The 1) wording around the opportunity and activity of the water business in the 10-K combined with 2) the capital spending on the water biz and 3) big hikes in executive comp are all signs (in my mind) that $TPL is going to get extremely aggressive with water.
This may be obvious to others but I think they are going to be more water-forward than most investors expect.
You don’t pay your top two dudes $2mm+ each to collect royalty checks and do small ticket land sales. More is happening here…
Some of my favorite sentences are below:
Oh and Glover and Packer got P A I D. The numbers speak for themselves; they appear to be deserving of their comp. Have to expect that operators in the area have those two gents on the shortlist for other big jobs down the road.
I’m fully expecting them both to buy more TPL in the open market.
As of December 31, 2018, TPWR continues to build out its water production, storage and delivery infrastructure system in the Permian Basin. TPWR has entered into multiple sourcing contracts with oil and gas operators throughout the basin, the terms of which provide justification for continued investment. During the year ended December 31, 2018, the Trust invested approximately $35.2 million in TPWR projects to develop brackish water sourcing and re-use assets.
While there is competition in the water service business in West Texas, we believe our position as a significant landowner of approximately 900,000 acres in West Texas gives us a unique advantage over our competitors who must negotiate with existing landowners to source water and then for the right of way to deliver the water to the end user.
As of December 31, 2018, Texas Pacific owned the surface estate in approximately 902,177 acres of land, comprised of numerous separate tracts, located in 19 counties in the western part of Texas. There were no material liens or encumbrances on the Trust’s title to the surface estate in those tracts. As of December 31, 2018, the Trust also owns a 1/128th nonparticipating perpetual oil and gas royalty interest under 84,934 acres of land and a 1/16th nonparticipating perpetual oil and gas royalty interest under 370,737 acres of land in the western part of Texas. Generally speaking, if the Trust sells the surface estate in real property with respect to which it holds an oil and gas royalty interest, that oil and gas royalty interest is excluded from the sale and retained by the Trust. In addition, the Trust acquired oil and gas royalty interests in approximately 1,826 net royalty acres during 2018.
The Trust has not incorporated equity-related compensation elements in its compensation programs. During the year ended December 31, 2018, the Trust did not issue or sell any equity securities.
The Trust purchased and retired 19,417 Sub-shares in the open market. (~0.25% of total).
Revenues increased $145.6 million, or 94.1% to $300.2 million for the year ended December 31, 2018 compared to $154.6 million for the year ended December 31, 2017. Net income increased $112.5 million, or 115.7% to $209.7 million for the year ended December 31, 2018 compared to $97.2 million for the year ended December 31, 2017.
Salaries and related employee expenses were $18.4 million for the year ended December 31, 2018 compared to $3.8 million for the comparable period of 2018. The increase in salaries and related employee expenses is directly related to the increase in the number of employees from 26 employees as of December 31, 2017 to 64 as of December 31, 2018 as well as an increase in contract labor expenses over the same time period.
Cash flows used in investing activities were $81.5 million compared to $18.7 million for the years ended December 31, 2018 and 2017, respectively. The increased use of investing cash flows is principally due to our investment of $44.7 million in water service-related assets during 2018, an increase of $27.0 million over our investment during 2017. Additionally, for the year ended December 31, 2018 we acquired $24.3 million of royalty interests and $9.4 million of land acquisitions. There were no such acquisitions of royalty interests and land for the year ended December 31, 2017.
As of December 31, 2018, we had a cash and cash equivalents balance of $119.6 million that we expect to utilize, along with cash flow from operations, to provide capital to support the growth of our business, particularly the growth of TPWR, to repurchase additional Sub-share Certificates subject to market conditions, and for general corporate purposes. We believe that cash from operations, together with our cash and cash equivalents balances, will be enough to meet ongoing capital expenditures, working capital requirements and other cash needs for the foreseeable future.
For the year ended December 31, 2017, the Trust sold approximately 11.0 acres of the Trust’s Assigned land in Texas for an aggregate sales price of approximately $0.2 million, an average of approximately $20,000 per acre. For the year ended December 31, 2016, the Trust sold approximately 774.6 acres of the Trust’s Assigned land in Texas for an aggregate sales price of approximately $2.9 million, an average of approximately $3,803 per acre. For the year ended December 31, 2018, the Trust acquired approximately 14,650 acres of land in Texas for an aggregate purchase price of approximately $9.4 million, an average of approximately $640 per acre.
