.

Lease operating expenses are 11% lower from the prior quarter and 40% less than the prior year. Our operational team has simply done an outstanding job as they continue to find ways to drive down costs. In April, we saw a 20% reduction in head count, and G&A excluding severance was down 17% from the prior quarter and 40% from the prior year.

As you turn to the slide 10, it highlights the operational and financial results compared to guidance. Production was around the low-end of guidance. This was driven by the completion of cross-unit extended laterals in North Louisiana, which resulted in shutting-in 18 wells surrounding the wells being drilled as the frac work was completed. These shut-ins contributed to an overall companywide 1 Bcf of production that were shut-in during the quarter. As you know, we've proactively shut-in the wells surrounding the active fracs work to prevent damage, and they're all back online currently as we've concluded the frac work in July. Several of the wells have experienced improvements in production, as Harold spoke to earlier.

Oil production during the quarter experienced downtime resulting from operational issues at a third-party gathering facility in South Texas. I am happy to report these issues have resolved and the facility is functioning as designed currently and has functioned that way through the third quarter. We have revised full-year guidance to reflect impacts of non-core divestitures and other transactions.

Oil differentials are trending in the right direction and we anticipate they will continue for the remainder of the year, as we've been successful in renegotiating a significant sales contract in August that improves our price by $1.95 to $2.90 depending on the delivery points. Gas differentials also improved during the quarter from taking gas in-kind from other operators and higher regional prices in the Northeast.

We continue to focus on controlling our costs. We delivered lease operating expenses below the low end of guidance. G&A would've been in the guidance range absent the one-time severance cost. These costs will trend upward during the remainder of the year as we incur more professional fees associated with our restructuring program. These types of costs are not indicative of our long-term G&A structure and should subside on the completion of our restructuring initiatives.

We believe we can sustain a G&A run rate of approximately $25 million if, and I want to stress if, our restructuring program is successful. We ended the quarter with $246 million in liquidity and expect a cash flow outspend of approximately $60 million to $70 million for the remainder of 2016, excluding spending on liability, management initiatives such as the tender offer.

Turning to slide 11. Upward movement in spot and future prices for natural gas is encouraging and brought our hedges basically in line with the markets. As we look to the remainder of 2016, we're 66% hedged in natural gas on a PDP basis at $2.88 or 56% on the total estimated production for the remainder of 2016 basis.

For oil, we're 75% hedged for the remainder of 2016 at $58.61, and as we move to 2017, we have 66% of our projected PDP production with downside projection ranging from $2.76 to $2.99. We've entered into a power as recent as the 21st of last month that was $2.90 to $3.20 for Cal-17.

We continue to monitor the market conditions and look for opportunities to add to our hedge portfolio. I'll now turn the call back over to Hal.

Harold L. Hickey - President & Chief Executive Officer

Thank you Ricky. I'd like to remind everyone that our Q&A will be focused on operational matters and financial matters outside of our ongoing restructuring.

And with that, we'd now like to open the call for questions.

Question-and-Answer Session

Operator

Your first question comes from Tarek Hamid from JPMorgan. Your line is open.

Tarek Hamid - JPMorgan Securities LLC

Good morning.

Harold H. Jameson - Chief Operating Officer

Good morning, Tarek.

Tarek Hamid - JPMorgan Securities LLC

So, operationally, the three wells that turned to sale during 3Q 2016, did that require any wells to be temporarily plugged to facilitate the frac or did that all occur in the second quarter?

Harold H. Jameson - Chief Operating Officer

The wells that we fracked didn't require any plugging, but we did shut-in some wells that were offset to that frac work and actually we had some 18 wells or so shut-in across multiple sections. All those wells are now back on, the majority of those wells actually came on at three times the flowing rate that they were prior to being shut-in.

So, we're very excited about the results of those wells and we'll continue to look for opportunities to drill longer lateral and increase our proppant loading.

