EXCO Resources, Inc. (NYSE:XCO)
Q4 2016 Earnings Conference Call
March 20, 2017 10:00 AM ET
Heather Lamparter - Vice President, General Counsel and Secretary
Harold Hickey - Chief Executive Officer and President
Tyler Farquharson - Vice President, Chief Financial Officer and Treasurer
Harold Jameson - Vice President and Chief Operating Officer
Sinan Kermen - DRW Securities, LLC
Good morning. My name is Teshaun, and I will be your conference operator today. At this time, I would like to welcome everyone to EXCO’s Fourth Quarter and Year-End 2016 Results 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. [Operator Instructions]
Thank you. I would now like to turn the call over to Heather Lamparter, Vice President and General Counsel. The floor is yours.
Good morning. Thank you for joining EXCO Resources fourth quarter and full 2016 review conference call. Hal Hickey, Chief Executive Officer and President; Tyler Farquharson, Vice President and Chief Financial Officer, and Harold Jameson, Vice President and Chief Operating Officer, will provide our perspective on EXCO’s results followed by a Q&A session.
You can access our slides on our website at excoresources.com, and we will refer to these slides during our remarks. Certain statements made during today’s conference call including those concerning future plans, objectives, goals, strategies or performance are forward-looking statements. These statements reflect the good faith, beliefs and judgments of the company and are based upon currently available information only as of the date of this conference call.
These statements are subject to risks, uncertainties, and other factors that could cause actual results to differ materially from current expectations. These factors include those described in the risk factor section of the company’s periodic reports that are filed with the Securities and Exchange Commission. Forward-looking statements are not guarantees of future performance and the company expressly disclaims any obligation to update earlier statements as a result of new information expect as required by law.
I will now turn the call over to Hal to begin.
Thanks you, Heather. Good morning, everyone. First, let me congratulate Tyler Farquharson and Heather Lamparter upon their recent promotions to Chief Financial Officer and General Counsel, respectively. Both Tyler and Heather have been with EXCO for years and are most certainly deserving of their promotions. I’m personally pleased and very excited to continue working with them in their new roles.
Additionally, let me thank Wilbur Ross for his years of service on the EXCO Board, noting he recently resigned to become Secretary of Commerce in the new administration. Wilbur’s guidance and oversight will be missed. However, we have two recent additions to our Board, including Tony Horton, who is Chief Financial Officer and Executive VP of Energy Future Holdings; and Stephen Toy, who is Senior Managing Director and Co-Head of WL Ross & Co. Tony and Stephen have outstanding credentials and will serve the shareholders of EXCO very well. I certainly look forward to work with them as we move the company forward.
Next, as noted by our recent press releases and other filings, we’re very excited to announce the completion of a series of very complex financial transactions. These transactions enhanced our capital structure and position EXCO for strategic drilling and funding of other opportunities to create value for our stakeholders.
I apologize for delay in the call about few days, but we wanted to be able to share with you a fulsome disclosure of these transactions on our call. As a result, this conference call was rescheduled for today in order to allow us the time needed to close the transactions last week.
This morning, I’ll provide some additional introductory remarks and provide an overview of our strategic efforts. Following me, Tyler Farquharson will detail our recent capital structure transactions. Next, Harold Jameson will discuss operational results, as well as drilling and completion opportunities, improvements and priorities. Following Harold, Tyler will pick back up to discuss our financial results and provide guidance before we finish with our Q&A session.
Most of our assets and activity are built around natural gas, regarding significant macro trends that impact our business. Cal-17 natural gas prices are currently trading at approximately $3.15 per Mmbtu for the balance of the year, Cal-18 is at approximately $3.
The gas rig count was recently reported at 157 rigs. Towards figures for natural gas indicates that we’re likely to exit the injection season with a slightly more than two TCF in storage, though we’re currently below last year’s storage by about 9.5%.
We expect a record setting draw of natural gas from storage for the week ending March 17, due to last week’s cold weather. LNG exports are growing. Demand for natural gas in Mexico is increasing. Industrial growth calls for more natural gas feedstock. Opportunity for coal-to-gas switching for electrical generation exists. Lagging U.S. natural gas production combined with an expected rise in export demand is lending strong support to the forward price curve.