As of December 31, 2018 and 2017, the Trust owned the following oil and gas royalty interests (in thousands, except number of interests): 1/16th: Nonparticipating perpetual royalty interests in 370,737 and 373,777 gross royalty acres as of December 31, 2018 and 2017, respectively. 1/128th: Nonparticipating perpetual royalty interests in 84,934 and 85,414 gross royalty acres as of December 31, 2018 and 2017, respectively.
For the year ended December 31, 2018, the Trust sold nonparticipating perpetual oil and gas royalty interests in approximately 812 net royalty acres (1/8th interest) for approximately $18.9 million, an average price of approximately $23,234 per net royalty acre. In conjunction with this sale, the Trust acquired oil and gas royalty interests in approximately 1,480 net royalty acres for an aggregate purchase price of $20.6 million, an average of approximately $13,949 per net royalty acre. (This doesn’t tie with the table?)
On January 7, 2019, the Trust sold approximately 14,000 surface acres of land in Loving and Reeves Counties, Texas for an aggregate price of $100.0 million (the “Sale”). The Sale excludes any mineral or royalty interest in the lands to be conveyed and the Trust reserved certain usage, disposal and water rights in approximately 1,280 acres of the lands conveyed.
On February 22, 2019, the Trust used approximately $46.9 million of the sales proceeds to acquire approximately 11,700 acres of land in Reeves and Culberson Counties, Texas. The remaining $53.1 million of sales proceeds will be used to acquire other like kind properties.
There are a number of oil and gas wells that have been drilled but are not yet completed (“DUC”) where the Trust has a royalty interest. Currently, the Trust has identified 309 DUC wells affected by our royalty interest. The process of identifying these wells is ongoing and we anticipate updates going forward to be affected by a number of factors including, but not limited to, ongoing changes/updates to our identification process, changes/updates by Drilling Info (our main source of information in identifying these wells) in their identification process, the eventual completion of these DUC wells, and additional wells drilled but not completed by companies operating where we have a royalty interest.
On February 25, 2019, Maurice Meyer III notified Texas Pacific Land Trust (the “Trust”) of his resignation as a Trustee and Chairman of the Board of Trustees effective immediately, in light of certain health issues. Mr. Meyer has served as a Trustee of the Trust since 1991, including as Chairman since 2003.In accordance with the Declaration of Trust, the remaining Trustees are in the process of nominating a successor trustee, whose nomination will be submitted to a vote of security holders at a special meeting.The Trustees have appointed John R. Norris III and David E. Barry, current Trustees, as Co-Chairmen upon Mr. Meyer’s resignation.On February 26, 2019, the Trust issued a press release for these announcements, a copy of which is filed herewith as Exhibit 99.1.
Texas Pacific Land Trust (NYSE:TPL) announced today that its Board of Trustees has declared a cash dividend of $1.75 per sub-share, a $0.70 increase over the prior year, payable March 15, 2019, to sub-shareholders of record at the close of business on March 8, 2019. This is the sixteenth consecutive year that the declared dividend has increased. Additionally, the Trustees declared a special dividend of $4.25 per sub-share payable March 15, 2019, to sub-share holders of record at the close of business on March 8, 2019.
$6 all in takes approx $47MM off the balance sheet. You’ll recall that there was about $110MM on the sheet as of Q3. I view this as a signal that TPL wants to play it down the middle of the fairway. Dividend is certainly up but not to a point where it is boxing out repurchases, water CAPEX, and land dealings.
$6 all in gets you to a 0.92% div yield. Certainly not a high flyer in the dividend income world.
$TPL-specific news is pretty scant as we await dividend declaration and the 10-K. News from the Permian, however, remains constant. Here are a few things that caught my eye recently:
Produced water in the Permian Basin is projected to grow 5 percent a year to between 7.5 billion and 8 billion barrels a day by 2025, according to Helstrom.
“Just the amount of produced water coming online will strain the system without everyone working together to find solutions,” he said.