Tarek Hamid - JPMorgan Securities LLC

Great. So, the shut-in impacts all hit in 2Q 2016 and the benefit is largely going to be hitting in 3Q 2016? Is that the right way to put it?

Harold H. Jameson - Chief Operating Officer

Correct.

Harold L. Hickey - President & Chief Executive Officer

Right.

Tarek Hamid - JPMorgan Securities LLC

And then, just on gathering and transportation, just to clarify, as we think about that cost, when we think about where you are sort of above market, is it more on the gathering side or more on the transportation side or a mix of both?

Harold H. Jameson - Chief Operating Officer

It's a mix of both.

Tarek Hamid - JPMorgan Securities LLC

Okay. Any kind of way to ballpark it in your minds, like more gathering, more transportation, kind of any way to just help us think about it?

Harold H. Jameson - Chief Operating Officer

We're not going to talk about that at this point Tarek, I appreciate the question, but let's move on.

Tarek Hamid - JPMorgan Securities LLC

Fair enough. Thank you very much, guys.

Harold H. Jameson - Chief Operating Officer

You're welcome. Thank you.

Operator

Your next question comes from the line of Sinan Kermen from Drw. Your line is open.

Sinan Kermen - Drw Securities, L.L.C.

Good morning. If you could maybe start with what the current rights and obligations are, and economic interest if any retained in the JV, with KKR (24:08) as to how that's going to look with the arrangement going forward?

Harold H. Jameson - Chief Operating Officer

I would say that that arrangement going forward is going to be operated under more of a traditional JOA type operation. There will be no further obligations to make offers to purchase.

Sinan Kermen - Drw Securities, L.L.C.

Okay. Okay. And then, could you highlight the differences in the covenant amendment that you're seeking on the 2022s versus the ones – the covenant amendment that you recently received on the 2018s, as to what the differences are?

Richard Alan Burnett - VP, Chief Financial & Accounting Officer

They're very similar.

Sinan Kermen - Drw Securities, L.L.C.

Okay. Any reason why they were not done at the same time, back when you did the 2018s?

Christopher C. Peracchi - Treasurer, VP-Finance & Head-Investor Relations

Yeah. Sinan, it's Chris. The reason we did the 2018s when we did was to reset the $1.2 billion on the liens basket...

Sinan Kermen - Drw Securities, L.L.C.

Oh, Okay.

Christopher C. Peracchi - Treasurer, VP-Finance & Head-Investor Relations

...and that amendment is not getting made because the (24:58) 2022s we're just broadening the definition of credit facilities.

Sinan Kermen - Drw Securities, L.L.C.

Perfect. Perfect. And my final question is the gathering and transportation agreements that you're hoping to renegotiate with some of your counterparties, are they primarily or exclusively at the EXCO Resources, Inc. level or at intermediary OpCo levels?

Harold H. Jameson - Chief Operating Officer

We're not going to address that at this time. Thank you.

Sinan Kermen - Drw Securities, L.L.C.

Okay. Thanks.

Operator

Your next question comes from the line of Steven Karpel from Credit Suisse. Your line is open.

Steven Marc Karpel - Credit Suisse Securities (USA) LLC (Broker)

Good morning.

Christopher C. Peracchi - Treasurer, VP-Finance & Head-Investor Relations

Hi, Steven.

Steven Marc Karpel - Credit Suisse Securities (USA) LLC (Broker)

I tried to follow this, but can you tell me quickly what the cash effect of the adjustment on – or the change on the KKR agreement is, and I know that you didn't necessarily know how much you repurchased, but is it fair to say, you're talking somewhere around $20 million, is that how we should think about the change from a cash basis?

Christopher C. Peracchi - Treasurer, VP-Finance & Head-Investor Relations

Yeah. Steven, it's Chris again. If you look at the disclosure in the documents, I think you can see there was transfer of interest in wells, and not really any cash related items.

Steven Marc Karpel - Credit Suisse Securities (USA) LLC (Broker)

What I mean by that is, cash that you no longer have to expend?

