[Editor's note: A version of this story appears in the February 2019 edition of Oil and Gas Investor. Subscribe to the magazine here.]

For the most part, 2018 was a good year for producers.

Oil was on a steady rise and most plays were in the money. Natural gas prices remained capped for much of the year as production increased, but new demand seemed to be available as needed. As the industry approached year-end, oil swooned and gas excelled.

Producers scratched their heads, however, over the apathy on Wall Street toward oil and gas stocks. Despite robust economics in the oil patch, investors only wanted evidence of cash flows that resulted in shareholder returns, and, even then, weren’t overly enthused. Public investors’ shunning of E&P equities trickled down to the private-operator world, which struggled to find an exit in the markets.

And it wasn’t just the commodity markets and the financial markets exhibiting volatility—the industry’s trust of President Trump championing hydrocarbons took a hit when trade wars and tariffs took a bite out of their profits. And, with product flowing from re-activated plays, anti-hydrocarbon activists took aim at the industry by blocking pipelines at the regulatory level and blaming climate change on producers at the court level.

Here, Oil and Gas Investor chronicles the highlights of the year in energy.

Shale vs. OPEC

Oil-Price Roller Coaster

Oil in the $70s? It happened. In fact, Brent surpassed the $80 mark in May a first time in three years. But what the markets so briefly giveth, they also taketh away.

Producers breathed easy as West Texas Intermediate (WTI) crossed $60 going into 2018 and continued on an upward trend, throwing off the doldrums of a recent prolonged downturn. Buoyed by OPEC’s and Russia’s cut to daily production by 1.2 million barrels instated in late 2016, strong global demand and geopolitical tensions further fueled the climb.

Market-watchers gazed helplessly as Venezuela’s daily production plummeted more than 500,000 barrels amidst political and economic turmoil, and the U.S. promised to re-impose sanctions against Iran as President Trump exited the seven-nation nuclear agreement, creating uncertainty around supply. Add to that a trade skirmish between Washington and China.

OPEC, meanwhile, following its June meeting, began a systematic unwinding of its 18-month-old production cut by adding up to 1 million barrels per day (bbl/d) to the global supply, declaring the oil glut resolved. Members Iraq and Libya quickly filled any gap in supply made by Venezuela or Iran.

U.S. producers took advantage of the favorable price environment to ratchet up activity. By August, U.S. crude production surpassed 11.3 million bbl/d, according to the Energy Information Administration (EIA), the first time production had exceeded 11 million bbl/d. That number topped Russia’s estimated 11.2 million bbl/d, “making the U.S. the leading crude oil producer in the world,” the EIA reported, with Saudi Arabia in third. Likewise, in August, global oil and petroleum-liquids supply surpassed 100 million bbl/d for the first time ever, according to the International Energy Agency.

The rise in the oil price sparked the ire of President Trump, concerned about how higher gasoline prices would affect midterm elections within his base. He publicly lashed out at OPEC, tweeting “Looks like OPEC is at it again. Oil prices are artificially Very High! No good and will not be accepted!” Speaking before the UN, Trump continued his attack on OPEC, saying it is “ripping off the rest of the world” with “these horrible prices.”

In September, Saudi Arabia and Russia quietly met and agreed to increase production through year-end to cool prices, according to Reuters, but the chilling effect was unexpected. WTI crested above $75 and Brent above $85 in early October, but that was the end of the prolonged rally. Also, in October, the Trump administration released 11 million barrels from the Strategic Petroleum Reserve in advance of sanctions on Iran that were to take effect in November.

The result? WTI began a three-month freefall that would bottom at $42 on Christmas Day, ending the year at $45. Brent exited the year at $53.

In an effort to wrench the tumble, OPEC and Russia in December agreed to new production cuts just six months after loosening the valves. Despite the pain felt by jolted U.S. independents, one thing is certain: Trump got his wish for lower prices at the pump.

Load It Up And Ship It Out

It’s truly a global market. With oil production surging in the U.S., exports surpassed 2 million bbl/d in 2018, and that from a standstill as recently as 2015. Following a nearly 40-year moratorium on exports, the more than 11 million bbl/d that were flowing in 2018 from U.S. fields—driven by the shale plays—would not have been possible.

Notably, the U.S. port district of Houston-Galveston in Texas that includes Corpus Christi and represents about half of U.S. crude exports, began exporting more than it imported for the first time on record, according to the EIA in an August report. “In April 2018, crude oil exports from Houston-Galveston surpassed crude oil imports by 15,000 [bbl/d]. In May 2018, the difference between crude oil exports and imports increased substantially to 470,000 [bbl/d].”

But the ports are reaching maximum capacity. Anticipating some 2 million barrels of additional daily pipeline capacity aimed at the Gulf Coast within a couple of years, investors lined up plans for multiple new terminals to reach waterborne markets—and specifically those that can accommodate very large crude carriers (VLCCs). Only one such port exists thus far in the U.S.—the Louisiana Offshore Oil Port (LOOP).

Companies such as Trafigura Group Pte. Ltd., Enterprise Products Partners LP, Enbridge Inc., Buckeye Partners LP, Tallgrass Energy LP, JupiterMLP LLC and Moda Midstream LLC announced investments to welcome VLCCs to U.S. shores.

Can You Spare $11 Trillion?

Call it biased, but OPEC, in its “2018 World Oil Outlook,” reported that the oil and gas industry will need an additional $11 trillion during the next 20 years to keep up with anticipated growth in oil demand. Despite a growing market for electric vehicles (EVs), it expects the overall, global vehicle fleet itself to double, led by Asian countries; EVs would account for a 13% share. OPEC projects global oil demand to be 112 million bbl/d in 2040, although the growth trajectory will be steepest in the earlier years and tapering. “It is vital that, as an industry, we ensure there is timely and adequate investment so as not to lead to a supply shortage in the future,” OPEC Secretary-General Mohammad Barkindo said in the report.

O (No!) Canada!

While WTI soared past $70, Western Canadian Select (WCS) fell to $26 in October, a more than $40 discount to WTI, severely constricting Canadian producers’ profits. What’s the rub? Not enough pipe to handle growing production, combined with U.S. refineries in the Midwest undergoing maintenance. Current capacity out of the Western Canadian Basin is about 4 million bbl/d, and current production is closer to 4.4 million bbl/d, according to IHS Markit, as reported in the Calgary Herald.

“It’s a crisis,” Tim McMillan, CEO of the Canadian Association of Petroleum Producers, told the Herald. “When we were canceling pipeline projects over the last decade, this was the end result we should have expected.”

Where’s that Keystone XL pipeline when you really need it? Oh, yeah—that one, too, is still facing regulatory hurdles after 10 years.

Iran Offline—Or Is It?

After worrying much of the year about the consequences of pulling some 4 million bbl/d of Iranian oil off the market, the U.S. in November reinstated sanctions against Iran that had been lifted as part of an Obama administration multinational deal. But rather than cause a price spike, crude was already in a downward glide that didn’t blink with the enactment. Possibly, waivers—granted to eight countries to bypass the sanctions and still receive crude from Iran—softened the supply hit. The waivers are for six months.

