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W&T Offshore, Inc. (NYSE:WTI)
Q4 2019 Earnings Call
Mar 05, 2020, 10:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the W&T Offshore fourth-quarter and full-year 2019 conference call. [Operator instructions] This conference is being recorded, and a replay will be made available on the company's website following the call. [Operator instructions] I would now like to turn the conference over to Al Petrie, investor relations coordinator.

Al Petrie -- Investor Relations Coordinator

Thank you, operator. And on behalf of the management team, I would like to welcome all of you to today's conference call to review W&T Offshore's fourth-quarter and full-year 2019 financial and operating results. Before we begin, I would like to remind you that our comments may include forward-looking statements. It should be noted that a variety of factors could cause W&T's actual results to differ materially from the anticipated results or expectations expressed in these forward-looking statements.

Today's call may also contain certain non-GAAP financial measures. Please refer to the fourth-quarter 2019 earnings release that we issued yesterday for disclosure on forward-looking statements and reconciliations of non-GAAP measures. At this time, I would like to turn the call over to Tracy Krohn, W&T's chairman and CEO.

Tracy Krohn -- Chairman and Chief Executive Officer

Thank you, Al. Good morning, everyone, and thank you for joining us for our 2019 year-end conference call. With me today are Janet Yang, our executive vice president and chief financial officer; William Wilford, our executive vice president and general manager, Gulf of Mexico; Steve Schroeder, our chief technical officer; and Jim Hersch, our vice president, geosciences, who are all available to answer questions later during the call. Over the past 36 years, we've grown W&T through the right combination of attractive property acquisitions, methodical integration and exploitation of those acquisitions and successful development and exploratory drilling on our legacy fields, all while maintaining our focus on generating strong free cash flow.

We completed two great acquisitions in 2019 for approximately $188 million that added meaningful production, significant reserves, and future drilling locations. In addition, we added nine new shallow water and eight new deepwater leases in the Gulf of Mexico federal lease sales. Financially, we generated adjusted EBITDA of $283 million, reported positive adjusted net income for every quarter, generated about $106 million in free cash flow, excluding acquisitions and lowered per BOE operating and overhead costs. Thus, we increased reserves, increased production and cut costs.

So before we discuss our strong fourth-quarter earnings and provide an operations update, I'd like to review some of these important 2019 major achievements in a bit more detail. So at the beginning of 2019, I told you that we were looking closely at acquisition opportunities. And in the second half of 2019, we executed some very good transactions that met all of our stringent investment criteria. We look for properties with existing, good cash flow, upside that we can achieve with the drill bit and the potential to increase near-term cash flow through workovers, recompletions and/or facility upgrades.

We primarily use the cash we generate to fund drilling and make more acquisitions to consistently grow value. We also use our free cash flow to partially pay down our debt to protect our balance sheet. So on August 30th, we closed the Gulf of Mexico Mobile Bay acquisition from ExxonMobil for $167.6 million, which included working interest in nine shallow water producing fields and related operatorship in the Mobile Bay area, making W&T the largest operator in the area. These low decline assets are free cash flow positive and adjacent to our current operations, thereby providing us the opportunity to recognize increased scale, rationalize operations and capture cost efficiencies to further grow cash flow.

The acquisition also included their onshore gas processing facility that is near our Yellowhammer gas processing facility. So on December 12th, we completed an oil-weighted producing property acquisition from ConocoPhillips for their 75% working interest and operatorship of the Magnolia field in the central region of the deepwater Gulf of Mexico. The total purchase price was $20 million. Magnolia field provides upside from additional pay sands at existing wellbores and potential opportunities for future drilling.

Both acquisitions were funded from W&T's available cash on hand and our revolving credit facility. The 2019 acquisitions added approximately 82 million barrels of proved reserves as of year end, which was higher than the 78 million barrels of oil equivalent combined reserves as of the effective dates of each transaction. The increase to reserves was driven by synergies and operational cost savings already captured by W&T at Mobile Bay that were partially offset by lower year-over-year prices. The underlying technical analysis of the total field remained unchanged, but these lower costs allow for higher margins throughout the life of the asset, thus extending the overall field life.

