The trade that read the courthouse by hand, the barrels the newest federal data say the country pumps, ships and burns, and the market that will decide what a Permian barrel is for after the car.
A second entry. Section I follows the landman’s trade back to the county clerk’s book and forward to the run sheet. Section II reads the newest federal supply data for what a Permian barrel does after it leaves the wellhead. Section III asks what the lease says when the barrel’s buyer is a cracker rather than a car.
The record came before the trade. A Texas clerk was told to record deeds in 1836; a New Mexico clerk was told in 1887 that the record was notice to all the world. Everything a landman does today descends from the problem of reading those books.
On December 20, 1836, the first Congress of the Republic of Texas organized its county courts and told each clerk to “seasonably record all deeds and other instruments of writing required by law” [1]. Fifty years later the Territory of New Mexico wrote the sentence that still governs its recording system. Laws 1886 to 1887, chapter 10, made the record of an instrument affecting real estate notice to all the world from the time of recording, and told the clerk to enter every instrument in a reception book under the grantor’s name with the date, the hour and the minute, on pain of a hundred-dollar fine [2], [3]. Those two acts created the object every title examiner in Eddy or Lea County still works from: a book kept by a clerk, ordered by time, indexed by name, and open to anyone who walks in.
The name index is the reason the trade exists. A clerk indexes by grantor and grantee because the statute tells him to; nobody told him to index by land. The Texas Revised Statutes of 1885 required instruments to be recorded “word for word and letter for letter” with the exact time of deposit, and alphabetical indexes of the parties, and nothing more [4]. Anyone who wanted to know what had happened to a particular quarter section had to build the missing index himself, name by name, and that private index became the capital of a new business. George Warvelle’s 1883 treatise, the first American book on the subject, put it plainly: “No perfect abstract can be compiled without the assistance of a carefully prepared tract index” [5]. By 1908 William Niblack could state the product’s limits: the abstracter was liable only to the person who employed him [6].
The trade organized nationally in 1907 [9], and a directory of that year lists the Pecos Valley’s share of it: an Eddy County Abstract Company at Carlsbad, three abstracters at Roswell, and fifty-nine in Texas across two pages [10]. There was no Lea County to list; it was cut from Eddy and Chaves counties on March 17, 1917 [11].
The booms of the 1920s turned that record into money, and the Santa Rita play began as pure paper. Rupert Ricker, a Reagan County lawyer, filed applications on 431,360 acres of University of Texas land, could not raise the $43,136 filing fee, and sold his maps and preliminary leases to Frank Pickrell for $2,500 [16]. The well was spudded on January 8, 1921 and came in on May 28, 1923, after 646 days of cable-tool drilling, and by 1925 the Permanent University Fund was growing by more than $2,000 a day [16], [17].
The Hendrick field in Winkler County carries the clearest dated lease flip in the record: ranch leases taken for ten cents an acre, more than 21,000 acres of them resold at thirty-five cents, a discovery on July 16, 1926, and on November 22 of that year a controlling interest sold to a Standard of Indiana subsidiary for $510,000 [18]. Lease paper, not oil, was what most people in those towns were buying and selling.
Southeastern New Mexico joined the record in the same decade, on state paper. The Illinois No. 3 at Artesia, drilled into its pay sand on April 9, 1924, stood on state leases; the State Land Office had issued its first oil and gas lease in 1916 and received its first royalty in 1924 [19], [20]. Hobbs was a one-company wildcat. The Midwest Refining Company spudded the discovery well on October 12, 1927, being then all but the only company interested in the area; within two and a half years more than twenty companies were there [13]. The State Bureau of Mines also recorded the purest example of the lease clock at work: Humble’s No. 1 on the Bowers permit, spudded June 10, 1929 for “apparently no other reason than to satisfy an expiring land agreement,” and completed eight months later as the first well in the area of large production [13].
The lease men worked from a printer’s form. A 1952 law review traces the “unless” lease to the Producers 88 form, which originated in Oklahoma after the state’s Supreme Court decided Brown v. Wilson on January 11, 1916, holding a one-dollar lease with a surrender clause voidable for lack of mutuality [21], [22]. A group of lawyers took a redrafted form to a printer who, as was the custom, “added his serial number to the printed form” [21]. When a legal institute later gathered more than 200 lease forms, more than 180 were Producers 88 forms. The popular version of the story names no company, no printer and no date, and a 2012 reviewer who examined more than thirty-five printed versions found no original [23], [24].