Caution Executed

As the year waned, U.S. shale producers hit the brakes on 2019 spending projections with crude prices off 40% and mounting fears of oversupply, paring budgets that in some cases were set only weeks earlier. Production was expected to rise 11% in 2019 as large oil firms and independents add wells this year. Shale producer Centennial Resource Development Inc. on Dec. 20 joined Diamondback Energy Inc. and Parsley Energy Inc. in canceling 2019 rig additions.

Natural Gas

The Gas Conundrum—Where Is It All Going?

The central point about natural gas in 2018 came through loud and clear: U.S. producers continued to dial up production in a big way, and while demand grew, storage volumes did not. In fact, as Lower 48 dry-gas production rose to an all-time high beyond 80 billion cubic feet per day (Bcf/d), a reflection of the enormous resources at hand, gas in storage at the end of December totaled only 2,705 Bcf—some 560 Bcf below the five-year average.

Where did all that incremental gas go? To numerous Gulf Coast petchem expansions, increased gas-fired power generation, Mexico, and, especially, LNG exports.

As 2017 turned into 2018, the U.S. had become a net gas exporter for the first time in 60 years, and, by Christmas 2018, total feedgas supply to export facilities was nearly 5 Bcf/d, according to RBN Energy Inc. Five trains were producing in the U.S. and four more were in the testing or commissioning stage in preparation for exports starting in 2019.

By October, net U.S. gas exports were some 3 Bcf/d, compared with 1 Bcf/d in October of 2017 and net imports of nearly 2 Bcf/d in October of 2016, according to EIA data.

In his January 2018 State of the Union speech, President Trump crowed about U.S. oil and gas exports, saying they are a national priority. Later in November, while on tour in Europe, Energy Secretary Rick Perry touted U.S. LNG to allies. Indeed, during the year, U.S. LNG made its way to receiving terminals in Poland, Greece and the U.K., among other destinations.

The U.S. set new records for gas-fired power generation. And even industrial consumption jumped to 20 Bcf/d, also a record.

Permian associated-gas production grew rapidly to about 11 Bcf/d, but that was a good-news-bad-news story. The spread between the Waha hub in the Permian and Agua Dulce on the Gulf Coast widened to more than $2/Mcf, putting Permian gas at a steep disadvantage compared with South Texas gas, while producers awaited more takeaway.

Less gas in storage by year-end meant greater demand is soaking up much of the supply increase. Entering November, the prompt-month contract spiked to nearly $5 per million Btu (MMBtu) as freezing temperatures set in across the country—even in Houston.

But prices tapered back to about $3 as the year ended. Who can forget New Year’s Day 2018? That’s when the U.S. burned the most natural gas ever, consuming 143 Bcf as an Arctic blast swept the country—but prices failed to react.

“Rarely has the natural gas business offered so much promise with so little reward,” the Houston Chronicle complained at the time.

The average Henry Hub price in 2018 was $3.16 per MMBtu—up 15 cents from the 2017 average—according to the EIA.

Two More For The Demand Side

Dominion Energy Inc.’s Cove Point, Md., terminal loaded a first LNG carrier at the nation’s second major export terminal. Nameplate capacity is 5.25 million tonnes per annum (mtpa). A Singapore-flagged, Royal Dutch Shell Plc-owned LNG tanker left the port in March from the $4 billion terminal, which began producing LNG in late January but had faced a delay on making its first delivery.

The first shipment went to Yokohama, Japan. Some 1.4 mtpa will go to Tokyo Gas Co. Ltd. in a 20-year contract, with 0.8 mtpa going to Kansai Electric Power Co. Inc. via Sumitomo Corp. “Today marks an important day, not just for Cove Point, but for the U.S. LNG industry," said Charlie Riedl, executive director of the trade group Center for LNG. Cove Point is now exporting about 0.7 Bcf/d.

In December, Cheniere Energy Inc., already with five trains operating at Sabine Pass, La., shipped the first-ever cargo of LNG from Texas—with Greece as consumer on the receiving end. LNG production at Cheniere’s Corpus Christi Train 1 had started in November. The LNG-export facility is the first built in the Lower 48 on greenfield property—that is, not alongside a pre-existing LNG-import facility.

Meanwhile, the Federal Energy Regulatory Commission (FERC) recently approved Cheniere’s request to commission Train 2 at Corpus Christi, and the company announced its final investment decision (FID) in May to build a third train there that is expected to be in operation in 2021.

It also unveiled plans for another train, number six, at Sabine Pass, Louisiana, where it shipped its first LNG, from Train 1, in 2016. Competing providers Tellurian Inc. and Freeport LNG Development LP also progressed on their projects in 2018, announcing FIDs and sales agreements with key buyers. The first Freeport train is expected to be in operation in the second quarter of this year.

LNG Canada Gets Green Light

Royal Dutch Shell Plc and partners Petronas, Mitsubishi Corp., PetroChina Corp. and Korea Gas Corp. gave the go-ahead for a huge LNG export project in Kitimat, British Columbia—the largest new project of its kind in years at 14 mtpa. The facility would benefit from having a faster delivery route by 50% to Asian buyers than any competing project whose LNG has to go through the Panama Canal. Wood Mackenzie reported the facility would be the biggest greenfield project to be sanctioned since Yamal LNG in Siberia in 2013, and is the first LNG export project to reach FID in Canada ever. “It seems that megaprojects are back,” said Dulles Wang, director of natural gas, WoodMac.

A Fast Track For The Small Batch

The House passed a bill that would expedite small-scale gas exports, codifying a Department of Energy (DOE) rule finalized in 2018. It would allow the DOE to automatically approve applications to export 0.14 Bcf/d or less, if they do not require an environmental assessment under the National Environmental Policy Act. The bill’s backers say it would create more regulatory certainty for companies looking to export LNG to smaller, emerging markets in the Caribbean and elsewhere.

Stay Thirsty, My Friend—For U.S. Gas

The EIA reported exports of U.S. gas to Mexico reached an all-time high of about 6 Bcf/d in August, with roughly 5.1 Bcf shipped via pipeline and 860 million cubic feet (MMcf) via LNG. Mexico’s gas demand has continued to climb while its production continued to fall, as lower commodity prices and budgets limited drilling new wells.

The EIA reported that the country’s dry-gas production was down 7% year-over-year to 2.4 Bcf/d in October. At the same time, the EIA forecast U.S. exports will average 5.5 Bcf/d to Mexico via pipeline in 2019.

Howard Midstream Energy Partners LLC placed in service its Nueva Era pipeline to Mexico from South Texas in July, with capacity of 630 MMcf/d.

The Mexican state of Sonora signed a nonbinding agreement with Arizona and New Mexico to interconnect existing gas pipelines, allowing gas from the San Juan Basin to supply a proposed export terminal on the Gulf of California in Mexico.

Under the agreement, the three parties would promote investment and research that could lead to LNG being exported from Mexico’s west coast to Asia. Mexico Pacific Ltd. LLC would export up to 1.7 Bcf/d via an LNG facility planned in Sonora, with supply coming from the Permian and San Juan basins, the Eagle Ford and the Barnett shales.