In addition, there is the opportunity for future growth and reserves from potential field life extensions with little or no capital, as well as through drilling and facility upgrade opportunities. We have a very good track record of reducing costs and enhancing value with all of our past acquisitions, and we intend to do that with both Mobile Bay and Magnolia in 2020 and beyond. So you saw in our release last night that we recently signed a purchase of sale agreement to acquire the remaining 25% working interest in the Magnolia field. We expect to close that transaction on March 31.

This is another example of the attractive acquisition opportunities we're seeing across the Gulf of Mexico. Looking at our strong year-end reserve report, W&T's 2019 SEC proved reserves increased 87% to 157.4 million barrels of oil equivalent from 84 million barrels of oil equivalent at year-end 2018. So about 40% of year-end 2019 reserves were liquids and the balance was natural gas. The company achieved a proved reserve replacement rate of nearly 600% of 2019 production of the 14.8 million barrels of oil equivalent.

This included acquisitions, positive revisions, extensions and discoveries and the impact of negative revisions due to pricing. At year end, approximately 78% of 2019 proved reserves were classified as proved developed producing. 7% is proved developed nonproducing, and 15% is proved undeveloped. We extended our reserve life ratio with 2019 acquisitions and successful drilling to 8.7 years based on year-end 2019 proved reserves and the midpoint of our 2020 production guidance of 49,600 barrels of oil equivalent per day.

The PV-10 value of W&T's SEC proved reserves at year-end 2019 was $1.3 billion, down about 9%, from $1.4 billion at the end of 2018. This was driven by reduced oil pricing of 11% and natural gas pricing of 16%. The 2019 SEC PV-10 is based on an average crude oil price of $58.11 per barrel and an average natural gas price of $2.63 per Mcf. The total impact from the year-over-year pricing change reduced proved reserves by approximately 10 million barrels of oil equivalent and PV-10 by approximately $0.5 billion.

So our all-in reserve replacement cost in 2019, including acquisitions, drilling costs and considering all reserves and the impact of negative price revisions was $4.18 per barrel of oil equivalent. For the three-year period 2017 through 2019, W&T's all-in reserve replacement cost was $5.05 per barrel of oil equivalent. We think that's a very competitive cost for any U.S. E&P, especially for a company with proved reserves that are 85% proved developed.

So now turning to our fourth-quarter results, we're pleased with our performance, in particular, with the increases in production, integration of the Mobile Bay assets' growth in adjusted EBITDA and continued strong cash flow generation. We grew adjusted EBITDA to $79 million in the fourth quarter, despite a weak pricing environment, while investing $32.2 million in capital expenditures, excluding acquisitions and maintained an active drilling program in the GOM, with two rigs running. This is very important as we continue to create significant value by generating nearly $50 million more of adjusted EBITDA versus our CAPEX. One of the pillars of our success is our ability to generate positive cash flow.

For the full-year 2019, we generated $283 million in adjusted EBITDA. It's been $126 million in CAPEX, excluding acquisitions, which was below the low end of our guidance of $130 million to $150 million. In the fourth quarter of 2019, our production increased 28% to 52,773 barrels of oil equivalent per day or 4.9 million barrels of oil equivalent compared to the third quarter of 2019. This was above the midpoint guidance range and included three months of production from the Mobile Bay assets and less than one month from Magnolia asset.

Total liquids production comprised 45% of production in the fourth quarter of 2019. Production for the full-year 2019 was above the midpoint of production guidance and came in at 40,600 barrels of oil equivalent per day or 14.8 million barrels of oil equivalent. So for the first quarter of 2020, we expect our production to be between 49,600 and 54,800 barrels of oil equivalent per day. And for the full-year 2020 to be between 47,100 and 52,100 barrels of oil equivalent per day.

So for the fourth quarter of 2019, prices declined about 4% for oil compared with the third quarter, but increased modestly for NGLs and natural gas. The average realized crude oil sales price was $56.84 per barrel. The NGL sales price was $16.64 per barrel, and the natural gas price was $2.58 per Mcf. Revenues for the fourth quarter increased quarter over quarter by 15% to $151.9 million.

The increase was driven by higher sales volumes, partially offset by the decline in realized oil prices. So our total fourth quarter LOE came in at $53.3 million, which was below the low end of our guidance range primarily due to lower work-over costs and nonoperated facility maintenance expenses resulting from delays in the timing of planned projects. On a quarter-over-quarter basis, LOE costs were up primarily due to additional costs associated with the Gulf of Mexico, Mobile Bay acquisition. But on a per BOE basis, fourth-quarter costs were down 12%, to $10.98 per BOE.