He said the water cut is very high in the Permian Basin, with two to four barrels of water produced with each barrel of oil. If those water barrels can’t be managed, operators may have to shut in wells and limit production, he said.
This will be a theme for 2019
The decline began in mid-November after Plains All American Pipeline LP expanded the capacity of its about 300,000 barrels per day (bpd) Sunrise Pipeline.
The drawdown accelerated this month when Enterprise Products Partners LP began shipping crude on a converted natural gas liquids pipeline, the 200,000 bpd Seminole-Red line, two months ahead of schedule.
“They talked about improvement and now it was about hyper-targeting completions even more methodically in 2019,” explained Johnson. “Then a crude pricing anomaly happened over the holidays and everyone hit pause.”
Although concerns about market risk and perceived global demand linger, service companies have had the opportunity to put the less frenetic pace to their advantage by refining some of their internal processes, Johnson added.
“With a bit more patience this year operators can have their logistical systems improved (think water and proppant strategy), oilfield services will continue to give further pricing incentives to pump and more pipelines will come online,” said Johnson. “These are all considerations that make both logical and economical sense.”
Although his firm holds the view that much of the downward spiral in crude pricing was algorithmic, Johnson opined that operators “wanted the dust to settle first and see the market act more rationally.” Now, he added, “smart operators” hold the advantage.
“Strategic planning and expert-level execution takes position and timing, all things smart operators have on their side now,” said Johnson. “We’ve heard of stories where the biggest operators in the world have break-evens in the teens and low-20s in the Permian. Kudos to the operators that learned their lessons from the rough patches of last cycle and improved every department under the sun.”
Concho Resources Inc., one of the largest operators in the booming West Texas region, fell more than 13% in the two days last week after it released earnings that failed to meet analyst expectations for cash flow. Concho also said it plans to cut spending 17% from previous guidance, a reduction that would lead to oil output growth of 15% from the fourth quarter of 2018 to the same period this year, instead of 25%.
The bond between U.S. producers and financiers doesn’t appear to be completely broken, and the strongest shale companies continue to attract Wall Street backers. Industry bellwethers such as EOG Resources Inc. have begun to generate free cash flow and don’t need outside funds. They also have locked up land for future drilling locations and have less need to pay out billions for new inventory, a significant source of capital demands in previous years.
The tumble in oil prices at the end of 2018, combined with investor demands for fiscal discipline, has prompted most shale executives to only invest what they earn in cash flow, ending years of debt-fueled growth. But the scale of past investments and low service costs mean that the cutbacks will only put a dent in growth projections.
On average, U.S. explorers have cut their capital budgets 4 percent but are predicting a 7 percent increase in production, according to RS Energy Group, a Calgary-based researcher.
Exxon has homed in on the Permian Basin of West Texas and New Mexico as it struggles with dwindling production in formerly prolific oil provinces such as West Africa. The Microsoft partnership, which could add as much as 50,000 barrels of daily output, marks a strategic shift for Exxon, which historically developed technological tools and techniques in-house.
“We realized that we have to do something fundamentally different from a technology standpoint to enable us to grow to meet those volumes,” Anish Patel, Exxon’s leader on the project, said by phone.
TPL, among many otber things, is partly a call option on drilling technology.
Occidental has developed a detailed, standardized subsurface workflow that draws on a large company database to evaluate where and how to develop its huge inventory of Permian acreage, said John Polasek, vice president of geoscience for Occidental. The database consolidates its rock and reservoir data as well as results from companies actively working these plays.
Predictions are based on its store of geological, geophysical, geochemical, and petrophysical information. They are compared to the well results. If model predictions are validated by the “actual performance we know we have this figured out,” Polasek said.
Early results are promising. Occidental’s 30-day average production has increased annually since 2012, and it has drilled 26 of top of 50 wells in the basin while drilling 5% of the wells, he said.
Polasek pointed out that those top wells were completed with “25% less proppant than our peers. We feel we have done quite well with less and that is critical to becoming profitable in shale.”
Anyone know of a trust with lots of land that could host solar and wind projects?
Texas is also sixth in the top ten U.S. solar states, according to the Solar Energy Industry Association (SEIA).