The new facility would be adjacent to the Infraestructura Energetica Nova (IEnova) Sonora Pipeline, and benefit from “multiple natural gas supply routes, allowing both Henry Hub and Waha gas to be efficiently supplied to the site,” according to the project website.

Russia To The Rescue?

One might question why a Russian tanker carrying natural gas from Siberia would need to supply the U.S. Northeast when 31 Bcf/d is currently being produced just 400 miles west in Appalachia. It did happen. Twice.

With New England supplies depleted by a severe cold snap into early 2018, the Gaselys, carrying LNG from the giant Yamal LNG plant in the Russian Arctic, offloaded its cargo in Boston in late January. Another load arrived in February.

New England doesn’t usually get its gas from Russia, according to The Boston Globe. The terminal received five prior winter LNG shipments from Trinidad.

“This is what happens when you don’t build your own natural gas pipelines, which are the safest and most economical way to transport energy,” said Mark J. Perry, a blogger for think tank The American Enterprise Institute.

The incident caused an awkward moment for President Trump while speaking overseas, when asked by a journalist about being hypocritical: Trump has loudly criticized Germany for accepting Russian gas.

Trump

Trade War—Energy’s Friend or Foe?

Donald Trump burst into the White House in 2017 as a champion of energy, particularly oil, gas and coal, and his agenda into 2018 continues with a plethora of regulation rollbacks of Obama-era regulations that the industry felt to be death by a thousand cuts. But Trump, certainly, is unpredictable and volatile in his methods, and where he swings in favor of oil and gas in one move, he leaves a black eye with others.

Such is the case with steel. In March, Trump fired the first shot in a global trade war by imposing a 25% tariff on steel imports and 10% on aluminum in an effort to revive those industries domestically. “Trade wars are good, and easy to win,” he tweeted.

But the oil and gas industry was caught off guard—as a voracious consumer of steel in the form of drill pipe, rigs, pipelines, storage tanks, processing units, pumpjacks, even LNG-export facilities. Industry leaders tried, with limited success, to be exempted from the tariffs.

When allies Canada, Mexico and the European Union became subject to the pinch in May, American Petroleum Institute CEO and president Jack Gerard lashed back. “We are deeply discouraged by the administration’s actions to impose tariffs on our three closest trading partners … and view this as a step in the wrong direction.

“The implementation of new tariffs will disrupt the U.S. oil and natural gas industry’s complex supply chain, compromising ongoing and future U.S. energy projects.”

Ed Longanecker, president of the Texas Independent Producers & Royalty Owners Association, said, “These tariffs on imported steel and aluminum have been described by many as effectively a tax against U.S.-based producers, large and small, adding significant cost on a per-well basis and a punitive tax of tens of millions of dollars to some critical infrastructure projects.”

Andy Black, CEO of the Association of Oil Pipe Lines, accused Trump of killing U.S. jobs, to no avail. The fight continued.

While China represented just 3% of steel imports, trade relations with the country was a particular point of contention with Trump. When he imposed a 10% tariff on an additional $250 billion in goods, China fired back, slapping duties on additional U.S. goods. Oil and gas once again got stung.

The tit-for-tat resulted in China taxing U.S. LNG cargoes a 10% duty, less than the 25% threatened but still striking at Trump’s use of energy for dominance. If left unresolved, the trade war could imperil the construction of 20 LNG projects in the U.S. that have been approved or proposed but are not yet under construction.

The year ended in a 90-day trade truce with China, following a meeting between Trump and Chinese President Xi Jinping. But Trump, who proclaimed himself “Tariff Man,” promised more duties if talks didn’t pan out.

Energy Cabinet Overhaul

The year started with at least four faces familiar to the oil and gas industry occupying high-level cabinet positions within the Trump administration. When the year ended, only Energy Secretary (former Texas governor) Rick Perry remained. Along the way, Secretary of State (former Exxon Mobil Corp. chairman and CEO) Rex Tillerson, EPA Administrator (former Oklahoma attorney general) Scott Pruitt and Interior Secretary Ryan Zinke had exited.

Tillerson was first, resigning in March. Trump publicly undercut Tillerson’s diplomatic initiatives numerous times, including when his comments about Russia appeared to be at odds with those of the White House.

On July 5, Pruitt handed in his resignation, and Deputy Administrator Andrew Wheeler took his place. Pruitt was one of Trump’s most polarizing Cabinet members, slashing regulations on the energy and manufacturing industries, including a move to repeal former President Obama’s signature program to cut carbon emissions from power plants, dubbed the Clean Power Plan. He was also instrumental in lobbying Trump to withdraw the U.S. from the 2015 Paris Agreement that is to attempt to combat global warming.

But a string of controversies eventually caught up to Pruitt.

Wheeler, a former mining-industry lobbyist, has kept up the policies started under Pruitt. At the time, Matt Dempsey, an energy lobbyist at consultancy FTI, said Wheeler will be less controversial than Pruitt but without altering the agenda. That prediction has proved true, so far.

In December, Zinke, also mired in controversy, resigned from the Department of the Interior. While in office, Zinke pared national monuments in Utah and pushed for drilling offshore Alaska and the Pacific and Atlantic coasts.

Trump’s New NAFTA

As the trade kerfuffle with China caused angst, the skirmish with Mexico and Canada created heartburn in the energy world as well. Trump characterized the long-standing North American Free Trade Agreement (NAFTA) as “the worst trade deal ever made.”

Unfortunately, a lot of hydrocarbon flows to and fro the southern and northern borders, and industry went about protecting its interests amidst the bigger fray. The American Petroleum Institute, along with its counterparts in Canada and Mexico, released a joint statement insisting that “NAFTA works” and “do no harm.”

“Since its inception in 1994, NAFTA has facilitated the greater flow of oil, natural gas and derived products to and from all three countries. As a result, today the U.S., Canada and Mexico together are a unique global energy center.”

In October, after much public bluster among the countries, Trump revealed the United States-Mexico-Canada Agreement (USMCA), which resembled a lot of the old NAFTA with tweaks.

While the USMCA, also known as the “new NAFTA,” largely focused on the automotive industry, some provisions were wins for the oil and gas industry that promise to spur further investment, exploration and production. The new framework requires that the U.S. government automatically approve any gas exports to Mexico.

Meanwhile, a dispute-resolution process that allows multinational corporations to sue governments over regulatory changes has been preserved for the oil and gas industry, prompting objections from environmentalists.

In the end, the product still flows, both north and south.

Biggest Lease Sale Ever

In March, the Interior Department conducted the largest-ever lease sale in U.S. history, offering some 77 million Gulf of Mexico acres. Despite the bounty, bids were accepted on only 815,000 acres, garnering $125 million. Post-downturn capital caution, offshore’s costs vs. shale, and energy-investor apathy all played into the anti-climactic conclusion.

But in making more than less available, Trump’s policies are making a point: offer it all and let the market decide. “Today’s sale is a continuation of our all-of-the-above energy strategy,” said Vincent DeVito, counsel to the Secretary of the Interior for Energy, “and will result in responsible development of American energy resources.”