The people doing this work did not yet have a profession, or a name they liked. Early in 1954 a group of landmen led by George Foster Brown began organizing; by February 1955 they had pledges from 601 landmen at 200 companies in 21 states; and the first annual meeting of the American Association of Petroleum Landmen opened in Fort Worth on April 28, 1955 with 1,000 registered members [14], [25]. A charter member remembered the motive: “We were called lease hounds, and we detested that” [25]. The association then did what professions do. Its Form 610 operating agreement appeared in 1956, with editions in 1977, 1982, 1989 and 2015; Landman magazine in 1960; independents were admitted in 1964; the Certified Professional Landman program came in 1980; and the name changed to Professional Landmen in 1992 [14], [26], [27]. Its Code of Ethics opens with four words: “Under all is the land.” [28].
Membership tells the trade’s own history in one line: 8,045 in 1993, a low of 6,877 in 2000, 21,537 at the top of the shale boom in 2014, and 11,157 by 2024 [15]. No state licenses the occupation as such. Texas exempts the sale, lease or transfer of a mineral interest from its real estate licensing act, and Senate Bill 1172, signed May 24, 2025, widened the exemption to geothermal, solar and wind [29], [30]. New Mexico exempts persons who deal exclusively in mineral leases or mineral rights where the surface is not involved [31]. Ohio alone registers oil and gas land professionals, since 2019, on condition that they belong to a body with a code of ethics [32].
The examination itself, when it was done by hand, is best described in a 1994 Baylor Law Review article. There were two methods. In a sit-down examination the attorney read an abstract compiled by an abstract company; in a stand-up examination the landman went to the courthouse. The stand-up procedure ran in a fixed order: fix a starting point; learn the county’s index structure; search the grantee indexes backward to build the chain and the grantor indexes forward to find everything each owner did while in title; search the probate, court, financing and tax records; pull and read every doubtful instrument; and list them all chronologically with the type of instrument, the parties and the recording data [33]. That list is the run sheet. The attorney then read every instrument in it, because “the examining attorney bears sole responsibility for interpreting these instruments” [33].
Texas wrote the practice down late. The first thirty-three Texas Title Examination Standards were approved at the State Bar’s annual meeting on June 27, 1997, with Oklahoma’s standards of 1946 as a source [34], [36]. Standard 4.50, adopted in 2013, defines the tool: unless furnished an abstract, the examiner will usually prepare “a run sheet (list of instruments in chain of title)” from tract records or the clerk’s indexes, searching each grantor from the date he acquired the land forward to the date he conveyed it out, a rule the Texas Supreme Court stated in 1899 [34]. New Mexico adopted no such standards, and a 2020 comparison of the two states says so [37].
The examination served four moments, in a 2000 primer’s account: the take-off report a landman prepares before a lease is bought, the drilling title opinion, the division order title opinion that governs who is paid, and the financing opinion a lender requires [35]. In the Permian the landlord was often not a private person at all. On federal land the Mineral Leasing Act of February 25, 1920 governed, and until December 22, 1987 a lease outside a known geologic structure went to the first qualified applicant, without bidding, at a royalty of twelve and a half percent [38], [39]. That rule produced the federal lease hound and, later, a public lottery: the Bureau of Land Management’s own 1981 pamphlet reported that “roughly 4 million people filed for about 7,000 tracts” in 1979, at ten dollars a card [40]. The 1987 reform act replaced the drawing with competitive sales, now held at least quarterly at a royalty of not less than 12.5 percent and a minimum bid of ten dollars an acre [39]. On May 20, 2026 the quarterly sale for New Mexico and Texas returned $4,007,944,870 on 33,530 acres, which is $119,533 an acre, computed by The Ledger [41].
On state land the root of title is the State’s own lease. The Enabling Act of June 20, 1910 gave the future state sections two, sixteen, thirty-two and thirty-six of every township in trust, to be sold or leased only to the highest bidder at public auction after ten weeks’ notice [42]. The State Land Office sells leases on the third Tuesday of every month. Its July 21, 2026 sale moved eleven tracts for $23,742,808 on 2,577.96 acres, with a high bid of $4,801,500 for the southeast quarter of Section 2, Township 23 South, Range 35 East, which is $30,009.38 an acre, computed by The Ledger [43], [44]. Senate Bill 23 of 2025 raised the royalty on premium tracts to one fourth for leases issued on or after July 1, 2025 [45].