In 2018, wind power provided 18.6 percent of the energy use in Texas, while wind will make up 23.4 percent of the 2019 generation capacity, according to ERCOT estimates from last month. Solar power is expected to account for 2.1 percent of the 2019 generation capacity in Texas.
Renewable energy and battery storage in Texas is set to increase in coming years. So is oil and gas production in the fastest-growing U.S. shale basin. Booming oil drilling will require more power to the grid and some of it, as odd as it may seem, will be coming from solar and wind power.
The Permian Basin is the prototype onshore unconventional super basin. It possesses key geological fundamentals in abundance. In addition, the Permian Basin and other North American basins are a fertile cradle of technology. They possess critical factors for innovation: private mineral ownership, a strongly networked community, service company partnerships and immediate rewards for risk taking. The Permian offers hard won lessons from more than a decade that include: addressing needs for energy transport, water handling, sand usage and variations in gas/oil ratios. Building on this experience, other basins can leapfrog ahead.
As always, good reading here. Of note are a couple charts in the comment section from Dennis Coyne. Take a look at his second chart that shows expected output from the Permian in pink.
Kermit is directly east of $TPL’s surface land in Loving, Reeves, and Culberson counties. The quote below speaks to the sheer amount of physical activity in the Permian right now.
With the increase of 18-wheelers and other vehicles on the roads of the Permian Basin, Prentice said the refinery will take advantage of locally produced crude oil and sell the gasoline and diesel locally.
“If the refinery were in operation right now, every single barrel would be sold within 100 miles,” Prentice said. “There’s been such an increase in demand.”
This is some of the end-of-2019 capacity we’ve been hearing about.
As construction for the 850-mile Gray Oak Pipeline draws to a finish, a joint venture led by Phillips 66 Partners has teamed up with Houston pipeline operator Kinder Morgan to move crude oil to more destinations.
Designed to move 900,000 barrels of crude oil per day by the end of the year, one of the end points of the Permian Basin to Gulf Coast pipeline is the Phillips 66 Sweeny Refinery in Brazoria County.
I may have saved the best information for last here. Important to know that Solaris started its build out in 2015/2016. Two year head start relative to $TPL.
Launched in November 2015 and financially backed by the private equity firm Trilantic Capital Partners North America, Solaris Water Midstream sources and delivers freshwater to drilling operations and moves and recycles oilfield wastewater.
The company reports having 16 current customers already either connected or in the process of connecting to its Pecos Star System.
A subsidiary of Marathon Oil Company signed a long-term contract for water services in a 369,000-acre area of Lea County, New Mexico that will allow for a 125-mile expansion of the Pecos Star pipeline network.
Once the construction for the expansion is complete, the Pecos Star System will include more than 300 miles of large diameter permanent pipelines and more than 200 miles of temporary pipelines.
My never ending quest to find and link all available $TPL analysis on the web continues. Here are a few pieces from 2017 written by Mission Advisors. Will dig in post some quotes in the coming days.
https://missionadv.com/an-introduction-to-texas-pacific-land-trust-tpl/
https://missionadv.com/an-introduction-to-texas-pacific-land-trust-pt-2/
https://missionadv.com/an-introduction-to-texas-pacific-land-trust-pt-3/
We’ve heard this story before. Substitute TPL and EOG for Waterfield and Anadarko.
Waterfield is led by Co-Chief Executive Officers Scott Mitchell and Mark Cahill, who previously built and led Anadarko’s and Western Gas’s Permian Basin commercial water infrastructure platform. Since partnering with Blackstone last summer, Waterfield has put together a highly skilled team that brings together upstream and midstream technical expertise with a deep understanding of the subsurface and operating characteristics of the Permian Basin. This expertise positions Waterfield to provide reliable, turn-key services for its customers.
Waterfield’s progress should be of interest to TPL follows as there are parallels between the two entities. Waterfield appears to be well capitalized and has a strong management team; looks like prime competition.
“It used to be (water management) was trucking water to saltwater disposal wells. Then the next generation was to pipe water to SWDs to get trucks off the road and enjoy the economic benefits of pipelines,” said Cahill, an engineer who got his start at Chevron. “I think we’re entering the next phase, where you’ll see subsurface expertise. It’s not just pipes and facilities but knowing where you’re putting the water and how you’re putting the water,”
“The eye-opener for us was when we were talking to other producers and we were talking about our focus on the subsurface, and no one else was looking at the subsurface,” Mitchell said. “That gave them comfort things would be done right. It dawned on us that this is how it will be done.”