Year-to-date, U.S. natural gas production has averaged 70.6 Bcf per day and is down nearly 4% compared with the same period last year, when output averaged approximately 73.5 Bcf per day. At its current pace, U.S. production is also below levels in the closing months of 2016, when average production was about 71.6 Bcf per day according to Platts.
Assuming U.S. production remains around current levels, rising export demand is likely to put increasing pressure on U.S. gas prices later this year. By April, export demand should reach 7 Bcf per day. This demand is forecast to hit an annual high about 9 Bcf per day in October, as pipeline exports to Mexico and LNG exports to global markets continue to accelerate. The additional gas demand could lift U.S. gas prices to levels currently not seen by forward markets.
Like most oil and gas operators, we experienced a challenging year in 2016. Spot prices bottomed out in the neighborhood of $1.70 for natural gas and $30 for oil. We took decisive actions at the company to counteract some of the impact of this low pricing on our operations by limiting our development program, focusing on sustainable cost reduction initiatives, and improving our well performance. We also completed liability management initiatives to repurchase on secured debt at a significant discount to par.
Our ability to execute on these initiatives put us in a position to close the financial transactions last week, which now positions us with a path to grow the business and extend our run rate through at least 2020. We must deliver our expected well results, optimize and reposition our portfolio to potential acquisitions and divestitures, and continue to address debt maturities through additional liability management initiatives.
This will allow us to reduce our leverage and improve our debt to total capitalization back to sustainable levels. We believe this is achievable and the continued confidence, the affiliates of our Board of Directors have in the company, and our team was demonstrated by their significant participation in the recent capital structure transactions, where they invested additional capital into EXCO.
Now turning to Slide 2. Panel one highlights our recent capital structure transactions, which elevate the overhang of significant cash interest payment obligations that have burden thecompany for years. These new debt instruments, the $300 million 1.5 lien and the $683 million 1.75 lien allow us options to make optimal decisions for our shareholders.
In the immediate term, we can improve future cash flows for the payment of interest in equity or debt, and thereafter, we could limit future dilutions through the payment of interest in cash. We have potential to improve cash flow by more than $100 million per year by paying our interest in equity or debt as opposed to cash. Our liquidity pro forma for the transactions is $182 million, noting we have a redetermined credit facility of a $150 million with nothing drawn. Tyler will provide details later in the call.
Panel two references our gathering, marketing, and transportation efforts. We have not realized the success we aspired for. But we did take some actions and improve our overall position, including taking in count of our net volumes that are operated by others. We believe with our enhanced financing and opportunity to drill, we look forward to discussing a revised mutually beneficial rate structure with our main gathering.
Now, looking at panels three and four. We remain focused on managing all elements of our business, including costs, organizational structure, and drilling and completion designs. Costs are down dramatically. For example, our LOE cost during 2016 dropped approximately 35% on an absolute basis. GAAP G&A is down 17% and adjusted G&A is down 39%. Headcount is now below 180, down over two-thirds from January of 2015.
Regarding drilling and completion, the ability to extend lateral lengths resulted in a more cost efficient well design. We believe these are sustainable cost reductions regardless of volatility and service cost. Despite the headcount drop, we’ve maintained our technical and commercial skills to manage, drill, complete and produce wells and we’re well-positioned to execute development program. We’re excited to get back to drilling to create value for our shareholders.
We believe that longer laterals, increased profit levels, and manage production and pressure decline position us very well for drilling high rate of return, high net present value wells. We have a multi-year inventory of natural gas drilling in our portfolio that includes some 750 to 800 gross, or 250 to 260 net operated locations with rates of return in excess of 25% at varied prices.
With the recent completion of our capital transactions, we’re now evaluating our spending program for the remainder of 2017 and beyond. We’re excited about our opportunities noting that with our 95% operated position based on value and our 92% held by production acreage position, we control the timing and extent of development spending.
As Harold will discuss, the $3 pricing that we have allowed the economics of drilling and development in our core Haynesville region to be very strong. However, we will continue to evaluate opportunities on both sides of the balance sheet through our formal for our prioritized capital allocation system as noted in panel five to determine where and when we’ll be spending our capital.