That's reflecting the benefit of the higher volumes and lower per BOE costs associated with the Mobile Bay acquisition. We also reported net income in the fourth quarter of 2019 of $9.6 million or $0.07 per share, which included $18.1 million in unrealized commodity derivative loss. Our adjusted net income grew by 32% to $24.4 million or $0.17 per share. At December 31, we had $32.4 million in cash and cash equivalents and $139.2 million of availability under our revolving bank credit facility.

In early 2020, we paid down debt with a portion of the free cash flow that we continue to generate. And as of February 29, 2020, we reduced our borrowings on our revolving bank credit facility by $25 million to $80 million in borrowings under our revolving bank credit facility. This is about a 24% reduction in revolver debt. So turning now to operations.

We continue to have strong results through the drill bit. At the Ewing Bank 910 deepwater field, the South Tim 311 A-3 well was successfully drilled in the first quarter of 2019 and discovered two high-quality sands. The operator completed the well in the third quarter of 2019. Well is currently producing approximately 4,850 gross barrels of oil equivalent per day.

The A-3 well follows the success of the A-2 well that was brought online early in 2019. On June 5th, we announced an oil discovery at our first exploration well in 2019 at Gladden Deep. The well is located in approximately 3,000 feet of water, and was drilled to a total measured depth of 18,324 feet and encountered 201 feet of net oil pay. Well was completed and placed on production ahead of schedule in the third quarter, and it's currently producing approximately 4,360 gross barrels of equivalent per day, with 89% oil.

We are the operator of the well and own a 17.25% interest in the discovery that will increase to 22.1% once performance thresholds are met. Additionally, we successfully drilled the Ship Shoal 28 number 41, and the East Cameron 321 B-8 sidetrack wells in the third quarter. The Ship Shoal 28 number 41 was brought online in the fourth quarter of 2019 at a gross rate of 1,440 barrels of oil equivalent per day. The East Cameron 321 B-8 sidetrack well, logged better-than-expected net vertical pay of 84 feet and was brought online late in the fourth quarter of 2019 at a gross rate of 940 barrels of oil equivalent per day.

Our interest in both of these wells is currently 30%, and that will increase to 38.4% once performance thresholds are met. So we're currently drilling our first well of 2020 in the East Cameron 338/349 field. The Cota well is in over 290 feet of water, with a planned total depth of over 6,000 feet, and we expect to reach TD in the second quarter of 2020. We currently own a 20% interest in the Cota well, which will also increase to 38.4%, once the well is brought online and performance thresholds are met.

During the fourth quarter, we performed one well recompletion and six workovers that in total added about 1,000 net barrels of oil equivalent per day. So looking ahead to 2020 under current commodity pricing conditions, we intend to continue to generate free cash flow and focus on debt reduction and additional acquisitions. This means that we will take a measured approach to drilling, while continuing to find our capital expenditures, excluding acquisitions, with available cash and cash generated from operations. Our preliminary capital budget for 2020, excluding acquisitions, is expected to be in the range of $50 million to $100 million.

We also expect to spend about $15 million to $25 million on asset retirement obligations this year, which is in line with the $20 million average that we spent on ARO in the past two years. We have significant flexibility to adjust our capital spending up or down at any time since we have no long-term rig contract commitments or drilling obligations. Our lower production decline profile combined with a 2020 drilling program that will add incremental production in late 2020 and early 2021, allow reductions in CAPEX without significantly impacting near-term production levels. For example, we could further reduce our CAPEX to approximately $20 million and see an approximately 1% decline in production from the range we provided for 2020.

For 2020, assuming the midpoint of our preliminary CAPEX range of $75 million, we currently estimate that we will generate free cash flow at or above $45 per barrel of oil and $1.50 per Mcf of natural gas. We think that's a very positive statement to make in this current, uncertain price environment. So our 2020 capital program will continue to be focused on lower risk, high return projects, which could be placed on production fairly quickly. We have a strong inventory of drillable projects and a long track record of drilling success.