First Steps In The Atlantic

In November, and under a directive from the White House, the National Marine Fisheries Service, a division of the National Oceanic and Atmospheric Administration, issued guidelines allowing seismic surveys offshore the U.S. East Coast. The new guidelines allow surveyors “to incidentally, but not intentionally, harass marine mammals.” Five companies have applied for permits. The seismic surveys use air guns to bounce sound waves off the ocean floor, which environmentalists contend damage the hearing of sea mammals.

Come On In, But The Water’s Not Fine

Bucking decades of offshore absence along the Atlantic and Pacific seaboards as well as Alaska, President Trump’s proposed five-year offshore lease plan would open 90% of America’s coastal waters—nearly the entire Outer Continental Shelf—to oil and gas leasing.

The National Outer Continental Shelf Oil and Gas Leasing Program (National OCS Program) for 2019-2024 is in stark contrast to President Obama’s policies that banned exploration in 94% of U.S. waters.

The move pits Trump’s theme of energy dominance, by opening access to any and all reserves, against environmental protectionism, riling a number of coastal states.

The draft proposal includes 47 potential lease sales in 25 of the 26 planning areas—19 off the coast of Alaska, seven in the Pacific Region, 12 in the Gulf of Mexico, and nine in the Atlantic Region. This is the largest number of sales ever proposed for the National OCS Program’s five-year lease schedule.

“Responsibly developing our energy resources on the [OCS] in a safe and well-regulated way is important to our economy and energy security, and it provides billions of dollars to fund the conservation of our coastlines, public lands and parks,” said Interior Secretary Ryan Zinke. “Today's announcement lays out the options that are on the table and starts a lengthy and robust public-comment period.”

Robust, indeed. The announcement set off a firestorm among state and local governments opposed to drilling off their shores. In a joint statement, the governors of California, Oregon and Washington State said, “For more than 30 years, our shared coastline has been protected from further federal drilling and we’ll do whatever it takes to stop this reckless, short-sighted action.” Atlantic-side lawmakers from federal to local—both Democrats and Republicans—condemned the move as well.

Regardless of the vast bounty potentially coming available, the industry is most desirous of the eastern Gulf of Mexico offshore Florida. A plethora of known reserves and infrastructure abuts the Central Gulf region, and offshore explorers would jump at the opportunity to cross over.

The caveat: The Department of Defense uses the region for military testing and training. The other caveat: the state of Florida views any potential threat of spills or offshore visual blight to be a downer for its robust tourism trade. The state has petitioned Zinke for exemption.

The plan became a hot button in the midterm elections, even pitting some Republicans against Trump’s scheme. As a stopgap, in November, Florida succeeded in passing a ballot referendum that bans drilling in state waters within three miles of the coastline. California enacted legislation that would block any infrastructure supporting offshore drilling.

Zinke assured that, while nearly all coastal waters were put on the table, not all would make the final program. The five-year plan is due to be finalized in 2019.

Rolling Back Methane Rules

As one of his last acts in office, former President Obama, via the Bureau of Land Management (BLM), enacted the Waste Prevention Rule (also known as the Venting and Flaring Rule) to prevent methane emissions on public lands. Yet the rule was ambiguous and arduous to follow, according to industry, and puts the burden of air-quality regulation on the wrong department.

In September, the Interior Department dropped the added regulation. In a statement, the BLM reported it found “that many parts of the 2016 rule were unnecessarily burdensome on the private sector.”

Similarly, the EPA is proposing rolling back the regulations on monitoring emission leaks that were imposed in the 2016 New Source Performance Standards, also a last-second Obama move.

“These common-sense reforms will alleviate unnecessary and duplicative red tape and give the energy sector the regulatory certainty it needs to continue providing affordable and reliable energy to the American people,” said EPA Acting Administrator Andrew Wheeler.

“Removing these excessive regulatory burdens will generate roughly $484 million in cost savings and support increased domestic energy production—a top priority of President Trump.”

“America’s oil and natural gas producers understand the importance of fair, commonsense regulations,” said Independent Petroleum Association of America president and CEO Barry Russell. “But, for too long, the federal bureaucracy has buried our industry in unnecessary and often duplicative red tape.”

Oil And Parks

Drilling on public lands has faced stiff opposition in recent years, and national parks are suffering from some $12 billion in needed, but unfunded, maintenance. What better way to solve both problems than to marry them? Interior Secretary Ryan Zinke in April proposed that proceeds from drilling on federal land be a solution to the park-maintenance backlog.

The idea received rare bipartisan support, but Democrats still hesitated that the plan would incentivize drilling to keep funds flowing. The proposed solution was to earmark existing proceeds from energy production and to expand the scope to include funding for Fish & Wildlife, Indian Education and the Bureau of Land Management. The bills, with overwhelming public support, remained in the House and Senate at year-end.

FERC Turnover

At a crucial time for getting pipeline projects through the federal approval process, FERC commissioner Robert Powelson stepped down in June. The departure, less than a year into his tenure after being nominated by President Trump, left the commission with a 2-2 partisan divide. The Senate confirmed Bernard L. McNamee in December, but on Jan. 3 of this year, commissioner David McIntyre, also a Trump appointment, died following a bout with cancer, leaving another vacancy.

Money & Markets

The Big Chill

Energy investors yawned. 2018 was largely another year of investor apathy—and worse. E&P stocks lagged oil prices on the way up for most of the year. And then, after a mix of toxic factors all converged—Iranian waivers, U.S-Sino trade friction, oil-demand concerns amid slumping global equity markets, plus growing U.S. oil supply—E&P equities tumbled in a race to the bottom with crude.

Once in motion, the decline in oil prices was exacerbated by the impact of computer-driven models, especially in less liquid markets in the latter part of the year. From an early October peak of $76.40, WTI fell as much as 40% to $45.40 at year-end. One analyst attributed the last $15 or more of the decline to technical, rather than fundamental, factors.

Against the backdrop of swooning crude prices, the XOP—that is, the SPDR S&P Exploration & Production ETF—plummeted 38.5% in the fourth quarter and was down 28.1% for the year. One sell-side firm described 2018 as “an all-around horrible year” for energy.

Energy’s performance did little to attract investors, and the energy weighting in the S&P 500 fell to 5.3%, down from 6.3% as of June 30, 2018.

Obviously, market conditions—and the direction of oil prices—played a key part in capital-raising in the energy sector over the course of 2018. With WTI settling into the low to mid-$60s in early 2018, market conditions were supportive of IPOs by a handful of oilfield-service companies, including Liberty Oilfield Services Inc., FTS International Inc., Nine Energy Service Inc. and Cactus Inc. On the E&P side around midyear, Berry Petroleum Corp. broke a dry spell with a first IPO by a producer (that wasn’t as a SPAC) in more than a year.

Not surprisingly, issuance declined for both equity and fixed income as year-end drew nearer amid continued unsettled market conditions. For example, with junk-bond spreads widening to near 30-month highs, no high-yield bonds were expected to be issued in December, least of all related to energy. This would mark the first month in 10 years with no high-yield bond sales, according to Bloomberg.