Our spinning will be directed towards a highest PV over I opportunities, which could include drilling and development, acquisitions, leasing or our continued program to purchase unsecured debt among other opportunities. We’ll coordinate with our Board of Directors to determine our forward spending and development plans and will apprise you. Finally, note that we’re continuing to consider asset sales as we are evaluating a potential divestiture of south Texas.
Now, Tyler will discuss our capital structure transactions in more detail.
Thanks, Hal. On Slide 3, we highlight some of the key items from the transactions we announced last week. Our focus continues to be on establishing a sustainable capital structure that provides us with the liquidity necessary to execute our business plan.
Last week, we took another important step towards improving our capital structure by announcing a series of transactions, including the issuance of $300 million of 1.5 lien PIK Toggle Notes, exchanging $683 million of Second Lien Term Loans for a like amount of 1.75 Lien PIK Toggle Term Loans and securing covenant relief in our existing first lien credit agreement.
Taken in hold, these transactions increased our liquidity by $116 million, reduced potential cash interest payments by up to $109 million per year through an option to pay interest in common shares, extended our weighted average debt maturity by 30% and established structural liquidity allowing us to reinitiate the development of our drilling opportunities.
We remain committed to improving our financial flexibility and enhancing long-term value for our shareholders and are encouraged by the continued support and confidence from affiliates who have invested additional capital for their participation in the 1.5 lien.
Slide 4 provide some additional detail for the capital transactions announced last week. In panel one, the proceeds from the issuance of the 1.5 lien notes were primarily utilized for the repayment of the entire amount outstanding under EXCO’s credit agreement, transaction fees and general corporate purposes. In connection with this transaction, we amended the credit agreement to secure important financial covenant relief and establish the borrowing base at $150 million, with the next redetermination scheduled for November 2017.
Panel three shows the warrants issued in connection with the 1.5 lien issuance in exchange transactions. Please note that should the holders choose to exercise the warrants, the exercisability is subject to conditions, including the receipt of shareholder approval and change of control limitations. The financing warrants have a strike price of an approximate 50% premium to the day share price.
Also the amount of capital actual common shares purchased by the exercising party could be significantly lower than the amount depicted in this panel, depending on the holder’s election of either a cash or cashless exercise. Additional information related to all these transactions can be done in the Form 8-K filed with the SEC on March 15, 2017.
I’ll now turn it over to Harold who will discuss our operating results.
Thanks, Tyler. On Slide 5, you can see a map depicting the locations of our asset holdings in Texas, Louisiana, and Appalachia. Our year-end proved reserves were in excess of 1.5 TCF equivalent based on 12/30/16 NYMEX pricey up approximately 40% from year-end 2015, which was calculated on a year-end 2015 NYMEX trip. We reported increases in nearly all of our type curves from prior year, particularly the Haynesville shale with a 13% increase in Holly core and a 73% increase in the Southern Shelby area.
Nearly 75% of our reserves are in the Haynesville Bossier region of North Louisiana and east Texas. The area has undergone a resurgence over the past year, as operators have been able to significantly enhance returns through longer laterals and changes to the completion design, including higher levels of proppant and change cluster spacing.
We still believe there’s additional work that can be done to optimize our well design. And the well is drilled in North Louisiana during early 2017 will feature 30% more proppant than prior year, other nearby operators have recently been completing wells with nearly double the amount of proppant as our prior here wells.
We have vast experience with the Haynesville shale, given that we’ve been in the epicenter of the play since the inception of its development. Accordingly, we believe we can continue to not only build on our success that replicated over and over again. As noted, we have a large inventory we are able to exploit, as appropriate. Although, our Bossier opportunities are held by production. We have begun efforts to appraise the Bossier formation in North Louisiana. In fact, our first well drilled during 2017 is Bossier appraisal.
Our 2016 program included limited D&C spending, which was 72% lower than 2015. It was a focus on larger completion designs to generate uplift in well performance and lower unit development costs, significant cost reduction efforts in the capital program and base production operations, and preservation of liquidity.