Nothing in that chain has been repealed. The clerk still records by time and indexes by name; the tract index is still someone’s private property; the lease is still a printer’s descendant; the State and the United States are still the landlords on most of the productive acreage; and the question the founders of 1955 wanted answered before they would drill is the one the first page of any Eddy or Lea County chain still poses. Who was given what, and what was kept? The answer has always been in the book. The labor of reading it, one name at a time, is what changed the cost of the answer. The record never changed.
The newest hard month in the federal record is May 2026, released July 31. It shows the United States pumping 13,714 thousand barrels a day, New Mexico posting its largest month ever, and crude exports at a record. Here is where the barrel goes, and what a gallon in Carlsbad is made of.
Three releases make up the season’s record. The Energy Information Administration’s Petroleum Supply Monthly for May 2026 was released on July 31, 2026; its Weekly Petroleum Status Report for the week ending August 21 was released on August 26, 2026; and its Short-Term Energy Outlook was released on August 11, 2026, with the modeling closed on August 6 [46], [47], [48]. The monthly is the hard number. In May the country produced 13,714 thousand barrels of crude a day, and New Mexico produced 2,394 of them, 74,229 thousand barrels for the month, the largest monthly volume in a state series that begins in 1981 [49], [50]. Texas produced 5,802. Together the two states supplied 59.8 percent of the nation’s crude, computed by The Ledger from the state table, a figure that is not the Permian, because it also counts the Eagle Ford, the Texas Gulf Coast and the San Juan Basin [49].
The Permian itself is a little under half the country. The Outlook’s regional table puts Permian production at 6.81 million barrels a day in the second quarter of 2026 against a national 13.82, which is 49.3 percent, computed by The Ledger; the share was 48.6 percent for 2025 and is forecast at 49.7 percent for 2027, when the region is expected to produce 7.03 million barrels a day [51]. The table’s own footnote matters for anyone quoting it: the regional figures are geographic, not geologic. On the geologic basis, Permian tight-oil formations produced 6.16 million barrels a day in the same quarter, and the difference is conventional production inside the same counties [52]. The weekly estimate for the week ending August 21 was 13,843 thousand barrels a day, and the Outlook expects 13.8 million for the year and 14.2 million in 2027 [48], [53].
Imports are Canadian and heavy. The country imported 5,953 thousand barrels of crude a day in May, down from 6,257 in April, and Canada sent 3,884 of them, 65.2 percent, computed by The Ledger [55]. The next largest suppliers were Venezuela at 471, Mexico at 276, Guyana at 239 and Ecuador at 183. The Persian Gulf, disrupted at the Strait of Hormuz since the end of February, sent 186: Saudi Arabia 103, Iraq 71 and Kuwait 12, or 3.1 percent of the total, after Saudi shipments had run near 490 a day in February and March [55], [56]. The agency’s own explanation for the Canadian barrels is a matter of machinery: “relatively complex U.S. petroleum refineries tend to prefer heavy crude oils” [57]. Nearly half of all imported crude lands in the Midwest, whose refineries took 2,816 thousand barrels a day in May, 47.3 percent of the national total, computed by The Ledger [58].
Exports are the other half of the ledger, and the reason a Permian barrel has a world price. Crude exports were 5,728 thousand barrels a day in May, the highest monthly figure on record; the agency had already called April’s 5,593 a record, 21 percent above the previous high of December 2023, and May exceeded April by 135 [59], [60]. Total exports of crude and products were 13,540 thousand barrels a day, which leaves 7,812 of products, computed by The Ledger: propane 2,023, distillate 1,655, normal butane 893, finished gasoline 806, ethane 717 [61]. The crude went to the Netherlands (1,174), Japan (1,084) and South Korea (829); none went to China in March, April or May [59]. In the week ending August 21 the country was a net exporter of 3,785 thousand barrels a day of petroleum, entirely on products, since crude alone was still a net import of 2,366 [62]. The legal basis is one sentence of the United States Code, enacted December 18, 2015: no federal official “shall impose or enforce any restriction on the export of crude oil” [63].
Refineries are running near their limit. In the week ending August 21 they ran 17.4 million barrels of crude a day at 97.4 percent of operable capacity; the Gulf Coast ran 9,520 thousand barrels a day at 97.0 percent, and the Rocky Mountain district ran at 101.4 percent, which the agency explains as gross inputs divided by the latest reported monthly capacity [65], [66]. The domestic share of the crude inside them is the number a reader in Carlsbad wants. It can be computed three ways from the record. In May, refinery inputs of 16,787 thousand barrels a day against imports of 5,953 give a foreign share of at most 35.5 percent and a domestic share of at least 64.5 percent, computed by The Ledger [54]. In the August week, inputs of 17,393 against imports of 6,158 give 64.6 percent [62], [65]. On the receipts basis for calendar 2025, refineries received 3,923,647 thousand barrels of domestic crude out of 6,116,682, or 64.1 percent [67]. Three methods, three periods, one answer: about two thirds.