Similar market conditions prevailed on the equity side. By November of last year, equity issuance had dwindled to isolated instances: a midstream follow-on, raising $40 million, and an E&P follow-on of $30 million. In December, a proposed financing through a preferred-stock issue and senior-note issue was cancelled due to the significant commodity decline “and the related adverse effect on the debt and equity markets.”

M&A

Coming Together

The watchword for M&A in 2018 was consolidation—but truthfully “mashup” described just as many of the multibillion-dollar deals that conspicuously arrived before Dec. 31. Encana Corp.’s $7.7-billion merger offer for Newfield Exploration Co. was among the “wait, what?” moments that no one had been waiting for and that many analysts, nevertheless, considered a pretty good bit of dealing.

Interest in Permian Basin consolidation had been whetted by deals in 2017, including ExxonMobil Corp.’s $6.6-billion deal to buy the Bass Cos.’ holdings and the $3.2 billion by Noble Energy Inc. to buy Clayton Williams Energy Inc.

The sparks generated by investor coaxing and near constant speculation finally caught fire in the Midland and Delaware basins, following the long Permian Basin land rush that had started to ebb in 2017. For company executives, the moves were motivated by a laundry list of needs: grow, kill off debt, and generate more cash—all while uncooperative public markets were closed to E&Ps.

The two largest U.S. E&P mergers of the year—Concho Resources Inc. with RSP Permian Inc. in July and Diamondback Energy Inc. with Energen Corp.—totaled $18.7 billion in value. Yet, for all the sound and fury over Permian team-ups, the basin ended up as just one of many. Past the Midland and Delaware, consolidation spread to other plays as oil-price volatility and investor pressure had companies looking for ways to create fortress balance sheets—in the future.

Apart from Encana’s deal in the Midcontinent, Chesapeake Energy Corp. went oily with a nearly $4-billion deal to buy WildHorse Resource Development Corp. and Denbury Resources Inc. agreed to purchase Penn Virginia Corp. for $1.7 billion. Of the seven largest mergers, totaling $34.9 billion in transaction value, three totaling $13.3 billion were outside of the Permian.

The service sector saw its share of consolidation as well. Two notable ones: Offshore contract driller Transocean Ltd. combined with Ocean Rig UDW Inc. for $2.7 billion, and Ensco Plc in October said it would buy out rival Rowan Cos. Plc in an all-stock acquisition worth about $2.4 billion.

While consolidation dominated conversations as a motivating force for 2018, it masked the undercurrent of a far less active year of small and midsize deals. While the third-quarter was one of the most lucrative in years, large-scale asset deals were the reason, including BP Plc’s $10.5-billion win of BHP Billiton Ltd.’s onshore U.S. portfolio—sans Fayetteville, which went to a privately held operator.

In the Fayetteville, Utica and Marcellus shales and in the San Juan and Permian basins, eye-popping value obscured a lull in transactions.

The deals were giant, but strangely slow-paced. The year’s magnificent third quarter, with deal value of about $32 billion, represented the highest level of quarterly value since the fourth-quarter of 2012, according to EnerCom Inc. But the values belied a stubborn slowdown in transaction volume, with 2018 on pace to be the second-slowest transactional year since 2011, according to Raymond James & Associates. In short, deals averaged about $450 million—$100 million more than in 2014—but with about 45 fewer deals compared with the previous year.

Still, M&A stayed consistent through the year, with about $61 billion in the first nine months and approached another $22 billion in the fourth quarter. Megadeals and deals of more than $500 million were transacted in nearly every established shale basin: Midland, Delaware, Eagle Ford, Williston, Scoop/Stack, Utica and the Fayetteville.

Similar transactions are lining up for 2019, based on commentary, whispers and published reports. Companies such as Jagged Peak Energy Inc. are reportedly looking to buy in the Permian, where Abraxas Petroleum Corp. wants to sell. Private companies Endeavor Energy Resources LP and Felix Energy LLC are reportedly up for sale.

And, to kick off 2019, activist investor Elliott Management Corp. offered QEP Resources Inc. an all-cash offer of more than $2 billion. If anything, expect the expected: ponderous, big deals and far fewer midsize exchanges.

The New Year sets up the industry for the same flavor of transactions, particularly after a shaky few months for oil prices and the continual near worthlessness with which the market values undeveloped resources. In effect, E&P dealmakers start 2019 more or less back where they started.

Investors: ‘Leave Those Deals Alone’

Corporate transactions were the go-to for many companies and buyers paid dearly—not just in premiums, but by a market discontented by E&P inertia. For many corporate buyers, the bill for a deal in the billions was nothing compared with the gratuity extracted by investors.

Partly, investors’ demands for companies to grow in a financially disciplined manner don’t account for the actual way companies grow—even when not spending cash. E&Ps also face an overhang from their reputations, which has seen them in years past try to buy their way out of trouble. That just wasn’t what was happening in 2018.

Concho Resources Inc. leveraged its superior equity value to buy discounted peer RSP Permian Inc. for $9.5 billion. The result was a next-day 9% loss of Concho’s value. Similarly, Diamondback Energy Inc.’s $9.2-billion purchase of Energen Corp. caused the company to see its value plummet 10% after announced. Chesapeake Energy Corp., Encana Corp. and Denbury Resources Inc. saw their market value decrease as well—each by at least 6%.

Simmons Energy/Piper Jaffray & Co. analysts noted in November that both companies continued to underperform the XOP: Diamondback by 3% and Concho by 13%. Nevertheless, the scope and scale created by the companies should create value over time, they added.

Recognizing the value, however, may take even longer.

The Price Of A Permian Acre

New Mexico and high-dollar real estate don’t often combine, yet the BLM leased some pricey acreage in September. How pricey? Try the highest per-acre price ever for the Permian Basin, bought by Matador Resources Co. for $95,001 (the $1 was the auto-raise that posted in the auction’s last seconds) per acre for parcels bordering the state line in Eddy County. In the two-day auction, bidders leased 50,797 acres for $972.5 million. By contrast, a BLM sale in December sold 174,044 acres for slightly more than $1.5 million.

Big? Try ‘BP Big’

BP Plc’s deal to buy BHP Billiton Ltd.’s U.S. shale package was so large, some have questioned whether it was a merger or an asset deal. Either way, the $10.5-billion cash transaction bested rumored rivals Chevron Corp. and Royal Dutch Shell Plc. in a bidding competition for solid Haynesville and Eagle Ford production and the potential of the Permian Basin.

For BHP, the shale assets were an albatross for the Australian mining giant. In the past three years, BHP bled $12.9 billion, largely through impairments from its shale business. BP’s big bucks bought 83,000 acres in the Permian, 194,000 in the Eagle Ford and another 194,000 in the Haynesville. The company also added 190,000 boe/d—an important step for the company as it aims to produce 200,000 bbl/d of oil in the Lower 48 by the mid-2020s.

Was it, perhaps, too pricey? BP’s response: time will tell.

SPACs Take Up Slack

Public markets generally turned their noses up to upstream companies, particularly IPOs—unless they weren’t quite sure where their money might be spent. In the case of the latter, apparently it does make sense then—and a money-back guarantee doesn’t hurt.