In 2019 and 2018, we had a 100% drilling success rate. And since 2011, across nearly 50 wells, we've achieved a success rate of 93%. We believe that even with that lower preliminary budget range of $50 million to $100 million, we will be able to increase production, approximately 16% to 28% in 2020 versus our full-year 2019 production rate of 40,634 barrels of oil equivalent per day. This increase is bolstered by acquisitions we completed in the second half of 2019.

We also expect our LOE to increase on an absolute basis, but we are forecasting a meaningful decrease on a per BOE basis compared to 2019. So despite the acquisitions that have significantly increased production and reserves, we believe our G&A expenses will be similar to 2019 levels. We will continue to control the cost that we can to maximize our margins and generate significant cash flow from our operations. Our release yesterday has more details on our 2020 first-quarter and full-year guidance.

So we remain optimistic about the future for W&T. We have a premier portfolio of both shallow water and deepwater properties with significant upside that will be further enhanced through acquisitions and organic drilling. We have developed significant technical expertise in the Gulf of Mexico for over 37 years and believe that we can leverage this expertise to maximize the value of our asset base and any additional acquisitions that we make. We believe that market conditions in the Gulf of Mexico remain very favorable for additional acquisitions.

We will continue to look at new opportunities that meet our criteria and are accretive, add production, reserves and cash flow. We are well-positioned to generate sustainable growth within cash flows, and we believe that the Gulf of Mexico is an excellent basin in which to achieve that growth. We remain focused on operating efficiently and executing our long-term strategy while maintaining our strong balance sheet to maximize shareholder value. Our management team's interests are highly aligned with those of our shareholders, given our 34% stake in W&T's equity, which is the highest of any public E&P company, the market cap below $7 billion.

This alignment of interest ensures that we're truly incentivized to maximize shareholder value and mitigate risk, and we look forward to working through it in 2020. Operator, we can now open the lines for questions.

Questions & Answers:

Operator

[Operator instructions] The first question comes from John White of ROTH Capital. Please, go ahead.

John White -- ROTH Capital Partners -- Analyst

Good morning, and congratulations. It's not every year that you're able to double proved reserves. So could you talk in general about the 2020 drilling and development program since CAPEX has been greatly reduced, which I think is a prudent move given the size of the CAPEX, that rule out any deepwater wells. Or are you going to focus on workovers? Could you just give us a little color?

Tracy Krohn -- Chairman and Chief Executive Officer

Yes. We do have a reduced program from last year, of course, because we've reduced our budget. We've got a well that we're drilling now. We've got plans a little bit later on in the year for another well in, what I would call, deeper water higher than 380.

And also, we've got plans for another well at Ship Shoal 14. We've got the Mississippi Canyon 800 Subsea 1 sidetrack that we did as an invention work over in '19. We're looking at some other activities around one of our fields that haven't really come to the forefront yet for announcement purposes, but that's going to be South Tim 316. And we expect that we'll have other opportunities as we work through the data at Mobile Bay and other places where we're doing more reprocessing in our shops now.

Expect to see the results of that kind of production increase, probably later on in the year in early 2021.

John White -- ROTH Capital Partners -- Analyst

OK. Well, thanks a lot. And given your production profile, you've got a lot of flexibility to cut CAPEX like that. And congratulations on the progress of paying down the debt.

Tracy Krohn -- Chairman and Chief Executive Officer

Thanks, John. Yes. If we could just get prices up, we'll do some more drilling, too.

John White -- ROTH Capital Partners -- Analyst

I appreciate you taking my question. Thank you, sir.

Operator

[Operator instructions] The next question comes from Richard Tullis of Capital One securities. Please, go ahead.

Richard Tullis -- Capital One Securities -- Analyst

Thanks. Good morning, Tracy, and everyone over there. Quick questions for you. You talked about the acquisition landscape.

And of course, the reduced budget for this year. What's the outlook for possibly pulling together additional drilling-type JVs similar to Monza to maybe do a little bit of work in 2020 with some outside funding as well?

Tracy Krohn -- Chairman and Chief Executive Officer

Yes. That's certainly a possibility. We do have more wells to drill. I'm really more inclined to focus on acquisitions at this point.

And of course, as we do the acquisition, that generates more prospects.

Richard Tullis -- Capital One Securities -- Analyst

Understood. And as you look at the 2020 budget, the $50 million to $100 million in total. You outlined the guidance for this year in production and talked a little bit about the impact on production later in the year. What sort of outlook would you see production-wise, say, the first half of 2020 as a result of this year's spending in broad terms?