The district matters more than the nation. The agency files New Mexico in the Gulf Coast district, not the Rockies, and Gulf Coast refineries received 77.1 percent of their crude from domestic sources in 2025, the highest of the five districts; the Midwest, which takes the Canadian barrels, was at 54.1 and the East Coast at 20.0 [67], [68]. New Mexico has one refinery, HF Sinclair’s Navajo plant at Artesia, in Eddy County, rated at 110,000 barrels a calendar day, against a state production of 2,394 thousand barrels a day: one barrel in twenty-two stays home to be refined, computed by The Ledger [49], [68], [69]. The agency publishes no crude slate for the plant and has discontinued the state-level gasoline sales series that would have said where the rest of the gallon came from [70]. What can be said from the record is this: a Carlsbad gallon refined at Artesia is predominantly Permian crude, the defensible published number for its district is three quarters domestic, and for the nation two thirds. Crude was 51.9 percent of a $4.479 gallon of regular in May; domestic crude on the Gulf Coast slate is therefore about forty percent of the pump price, and everything else in the gallon, refining, distribution and taxes, is spent in the United States, computed by The Ledger [71].
The cause of the season’s prices is named in the Outlook. Crude and liquids through the Strait of Hormuz averaged 4.9 million barrels a day in the second quarter against 21.6 in the last quarter of 2025; Brent reached $105 on July 23; production shut-ins averaged 5.5 million barrels a day in July; and the agency assumes the constraints persist through August [48]. West Texas Intermediate was $87.21 a barrel on August 21, 2026, $23.13 above a year earlier; regular gasoline was $4.085 a gallon on August 24, $3.638 on the Gulf Coast and $4.359 in the Rockies [64], [72]. The Outlook’s annual averages, $80.88 for WTI and $3.78 for gasoline in 2026, are annual averages and read lower than the August observations for that reason [73]. The Strategic Petroleum Reserve held 289.7 million barrels on August 21 against 404.2 a year earlier [64].
For Eddy and Lea counties the money moved from the wellhead to the lease. The State Land Office’s fiscal 2026 statement, updated August 5, 2026, shows oil and gas royalty at $1,910,113,810, down $510,319,418 from fiscal 2025, while oil and gas bonuses, paid at the instant a lease issues, rose from $40,816,418 to $542,764,425 [74]. The grand total was $2,633,791,490.64, up 1.7 percent, computed by The Ledger: leasing money replaced production money almost dollar for dollar. The office notes that royalty distributions are accounted for three months after product sales occur, so the royalty line lags the price by a quarter [74]. The federal side ran the same way. The three 2026 sales that included New Mexico parcels took in $4,473,777,851 on 130 parcels and 74,263 acres, computed by The Ledger, and the Bureau of Land Management states that the rate on new federal onshore leases is now 12.5 percent, lowered from 16.67 by the 2025 tax law [41], [75], [76]. The state’s August consensus estimate assumes New Mexico oil at $75.50 a barrel and 875 million barrels in fiscal 2027, and puts the state’s exposure in one line: a one-dollar change in the annual average price moves total state revenues by about $56.45 million [77].
A beginning, not an end. The June monthly, released August 31, 2026, answered two of the three questions May left open: crude exports fell back to 4.7 million barrels a day, and New Mexico’s June came in at 71.0 million barrels, 2.37 million a day, below May’s record; Persian Gulf crude arrived at 113,000 barrels a day, the lowest month in the series [46]. The September 9, 2026 Outlook will revise the forecast [48]. What the record shows next is what the strait carried in September, and whether May was the peak. The record will say.
The market that prices a Permian barrel was assembled in a handful of dated moves, and in 2026 it absorbed the largest supply disruption in its history. The outlooks that follow it disagree by ninety million barrels a day about 2050. The lease does not.