Special purpose acquisition companies (SPACs) did well in 2018. Two of the largest upstream deals, involving Roger Biemans’ purchase of QEP Resources Inc.’s Bakken assets and Steve Chazen’s EnerVest Ltd.’s Eagle Ford assets, ultimately ended up in the hands of blank-check companies in transactions totaling nearly $5 billion. In the midstream realm, Apache Corp. partnered with Kayne Anderson Acquisition Corp. to form a $3.5-billion company, Altus Midstream LP.

With public markets still closed to upstream IPOs, SPACs will continue to take up the slack. Newly formed blank-check companies, such as Jack Hightower’s Pure Acquisition Corp., look likely to provide exits for companies finding a cold shoulder in the IPO market.

Fayetteville Turns Over

Two deals last year briefly made no one think a Fayetteville reemergence was forthcoming, but they were nevertheless noteworthy for their disparity in value. BHP Billiton Ltd.’s sale of its Fayetteville assets to Merit Energy Co. grabbed about $300 million. Southwestern Energy Co.’s Fayetteville exit to Flywheel Energy LLC for $2.3 billion seemed suspiciously steeper.

On a purely PDP breakdown, Southwestern’s Fayetteville value was about $2,400 per flowing barrel. Merit paid BHP $1,400 per flowing barrel, Jefferies & Co. analyst Zach Parham wrote in a November report. Southwestern benefits from third-quarter 2018 ethane prices, which rose by about $6 a barrel compared with the second quarter.

The Plays

Crisis In The Permian

The king of oil plays came under siege. While it shouldn’t be a surprise, the ramping production resulting from the shift to unconventional drilling in both the Midland and Delaware basins—accelerated, coming out of the downturn—put enormous pressure on the infrastructure draining the region. But, while this same scenario has already played out in other shale plays, the size and potential of the Permian supersized the pain.

The problem: Permian production in May had doubled over the previous three years, to 3.2 million bbl/d, while pipeline capacity stood at 2.8 million bbl/d at the end of the first quarter. Deducting the roughly 500,000 bbl/d of local refining capacity, egress broached the brim. One study estimated up to $1.4 billion in well completions would be delayed or shifted to other plays by the end of 2019 due to the bottleneck. Producers felt the pinch in the oil-price differential; the Midland-Cushing blew out by more than $16/bbl in the summer.

Help is on the way. Some 20 new pipeline projects or extensions are to be online by the end of 2019, adding 2.6 million bbl/d of additional takeaway capacity.

Permian gas production faced woes as well, even threatening the continued production of oil. A byproduct of the burgeoning oil flow, the price of gas amazingly fell below zero for a brief period in November at the West Texas Waha hub, also the victim of full infrastructure. Permian producers stepped up flaring, exceeding 407 MMcf/d in the third quarter, according to Rystad Energy.

But it wasn’t just pipes curtailing activity—the overwhelming demand for completion crews, truck drivers, water and even power hindered producers’ ability to bring wells online. Yet the Permian’s unconventional pubescence portends to be a burgeoning hulk once these issues are thrown off.

Appalachia’s Battleground

The Marcellus and Utica shales together represent one of the largest gas fields in the world, but getting the gas out of basin has proved challenging. And just as the region is on the brink of parity with production and infrastructure, environmental activists are making a final, concerted push to stop new flows. Two pipeline projects in particular were targets in 2018.

Equitrans Midstream Corp.’s (formerly the midstream business of EQT Corp.) Mountain Valley Pipeline early in the year received green lights from various federal agencies to begin construction. The 300-mile, $3.7-billion project is to deliver 2 Bcf/d from West Virginia to Virginia. But environmental groups found fertile ground with the 4th Circuit Court of Appeals, which vacated permits and blocked construction on several occasions through the year. Even tree sitters succeeded in delaying the onset of construction.

By year-end, the project was 70% complete and set to be in service by fourth-quarter 2019, although the budget had ballooned to $4.6 billion due to delays.

Similarly, the Atlantic Coast pipeline suffered delays, also at the hands of the 4th Circuit. In December, a panel of judges threw out approvals by the National Forest Service for the route to cross two national forests. Dominion Energy Inc.’s 700-mile pipe would carry 1.5 Bcf/d from West Virginia to North Carolina.

But the basin had its successes on the takeaway front, with two other notable projects going into service and providing relief. Energy Transfer Partners LP’s Rover pipeline—a 713-mile, $4.2-billion project—began operation in May, delivering 3.25 Bcf/d north to Canada. Williams Cos. Inc.’s Atlantic Sunrise pipe to South Carolina in October added another 1.7 Bcf/d egress.

Basin differentials that had lagged Henry Hub by between $1 and $2.50 the previous year closed to 50 cents following the addition of capacity.

The Eagle Ford Keeps On Giving

The Eagle Ford Shale and cousins just got bigger. According to the U.S. Geological Survey (USGS), the Eagle Ford Group of Texas contains an estimated 8.5 billion barrels of oil, 66 Tcf gas and 1.9 billion barrels of gas liquids of undiscovered, technically recoverable resources stretching from the Mexico border to the Louisiana border. “It is one of the most prolific continuous accumulations in the United States,” the USGS reported.

Kate Whidden, lead author for the assessment, said, “This assessment is a bit different than previous ones because it ranks in the top five of assessments we’ve done of continuous resources for both oil and gas. Usually, formations produce primarily oil or gas, but the Eagle Ford is rich in both.”

Wolfcamp’s, Bone Spring’s Potentially Prolific Bounty

Not to be outdone, on Dec. 6, the USGS issued a report expanding the Permian’s Wolfcamp/Bone Spring potential bounty to an estimated 46.3 billion barrels of oil plus 281 Tcf of gas and 20 billion barrels of NGL. That’s more than double the previous estimate.

That’s the largest pool of oil and gas reserves ever announced by the USGS anywhere in the U.S., propelling the Permian Basin in New Mexico and Texas into the nation’s premier zone for energy production with some of the largest recoverable reserves in the world, said New Mexico Oil and Gas Association executive director Ryan Flynn as reported by the Albuquerque Journal.

And that’s just in two of the basin’s formations.

The Allure of Alaska’s ‘Super Basin’

Energy research firm IHS Markit in May estimated the Alaska North Slope Basin still holds some 38 Bboe—28 billion of oil and 50 Tcf of gas—and that it is poised to re-emerge as a major source of U.S. energy production. It characterized the region as “an arrested, late-emerging-phase ‘super basin.’”

“Previously thought of as a mature basin, recent large discoveries made in the shallow Nanushuk and Torok formations indicate this basin has a lot of room left to grow beyond the Endicott and Ivishak formations, which are the reservoirs from which the giant Prudhoe Bay and Endicott fields produce,” said Kareemah Mohamed, associate director, plays and basins research, IHS Markit.

“This is why we refer to this basin as being in the late-emerging phase, because it still has such significant resources to offer.”