I’d like to congratulate our teams as they have delivered results and executed on each of these initiatives extremely well. The D&C program with larger completions provided enhanced value through higher flow rates, higher EURs, and the lowest unit cost per lateral foot in EXCO’s history in the Haynesville play at just over $1,150 per completed lateral foot.
Our reserve expectations for these new larger well designs have increased to 2.3 to 2.6 Bcf per 1,000 lateral feet on a proved reserve basis, the high CUR per foot that EXCO has achieved in the Haynesville play to-date. Those uplift is attributable to improvements in completion design and refinements in our processes. We’ve made significant progress in drive our base LOE costs lower in total down 35% compared to 2015.
Congratulations to our operating teams on cost reductions and efficiency improvements in 2016. Some of the factors leading the charge were renegotiated salt water disposal contracts, redesign chemical programs, selective workovers and overall coordination on virtually all cost and supply items with our supply chain management process.
One focus for EXCO – focus area for EXCO that is delivered in adding compounded of LOE reduction, enhanced the EHS performance and production optimization is our Dallas control room operations. EXCO has made a significant commitment to technology. We placed that focus on the well site to monitor our operations closely.
Our control room is manned 24 hours a day and provide support across the EXCO asset base from South Texas to Appalachia. We leveraged the well site automation to optimize our company personnel time in the field, better use of manpower in the field results in lower production downtime, better EHS performance, and reduced costs by lowering contractor requirements.
The control room operation has been an integral part to EXCO’s success in lowering operating costs, changing the way we operate in the field, and we fully expect to sustain these captured efficiencies going forward.
Now picking up on Slide 6. I’ll highlight some of our recent well performance results in North Louisiana and East Texas. In panel one, the three curves show cumulative gas versus time for three different types of wells in DeSoto Parish, Louisiana. The three curves show our recent progression with completion design in lateral length. The lowest curve represents the standard length collateral with 1,600 pounds for foot.
The middle curve represents the larger completion design with 2,700 pounds per foot with the standard lateral length.
The highest curve is the average of our three most recent long lateral wells with approximately 2,650 pounds per foot. The sustained uplift in well performance is significant and demonstrates why we are focused on advancing our D&C activity in this core area of the play. The progression shows a 147% improvement in cumulative gas rate over that time period shown. This is achieved with much stronger well performance from the improved completion designs.
These longer lateral wells are currently forming with very low pressure declines of just under 10 psi per day. That slight decline demonstrates how strong these wells really are and provides further support to our crude reserves increase at year-end 2016.
In panel two, the same plot is illustrated for the Southern part of our East Texas area and the deeper part of the Haynesville play. These wells have three vertical depths ranging from 14,500, to 15,000 feet, that’s about 3,000 deeper than DeSoto Parish and Caddo Parish in North Louisiana.
The larger completion design in this area of the play has yielded a breakthrough in reservoir performance. We’re carefully choke-managing these wells just like in North Louisiana and the average PSR per day drop on these deeper wells is 7 to 10 PSR per day from the two wells with modified completions very flat.
This exceptional performance is direct support for higher proved reserve increases in this area. At year-end 2015, the PDP in this area was booked at 1.5 Bcf per 1,000 lateral feet and we’re currently booked at 2.6 Bcf per 1,000, or 73% increase. This is a significant change and we fully expect to incorporate this area into our development program earlier than originally planned based on this improved performance.
With the improvements in well performance achieved with our modified well designs, we have generated additional value to the drilling locations. In the Caddo area, example with panel four, 8-H PV-10 improves from $8.6 million per location from year-end 2015 to $10.7 million per location with our current target, or 24% increase in PV-10 value. The new designs are driving higher volumes, flatter, more sustained, well performance and higher value per location.
As you can see from these summary plots, our new completion designs are delivering strong results and generating high returns on our capital invested. In the appendix of the slide deck on Slide 13, our standard table of type curves, drilling inventory, capital and economics with break-even pricing is shown. We will have more details on the go-forward development plan soon.
Moving to Slide 7, the chart in panel one illustrates the EXCO drilling inventory ranked by break-even gas price required to deliver a 25% before tax rate of return. We have 773 gross, 254 net high-graded company-operated drilling locations, representing two of our asset areas that generate very strong returns.