Tracy Krohn -- Chairman and Chief Executive Officer

I'm not sure I have a response for that, Richard. I don't see any real dramatic increases or decreases throughout the year. I think we've outlined guidance kind of as a front well, not kind of, but as a function of the budget that we proposed. Clearly, if we spend more money, we'll expect to see an increase in the budget.

We did tell you that down to a very minimal budget of around $20 million that we would expect to see only about a 1% decrease in production level.

Richard Tullis -- Capital One Securities -- Analyst

OK. And just as a quick follow-up. Could you do the same sort of production impact in 2021 with another $20 million-type budget in 2021?

Tracy Krohn -- Chairman and Chief Executive Officer

It's a little bit far-reaching right now. I think what we would expect to see is increases in production as a function of the work that we're doing. The more impact that we would see would be later on in the year in early 2021. So a complete blowdown to a lot of our reserves.

We doing no work is typical in the Gulf of Mexico, where we're seeing around 15-or-so percent. I mean, the good news is that our production profile -- our R/P is increased over eight -- about eight points out.

Richard Tullis -- Capital One Securities -- Analyst

OK. That's helpful, Tracy. Thank you.

Tracy Krohn -- Chairman and Chief Executive Officer

Sure.

Operator

The next question comes from Richard Dearnley of Longport. Please, go ahead.

Richard Dearnley -- Longport Partners LP -- Analyst

Good morning. Your comment about the price effect on reserves was 10 million barrels or $0.5 billion. Was that largely in the oil part of your reserves? Or was that spread across the three?

Tracy Krohn -- Chairman and Chief Executive Officer

No. It was more on the gas side of it.

Richard Dearnley -- Longport Partners LP -- Analyst

Oh, OK. And then to follow up on one of the prior questions. Your CAPEX of $20 million, keeping production down 1%, how much of the -- or what would the decline rate be for your assets pre last year's acquisitions?

Tracy Krohn -- Chairman and Chief Executive Officer

Pre last year's acquisitions. Well, pre last year, we had an R/P of around 5.5 to 6. And currently, it's around 8.7. So I think that should make up for most of it.

Richard Dearnley -- Longport Partners LP -- Analyst

I'm not at very facile with those numbers. Since you have a bunch of production coming from 2019 acquisitions. That's masking or it's offsetting the base decline rate.

Tracy Krohn -- Chairman and Chief Executive Officer

No. It doesn't offset at all. It increases it. The base decline rate gets longer because we've added reserves that are long-lived reserves.

Richard Dearnley -- Longport Partners LP -- Analyst

OK. And the long-lived reserves increased the decline rate?

Tracy Krohn -- Chairman and Chief Executive Officer

They decrease the decline, right.

Richard Dearnley -- Longport Partners LP -- Analyst

Yes. They decrease the decline. OK.

Tracy Krohn -- Chairman and Chief Executive Officer

That's correct.

Richard Dearnley -- Longport Partners LP -- Analyst

OK. So I'll just say not available.

Tracy Krohn -- Chairman and Chief Executive Officer

I don't know what you mean by that.

Richard Dearnley -- Longport Partners LP -- Analyst

So the answer is -- I'm still murky on the answer. Now it could be --

Tracy Krohn -- Chairman and Chief Executive Officer

I don't know how many different ways I need to answer it for you, sir. The R/P profile has increased. And reserves have increased. The only logical answer is, of course, that the production profile is better.

We're producing more, and we've added more reserve, and we've cut costs.

Richard Dearnley -- Longport Partners LP -- Analyst

OK.

Operator

[Operator instructions] This concludes our question-and-answer session. I would like to turn the conference back over to Tracy Krohn, president and CEO, for any closing remarks.

Tracy Krohn -- Chairman and Chief Executive Officer

Thank you, sir. We look forward to more good news in the not too distant future, and we'll talk to you again soon. Thanks so much.

Operator

[Operator signoff]

Duration: 36 minutes

Call participants:

Al Petrie -- Investor Relations Coordinator

Tracy Krohn -- Chairman and Chief Executive Officer

John White -- ROTH Capital Partners -- Analyst

Richard Tullis -- Capital One Securities -- Analyst

Richard Dearnley -- Longport Partners LP -- Analyst

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