The opportunity has not gone unnoticed by certain operators. ConocoPhillips bought out partner BP Plc in its Greater Kuparuk Area to bolster its position, and its Greater Moose’s Tooth project received fast-track approval by the Interior Department for exploration. First oil flowed there in October. Also, privately held Hilcorp Energy Co. in October received approval from the Trump administration to build an artificial island off Alaska’s north coast to develop wells.

“Today we’re announcing approval of the Hilcorp Liberty Project, which if completed, will be the first production facility ever located in federal waters off Alaska,” said Interior Secretary Ryan Zinke.

Bakken Rebound

One area feeling some relief from pipeline constraints is the Williston Basin. With the long-awaited addition of the Dakota Access Pipeline (DAPL) in 2017, an additional 470,000 bbl/d is flowing out of the basin, bringing differentials back to near-par with WTI.

Bakken production met and exceeded its previous 2014 high of 1.23 million bbl/d to exit 2018 at 1.44 million bbl/d, according to North Dakota state data. And Bakken producer Continental Resources Inc. CEO Harold Hamm said the play is still “in the third inning,” as high-intensity completion techniques used in other plays are just beginning to be deployed here.

But for those without access to DAPL, the increased production is causing growing pains all over again. Refinery maintenance pushed 800,000 bbl/d of flows elsewhere, according to S&P Global Platts, and Canadian oil depressed differentials at the Clearbrook hub by as much as $20/bbl to WTI. For some, it is possible to have too much of a good thing.

Climate Change & Activism

Activism From Within

Environmentalists, politicians and even celebrities have certainly had a lot to say about climate change and the oil and gas industry. But it’s the pressure being driven by investors that has had the most effect on the sector. Before the year closed, Chevron Corp. and Equinor ASA became the latest targets of activist investors moving to force five of the biggest oil companies to commit to fixed emissions targets and align with the Paris climate agreement.

The Chevron activist investors reported on Dec. 19 that they had filed annual-meeting resolutions, calling for the oil company to embrace greenhouse-gas reductions.

In Europe, Follow This filed a climate resolution for Equinor’s 2019 annual general meeting, mirroring its activist moves on BP Plc and Royal Dutch Shell Plc. A spokesman for Equinor said it was supporting the Paris climate agreement.

“We have our own climate roadmap and clear goals for how to cut CO2 emission,” he said.

Earlier in the year, Shell made a U-turn, setting out plans to introduce three- or five-year carbon-emissions targets linked to customers’ use of its fuels and affecting executive pay beginning in 2020. The move came after pressure from its activist investors. BP and Total SA also have set short-term targets on reducing their own CO2 emissions.

Meanwhile, two groups of Exxon Mobil Corp. investors said they would file a shareholder resolution that calls on it—the world’s largest oil company—to set targets.

In Re: Climate Change

A host of cities big and small as well as some states began testing the courts this past year to see if oil and gas companies could be held financially liable for climate change. The biggest to do so is New York City.

Mayor Bill de Blasio sued five energy companies—Exxon Mobil Corp., BP Plc, Royal Dutch Shell Plc, Chevron Corp. and ConocoPhillips—to cover costs of damages from severe weather, in particular Hurricane Sandy. In a podcast with U.S. Senator Bernie Sanders, de Blasio said the fossil-fuels industry “systematically poisoned the Earth. … We’re looking for billions to make up what they’ve done to us. Let’s help bring the death knell to this industry.”

The city of Richmond, north of San Francisco, filed suit against its biggest employer, Chevron, and 28 other energy companies, claiming they knowingly contributed to climate change and should pay for it. Chevron employs 3,500 workers at a refinery there.

Similarly, Boulder, Colo., took legal action to force companies to pay for severe weather events, and Seattle’s King County in Washington State targeted five large energy companies for “knowingly contributing to climate disruptions.” The state of Rhode Island sued, as did tiny beach town Dedina, Calif. Baltimore wants a piece of the action too.

Industry got its first victory in June when a federal judge threw out a suit by the cities of San Francisco and Oakland against Chevron, ExxonMobil, ConocoPhillips, Royal Dutch Shell and BP, potentially setting the trend for other suits. “The problem deserves a solution on a more vast scale than can be supplied by a district judge or jury in a public nuisance case,” the court ruled. “The court will stay its hand in favor of solutions by the legislative and executive branches.”

A Manhattan judge tossed New York City’s suit in July. While the battle might seem frivolous, it carries great consequences if it is lost and ongoing.

State Ballot Initiatives

The November midterm elections were full of intrigue on many fronts. While much of the country was fixated on the party balance in Congress, the oil and gas industry was also keeping a close watch on the Colorado ballot initiative, Proposition 112, which would have mandated at least 2,500 feet of separation between new drilling activities and occupied or vulnerable areas.

Had it passed, questions about the viability of the state’s oil and gas industry would have swiftly emerged, as up to 85% of the state would have suddenly been out of bounds for new drilling. In the end, the measure ended up garnering only 43% of the vote.

Shares of producers active in the state, including Anadarko Petroleum Corp., Noble Energy Inc. and Devon Energy Corp. rose on Nov. 7, retracing some of their double-digit percentage declines since the initiative went on the state’s ballot. As it was, the initiative cost oil and gas companies billions of dollars while the process played out.

Other ballot initiatives in Washington State and Arizona also fell flat. Arizona voters shot down a proposal to mandate 50% renewable power by 2030. Washington State voters rejected a $15-per- metric-ton carbon tax.

Unlikely Carbon-Tax Backers

Exxon Mobil Corp. in October pledged $1 million to promote a national carbon tax on oil and gas. ConocoPhillips followed suit in December with a $2-million commitment. The money will go to Americans for Carbon Dividends, a lobbying group created to back a plan put forward by former Secretaries of State James Baker and George Shultz. The plan would tax $40 per ton of CO2, equaling about 36 cents per gallon of gasoline, according to the Washington Post.

Axios.com columnist Amy Harder wrote, “Given the industry’s deep-pocketed influence with Republicans, this backing increases the odds Congress could eventually back the controversial policy.”

International

Sizing Up The Mexican President

Uncertainty in Mexico’s new position over foreign investment in its energy sector picked up when the country overwhelmingly elected leftist President Andres Manuel Lopez Obrador. A nationalist, he was vehemently opposed to his predecessor opening Mexican resources to foreign investment, putting foreign investors on alert.

Shortly after the election in July, Mexico scrapped plans for two oil auctions scheduled in the fall preceding his taking office. Thirty-seven conventional and nine shale blocks were set to be auctioned in September, and joint-venture bids in seven regions with Pemex were halted as well.

Lopez Obrador took office on Dec. 1, promising to increase the government’s role in the energy industry and roll back what he described as a 36-year neo-liberal era in which successive governments gradually opened up the economy. During the election campaign, he pledged to review the oil and gas contracts for any signs of corruption. He and his team have not said they have uncovered any wrongdoing in the contracts already awarded.

“The contracts will not be canceled, so there won’t be a loss of confidence,” he told reporters at a news conference.