On March 11, 2026 the International Energy Agency announced the sixth collective action in its history: thirty-two member countries would release 400 million barrels from their stocks, the largest such release ever made, in response to the closure of the Strait of Hormuz that had followed the military action of February 28 [78]. By March 19 the confirmed contributions came to 426 million barrels, 172.2 million of them from the United States [79]. The agency’s April report called what was happening “the largest disruption in history” [80]. Twenty million barrels a day of crude and products had moved through the strait in 2025, about a quarter of the world’s seaborne oil trade; by early April loadings were about 3.8 million a day, a fall of 81 percent, computed by The Ledger [78], [80]. That is the event this section reads: a supply shock, measured in barrels, dollars and days.
The price did what a supply shock does. Brent futures began the year at $61 a barrel, passed $100 on March 12 and ended the quarter at $118, the largest inflation-adjusted quarterly rise in data back to 1988 [81]. The weekly spot average peaked at $124.61 in the week ending April 10, fell to $69.70 in the week ending July 3 after a reopening agreement, and rose again to $96.12 by July 24 after hostilities resumed on July 7 and 8; on August 25 Brent closed at $88.24 and West Texas Intermediate at $83.90 [82], [83], [84]. War-risk cover on a tanker entering the Gulf reached 2 to 6 percent of hull value in July [85].
The shock was absorbed by stocks, by ships and by the United States. The Strategic Petroleum Reserve fell from 415.4 million barrels on February 27 to 289.7 million on August 21, a draw of 125.7 million, computed by The Ledger [86]. American petroleum exports set a record of 13.6 million barrels a day in April, with crude at 5.6 million, propane above two million for the first time and distillate at its highest since 2017, and the agency attributed the record to the disruption [87]. By late August the strait was partially open, not reopened: about five to seven million barrels a day were moving through it, a quarter to a third of the 2025 rate, computed by The Ledger [78], [88]. The three agencies that forecast demand read the year three ways in the same week of August: the IEA at 1.6 million barrels a day below 2025, the Energy Information Administration at 1.25 million below, and OPEC at 0.58 million above [89], [90], [91]. Any sentence that reads 2026 as structural decline is unsupported by all three.
The market that absorbed it was built in a few dated moves. Iran, Iraq, Kuwait, Saudi Arabia and Venezuela created the Organization of the Petroleum Exporting Countries at Baghdad on September 10 to 14, 1960 [92], [93]. On October 17, 1973 six Gulf members raised the posted price seventy percent, from $3.01 to $5.12 a barrel, and two days later the embargo on the United States began; by the time it ended in March 1974 the price had gone from $2.90 to $11.65 [94], [95]. The second shock followed the loss of Iranian output in 1979, and the average price American producers received climbed from $9.00 in 1978 to $31.77 in 1981, then collapsed to $12.51 in 1986 [96], [97]. The paper barrel arrived in between: the New York Mercantile Exchange listed crude oil futures on March 30, 1983, and Brent futures opened in London in June 1988 [98], [99].
The American barrel was fenced in and then set loose. The Energy Policy and Conservation Act of 1975 directed a rule prohibiting crude exports, which the Commerce Department ran as a license regime with listed exceptions; exports under it still reached 396,000 barrels a day in June 2014, nearly all to Canada [100]. Congress repealed the restriction on December 18, 2015, and within a year Permian crude was moving by pipeline to a new export terminal at Ingleside on Corpus Christi Bay, bypassing Cushing [63], [103]. The producers reorganized in the same season: the Algiers Accord of September 28, 2016, the Vienna Agreement of November 30 and the Declaration of Cooperation of December 10 created the group the agencies track as OPEC+ [101]. On April 20, 2020 the expiring West Texas Intermediate contract settled at negative $37.63 a barrel with the tanks at Cushing 76 percent full, the one day the paper barrel was worth less than nothing [102]. And in 2026 the United Arab Emirates left OPEC, effective May 1, taking 3.4 million barrels a day of 2025 production with it [104].
Where does the barrel go after the car? The outlooks answer with dates, and the dates keep moving while the level does not. In October 2020 the International Energy Agency wrote that “the era of growth in global oil demand comes to an end within ten years” [107]. Its June 2023 medium-term report had demand at 105.7 million barrels a day in 2028; its June 2024 report had 105.4 in 2030; its June 2025 report, the latest, has a plateau around 105.5 by 2030, with combustible demand peaking as early as 2027, refined products peaking that year at 86.3 million barrels a day, and polymers and fibers needing 18.4 million barrels a day by 2030, more than one barrel in six [108], [109], [110]. Its own April 2026 review records 2025 demand still growing, by 0.65 million barrels a day [111]. The World Energy Outlook of November 2025 brackets 2050 between 102 million barrels a day under stated policies, with demand levelling off around 2030, and 113 under current policies, carried by petrochemical feedstocks, aviation and trucks [112].