Christopher C. Peracchi - Treasurer, VP-Finance & Head-Investor Relations

The obligation that we previously had was to make offers, and there were some issues around those offers and that matter has been resolved. So, we have no further obligations to make offers or to purchase properties from the counterparty.

Steven Marc Karpel - Credit Suisse Securities (USA) LLC (Broker)

I guess what I'm trying to understand is – how much was in contest on a dollar amount for purchase?

Harold H. Jameson - Chief Operating Officer

As part of that settlement, we're going to defer answering that question at this time.

Steven Marc Karpel - Credit Suisse Securities (USA) LLC (Broker)

The Pennsylvania sale, obviously I know it's small, but just to kind of tie the model, how much was that?

Harold H. Jameson - Chief Operating Officer

It was a very small sale. We actually sold though a significant number of wells that only entailed about $5 million or $6 million a day of production. The number of wells that we got out of it was about 3,500. We actually retained an override in exchange for that sale and what we did – that was very important as we got away from some significant asset retirement obligation that exceeded $20 million.

Steven Marc Karpel - Credit Suisse Securities (USA) LLC (Broker)

And what do you have left now in Appalachia then?

Harold H. Jameson - Chief Operating Officer

We have left in Appalachia some 125, 130 Marcellus wells and we also have some 1,900 conventional wells in West Virginia and I would say that those conventional wells in West Virginia are what we might term non-core.

Steven Marc Karpel - Credit Suisse Securities (USA) LLC (Broker)

Obviously, you did small stuff (27:50) in South Texas through sales, what else do you have that's non-core?

Harold H. Jameson - Chief Operating Officer

The other thing that we have that is of significance in Appalachia, is we have over 40,000 acres net to our interest in the Utica Shale and we're evaluating the opportunities in the Utica as we speak.

Steven Marc Karpel - Credit Suisse Securities (USA) LLC (Broker)

Where? Which counties?

Harold H. Jameson - Chief Operating Officer

It's in the dry gas window, Armstrong, Jefferson, Clearfield, some of those counties. There's about six or seven contiguous counties in that region, but I'd say Jefferson and Armstrong are sort of the epicenter for us.

Steven Marc Karpel - Credit Suisse Securities (USA) LLC (Broker)

All right. And the GPT, I know you don't want to get too specific, but can you give me some semblance on when these contracts are set to roll-off?

Harold L. Hickey - President & Chief Executive Officer

You can see that Steven in our disclosure in the K, the table is in the back, you can see the maturities as they roll through the years.

Steven Marc Karpel - Credit Suisse Securities (USA) LLC (Broker)

So, it looks like it's 2018, 2019, is there anything beyond that, that's what I'm getting at?

Harold H. Jameson - Chief Operating Officer

Yes. I think there are some beyond that. Yes.

Harold L. Hickey - President & Chief Executive Officer

Yeah.

Steven Marc Karpel - Credit Suisse Securities (USA) LLC (Broker)

But, I mean, am I right, am I reading that right to say that 2018, 2019 is the vast preponderance?

Harold L. Hickey - President & Chief Executive Officer

I wouldn't say that, I'd say they keep on rolling through multiple years after that too.

Steven Marc Karpel - Credit Suisse Securities (USA) LLC (Broker)

Thank you.

Harold H. Jameson - Chief Operating Officer

It's about a four-year window between 2018 and 2021, 2022 when the bulk of the contracts roll-off.

Steven Marc Karpel - Credit Suisse Securities (USA) LLC (Broker)

Okay. Thank you.

Harold H. Jameson - Chief Operating Officer

Welcome. Thank you.

Operator

We've no one else in queue at this time. I'll turn the call back to the presenters for any closing remarks.

Christopher C. Peracchi - Treasurer, VP-Finance & Head-Investor Relations

We thank everyone for your participation this morning. Have a good day. We'll talk to you next quarter.

Operator

This concludes today's conference. You may now disconnect.

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