Yet two subsequent bidding rounds for February 2019 were also canceled, including shale offerings opposite the Texas border. It is unknown when—or if—future auctions might take place. He committed $8 billion to building a new refinery, although the country’s refining system is currently underutilized and imports light oil from the U.S. A week later, he announced Pemex’s budget would be increased to $23 billion, with an emphasis on exploration.

“We are going to rescue our dear Mexico and the national oil industry,” he said, according to Bloomberg.

Fracking The UK

Initial gas, albeit a tiny amount, began flowing from the Preston New Road well in Lancashire, U.K., in November—the very first horizontal well and hydraulic completion performed in the kingdom. Cuadrilla Resources Ltd. drilled the well into the Lower Bowland Shale at 8,000 meters vertical depth and 800 meters laterally. The well was drilled in April and “a small section of the shale” fractured in October.

Francis Egan, Cuadrilla CEO, reported, “The volumes of gas returning to surface at this stage are small. However, considering that we are only at the very start of fracturing operations and, given operating constrains, have not yet been able to inject as much sand into the shale as we had planned, this is a good early indication of the gas potential that we have long talked about.”

A second well has been drilled but yet to be completed—making it the U.K.’s first shale DUC (drilled but uncompleted well).

Venezuela Meltdown

The economic collapse in Venezuela continued. The country with the world’s largest oil reserves saw its production fall to 30-year lows to 1.2 million bbl/d at year-end. President Trump instilled tough sanctions on the country barring banks from doing any deals with the country or PDVSA. The measures are to deny any financing of the “illegitimate rule” of President Nicholas Maduro, the White House reported.

In May, a Curacao court authorized ConocoPhillips to seize PDVSA’s refining assets in the country in response to a $2-billion arbitration awarded by the International Chamber of Commerce. The award stems from the 2007 nationalization of foreign assets by Venezuela.

Bahrain Gets A Little Bigger

Bahrain, the smallest energy producer in the Persian Gulf, announced in April it had made an 80 billion-barrel discovery, its biggest oil field since it started producing 80 years ago. Independent consultants DeGolyer & MacNaughton, along with Schlumberger Ltd., confirmed that the find dwarfs Bahrain’s existing reserves, according to Reuters. Halliburton Co. was to drill two additional appraisal wells.

“The newly discovered resource, which officials expect to be on production within five years, is expected to provide significant and long-term positive benefits to the kingdom’s economy,” Bahrain’s National Communication Centre reported in a statement. Bahrain currently produces about 40,000 bbl/d.

We Like Gas Better—Or, Just Not You

Qatar might be OPEC’s smallest oil producer at 2% of the overall output, but it’s the world’s biggest LNG exporter, which might explain—at least in part—its exit from the cartel at year-end. With nearly 900 Tcf in reserve in its massive offshore North Field, Qatar said it wanted to focus on developing gas.

But fellow OPEC members Saudi Arabia, the UAE, Bahrain and Egypt have imposed an economic and political boycott of Qatar since 2017, accusing it of supporting terrorist activities. The OPEC exit wasn’t predicated on bad blood, according to Qatar Minister of State for Energy Affairs Saad al-Kaabi. But, he added, according to Reuters, “We are not saying we are going to get out of the oil business, but it is controlled by an organization [OPEC] managed by a country [Saudi Arabia].”

WILDCATTER MEMORIAM

Former U.S. President George H.W. Bush—A wildcatter and former IPAA director, President Bush began working in the industry in the oil fields of the Permian Basin—where his first son, former President George W. Bush, was born—with Dresser Industries, Zapata Petroleum Corp. and Walker-Bush Corp. He was awarded a lifetime IPAA membership in 1993.

Upon his death on Nov. 30, IPAA president and CEO Barry Russell responded on the organization’s behalf: “As a director of IPAA and, later, as a public servant, President Bush defined the characteristics of the great men and women who encompass our industry—hardworking, entrepreneurial, optimistic and patriotic. The IPAA board of directors, leadership and management team extend our heartfelt thoughts and prayers to the family and friends of President Bush.”

Ted Collins Jr.—It has been said that Ted Collins never met a stranger, and his penchant for doing deals reflects the relationships he built over his life. Collins began his career in 1959 and soon started his own venture, American Quasar Petroleum Co. along with other partners, which became the largest publicly traded drilling fund in the country. Later he was president of HNG Oil Co., a predecessor to EOG Resources Inc.

Collins proved his prescience when he partnered with George Young Jr. in the nascent Barnett Shale that resulted in a $2-billion sale. His opus was an investment in an early Permian start-up—RSP Permian Inc., which would later sell to Concho Resources Inc. for $8 billion.

John J. Amoruso—Houston geologist John J. Amoruso had a lifelong love of and career in geology after receiving his master’s degree in geology from the University of Michigan. He began his career with Pan American Petroleum (later it become Amoco Corp.) but went independent in 1969. He was active exploring in several states and discovered numerous fields.

Amoruso’s career culminated with his greatest discovery, the Amoruso Field in East Texas, a deep Bossier sandstone gas reservoir in Robertson County, in 2002. It held 3 trillion cubic feet of gas. This field became one of the largest onshore gas discoveries made in the U.S. in many years.

Raymond Plank—Raymond Plank was one of three founders of Apache Corp. in 1954 and led the company for 50 years until his retirement in 2009. With a financial degree from Yale, Plank created unique financial platforms for investment, including drilling funds, the first upstream MLP, and a deal structure that protected buyers if commodity prices fell.

At one time, Apache was the largest gas producer in the Anadarko Basin and had the largest operated position on the Gulf of Mexico Shelf. Apache also began venturing abroad in 1988, at one time holding concessions or production in Canada, Poland, China, Australia and Argentina’s Vaca Muerta Shale. It later retrenched to a U.S. focus on the Permian, remaining in Egypt and the North Sea.

Plank was known for making acquisitions from majors. “Raymond was a pioneer in the acquire-and-exploit strategy that ultimately transformed the U.S. E&P business,” said George Solich, who for more than a decade was Apache’s business-development chief and is now CEO of FourPoint Energy LLC.

Lester D. Moore—A long-time independent oil producer in Indiana, Lester Moore was the founder and owner of Moore Engineering and Production Co. Moore was the Illinois Oil and Gas Association Wildcatter of the Year in 1980.

Outside of Indiana, he made his mark at the Independent Producers Association of America (IPAA) as long-time board member and was a part of the IPAA volunteer leadership for almost 40 years. He began a leadership role in the late 1970s and, by the early 1980s, had become chairman of the IPAA Crude Oil Committee and a member of the Nominating Committee. He worked on the IPAA’s task force to submit the industry’s policy positions to President Ronald Reagan’s transition team; Reagan presided over deregulation of oil and gas prices.

James D. Woods—Jim Woods was the former chairman, president and CEO of Baker Hughes Inc., from which he retired in 1997. He joined Baker Oil Tools in 1955 and spent his entire career there. He was the guiding force behind the company’s 1987 merger with Hughes Tool Co. It was one of the first and largest oilfield-service company mergers of that decade. Both companies were more than 100 years old at the time. Upon retiring, he became an advisor to SCF Partners, the Houston private-equity firm that invests in oilfield service companies, and served on numerous boards.

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