He said producers have been reluctant to grant water management to other companies “because it’s so critical and it has to be done right. They know the subsurface, so they’re reluctant to hand it off to someone without that expertise.”
Already, Waterfield has a 15-year contract with Guidon Energy to construct a new system to handle Guidon’s water gathering and disposal needs across its 40,000-acre position in Martin County. That system, which will target deeper disposal zones, is expected to come online by mid-year. Waterfield also has an agreement with EagleClaw Midstream to operate EagleClaw’s Reeves County water assets — 58 miles of gathering lines and 390,000 barrels per day of permitted water disposal capacity.
Those contracts have met the company’s goal of “planting our flag, getting a platform in the Midland Basin and the Delaware Basin,” said Cahill.
15 year contracts are music to my ears.
Last year alone, the Permian’s production rose by a million barrels a day, and it could surpass the Ghawar field in Saudi Arabia, the world’s biggest, within three years. Now producing four million barrels a day, the Permian generates more oil than any of the 14 members of OPEC except Saudi Arabia and Iraq.
As many as 15 oil and gas pipelines serving the Permian are expected to be completed by the middle of 2020, potentially increasing exports from the Gulf of Mexico fourfold to eight million barrels a day after 2021, according to a recent Morningstar Commodities Research report.
“I will have work here forever,” said Mike Wilkinson, a truck driver who came from Dallas a year ago and moved into a trailer with his teenage daughter. “As hard a place as this is to look at, they are going to need guys like me to move equipment around here for years to come.”
With a major acquisition in New Mexico last year, Exxon Mobil became the most active driller in the basin, and projects that it will increase production fivefold by 2025. Also growing rapidly here, Chevron estimates that one in six of every barrels it produces globally will come from the Permian by 2021.
“For Shell, the Permian is absolutely critical,” said Gretchen Watkins, president of Shell Oil. “The Permian is massive; it’s a game changer for U.S. shale. It is the powerhouse field.”
Rude and crude analysis warning. I was looking at 4Q and was thinking that net income looked fairly light relative to revenue so I did a little digging and confirmed my suspicion.
The top analysis attempts to isolate the water business to determine profitability. We start with net income and add taxes back in to get an EBT. EBT is then reduced by TPL’s legacy “low expense” businesses (Royalty, Sundry, and Sales) to get towards earnings from the water business. This new adjusted EBT number is further adjusted by adding back an estimate for the expenses (2x 2016 full year expenses) of the “low expense” businesses. The result is something that might approximate income generated by the Water business. Water’s reported top line can be compared to the water income estimate to get a picture of what Water’s expenses and margin look like.
The conclusion is that Water’s expenses were up significantly in 4Q which drove the estimated margin down to ~21%. Lots of assumptions and brute force in here. Everything highlighted in green is a custom creation.
The bottom analysis gets to ongoing margins more directly. Here we compile the revenues from Royalty, Sundry, and Water and compare them to a “non-sale” income number that is generated by adding taxes and proceeds from asset sales back into net income. Adjusted income / adjusted sales = margin of repeating buiness. This analysis too points to materially lower margins in 4Q.
Where’s that margin going?
Update: Quick update 15 minutes after posting. Please take some time to look at the column all the way to the right. Margin compression or not, $TPL is on fire. Oh, and thank you Mr. Taxman.
Exxon was a latecomer to shale production in the booming Permian Basin, but the company has invested heavily in recent years, including the $6.6 billion purchase of acreage from the Bass family in 2017, and plans announced this week to expand a Texas refinery to use more of the light oil produced nearby.
“With access to terminals, railways, pipelines and waterways nearby, the Beaumont refinery is strategically positioned to benefit from Permian production growth,” said Bryan Milton, president of ExxonMobil Fuels and Lubricants Company. “The addition of a third crude unit in Beaumont will enhance the refinery’s competitive position and truly establish it as a leader in the U.S. refining industry.”
The Texas Pacific Land Trust Investor 