As the chart shows, we have 331 gross, 95 net locations that deliver these returns below $3 per Mcf. The inventory of high-quality locations on the chart provides EXCO 19 years of drilling inventory, assuming a development pace of four rigs delivering about 40 gross wells per year.
This chart is a gas focused high-graded subset of our entire acreage position. The chart does not include the Eagle Ford, the Buda, Georgetown, and Austin Chalk in the South Texas area. The Utica, the Upper Devonian, and the upper Marcellus – the additional Marcellus opportunities in the Northeast, or additional Tier 2 Haynesville development locations in Harrison and Panola Countiesin Texas, and the Northern Caddo Parish acreage in North Louisiana.
Those areas combined provide another 1,246 gross, almost 400 additional net locations bringing our overall combined location count to over 2,000 gross locations, 650 net locations. EXCO has many years of development drilling ahead with high-quality opportunities with the current acreage position.
Now, I’ll turn the call over to Tyler to cover our 2016 results.
Thanks, Harold. Slide 8 compares EXCO’s financial performance to the previous periods. Adjusted EBITDA increased 4% compared to the third quarter and was primarily due to higher commodity prices, partially offset by lower production. Total daily production fell 9% from the third quarter due to natural declines, the sale of our conventional producing properties in Appalachia, and our stop in development activity.
Our lease operating and gathering and transportation expenses for the fourth quarter were up on a per unit basis due to the decline in production. The company’s performance against guidance is shown on Slide 9. EXCO delivered operational and financial results within or better than guidance for the fourth quarter and full-year 2016. We did not drill any additional wells during the quarter, but we have reinitiated drilling activity with plans to spud five gross wells during the first quarter 2017.
This activity includes four gross Haynesville wells with lateral lengths up to 7,500 feet and one gross 7,500 foot lateral Bossier well. Fourth quarter production was at the high end of guidance. However, we do project an additional 9% production decline for the first quarter of 2017 since the wells drilled in the first quarter 2017 will not be turned to sales until the second or third quarter of 2017.
EXCO’s gathering and transportation expenses were at the high-end of guidance, primarily due to lower production quarter-over-quarter. G&A expenses, excluding equity-based compensation were at the high-end of guidance and were impacted by $4 million of legal and advisory fees associated with the restructuring program.
Slide 10, summarizes EXCO’s current hedge position. As of year-end, approximately 70% of 2017 forecasted natural gas and 15% of 2017 forecasted oil production have been hedged. The company will continue to review its hedge position.
This concludes our prepared commentary. We’d now like to answer your questions.
[Operator Instructions] You do have a question coming from the line of Sinan Kermen with DRW. Your line is open.
Good morning. I have two questions. One, to the extent that you do execute the sale of your South Texas assets, the proceeds, do they have to go pay down your revolver, or any of it newly issued secured debt, or could you use the proceeds as you see fit?
The second question is, with regards to your progress on gathering and transportation agreements. You haven’t made much progress, as per your statement. Did it have anything to do with the fact that your potential peers of bankruptcy by your counter parties up until the leased capital markets transactions that you just executed, as such do you have – do you envision success now that your capital structure is in better shape than the previous quarter? Thank you.
Sure. I’ll take the first one. So we can reinvest the proceeds from sales of assets within a year, so that’s what we would plan to do. Then on the second one, I think, Harold will handle the second one.
Yes, regarding our gathering and marketing transportation, I can’t speak to why the counterparties did not negotiate with us as far as resetting terms or such on GMT. But I’m encouraged about the fact that now that we have a clear path so that we can drill wells again depending on where they fall out in our prioritized capital allocation system ranking.
I do think that if we drill, we do have an opportunity to renegotiate rates, particularly with our gathering counterparty. Obviously, it’s into their best interest if we drill more, and in turn, we do think that we have an opportunity to open the windows and have some discussions.
And I do not see any further questions over the phone.
Thank you, everyone. We appreciate your participation with us this morning and look forward to talking to you soon.
And this concludes today’s conference call. You may now disconnect.
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