The industry’s own outlooks bracket the agency’s. ExxonMobil’s, published August 28, 2025, has about 105 million barrels a day in 2050 [113]. bp’s has oil returning to about today’s level by 2035 and 83 million barrels a day in 2050 on its current trajectory, with feedstock rising from about 15 percent of the barrel in 2023 to close to 30 percent, and 34 million barrels a day in a below-two-degrees case where feedstock is about 45 percent [114]. OPEC’s World Oil Outlook of June 18, 2026 has about 124 million barrels a day in 2050 and “no peak demand on the horizon” [115]. The Energy Information Administration’s last international outlook, from 2023, keeps transportation at 54 percent or more of liquid fuels in 2050 in every case it runs [116]. No base case among them has oil ceasing to be mainly a transport fuel by 2050, and every one of them has the burned barrel peaking first and the feedstock barrel lasting longest. The Permian sits at 6.7 percent of the world’s liquids supply in 2026, computed by The Ledger from the agency’s tables, and it is the country’s ethane [51], [90], [105].
Which brings the question to the lease. A Permian barrel sold to a cracker at Corpus Christi and a Permian barrel sold to a refinery hold the mineral leasehold identically, because the lease conditions on production of the substance and never on its buyer. The New Mexico Supreme Court read the habendum in 1922 as a term for as long thereafter as oil or gas is produced [117]. Texas read “produced” to mean produced in paying quantities in 1942, and in 1959 defined paying quantities as “a return in excess of operating costs, and marketing cost,” judged by a prudent operator whose factors include the price obtainable, never the purchaser’s industry [118], [119]. A well with no market or no pipeline is held by a shut-in royalty, a condition precedent with hard dates: a $50 tender made seventy-two days after the term expired was too late in Texas in 1960, and a New Mexico lease dated September 1, 1950 died on January 1, 1957 when production ceased and neither drilling nor the shut-in payment followed [120], [121]. The implied covenant to market asks for diligence and the best current price reasonably available, and in Texas “the reasonably prudent operator concept is an essential part of every implied covenant” [122], [123]. A lower feedstock netback would be tested there, as price, not as a change in the estate.
Where the end use can bite is valuation. Texas nets post-production costs against a royalty payable at the well, and in 1996 held that a lease’s post-production clauses merely restate existing law [125]. New Mexico’s Court of Appeals let compression, dehydration and gathering be deducted in 2000 because the gas was marketable at the wellhead, and in 2018 the Tenth Circuit found that the marketable-condition rule “finds no support within New Mexico case law” after the state’s Supreme Court had twice reserved the question [126], [127]. The regulators police the well, not the buyer. New Mexico’s rules define oil and gas by their physical state and a shut-in well by physical closure, and after one year of inactivity require the operator to plug or obtain temporary abandonment [128], [129]. Texas defines an inactive well as one with no permitted activity for more than twelve months, and sets its reactivation thresholds in barrels, not in buyers [130], [131]. A non-fuel end use has already run on ordinary lease machinery for fifty years: the Bravo Dome leases of 1971 to 1974 over about 1.17 million acres in Harding, Union and Quay counties produced carbon dioxide piped to West Texas oil fields, and the Tenth Circuit treated them as oil and gas leases in 1990 [132].
So the title question the market brings with it is a quiet one. When the last gallon of gasoline has been sold, the instrument in the Eddy County clerk’s book will still read as long thereafter as oil or gas is produced, the shut-in royalty will still be due on the anniversary, and the examiner opening the chain will still find the same lease, the same assignments and the same releases, none of which say what the barrel was for. The buyer changes. The record does not.
Archive builds title from the record: an automated title examination platform for the Permian Basin, beginning with Eddy and Lea counties, New Mexico. The Ledger is published at archiveledger.com.
Typeset in DM Serif Display, Inter and JetBrains Mono. Figures drawn by Archive. Membership and certification counts from the American Association of Professional Landmen’s audited annual report. Supply, import, export, refinery and price data from the U.S. Energy Information Administration; state revenue from the New Mexico State Land Office and Legislative Finance Committee; lease-sale figures from the Bureau of Land Management. Outlook figures are the projections of their issuers and are labeled as such.
The Ledger is an editorial publication of Archive Ledger, Inc. It is not legal advice, and it is not a title opinion. Every claim of fact is tied to a numbered source; corrections are welcome at archiveledger.com.
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