workover rig companies in colorado pricelist

The industry has kept the focus on complaints about regulatory changes in Colorado that have put tough new rules on drilling, and slowed permitting to a crawl they say.

“A well is its most productive in the first 18 months after its completed,” said Dan Haley, with the Colorado Oil and Gas Association. “Then you begin to see a pretty substantial decline curve. Wells drilled in 2018 and 2019 when we were hitting production highs are producing less now.”

But a spokesperson for the state regulator, the Colorado Oil and Gas Conservation Commission, disputed that new rules were primarily responsible for a lack of production, saying the industry is sitting on 2,600 permits already approved. The industry said many of those had expired, and what was left would not be enough to change the larger trend of production declines.

Under the new, more strict rules, that went into effect last year, the state says up to 227 new wells have been approved across 15 different oil and gas development plans submitted by drillers. One plan was rejected, which included 33 wells.

Permits are only part of the story. Even if the industry wanted to ramp up production, there are not enough workers to operate the rigs and wells. Many left during the pandemic slowdown. Mining and Logging employment in Colorado is down by about 10,000 workers, from 29,000 in 2019 to 19,000 in 2022, the lowest number of workers since 2006.

Lastly, Wall Street investors demand financial discipline from drillers now. The industry has a tendency to overbuild when prices are high, and then get crushed by debt when prices inevitably fall.

A survey by the Federal Reserve’s Dallas office of oil and gas companies across the U.S. found that, “slightly over half — 59 percent — of executives believe investor pressure to maintain capital discipline is the primary reason that publicly traded oil producers are restraining growth despite high oil prices.”

The Aztec Well family of companies provides complete oil and natural gas drilling, well servicing, trucking, rentals, equipment, support services and supplies. We offer each service separately, or as a package, to suit your needs. We have been professionally serving our customers in the oil and gas industry with family-owned care and expertise since 1963. With nearly five decades of experience, we provide you the best of both worlds: the knowledge and resources of a large and long-standing oil and gas company, combined with the care and timely responses of a family-owned business.

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Over the past month, oil prices have trended downward. On August 26th, prices closed at $93.06. On August 29th, prices hit a high of $97.01. Since then, prices have fallen steadily. On September 23rd, prices closed at $78.74.

The September 23rd Baker Hughes rig count report shows the active rig count is steady. Baker Hughes reports 764 active drilling rigs in the US. One month ago, the total active rig count was 765, and one year ago, it was 521 rigs.

The oil rig count is currently 602 rigs, compared to 605 one month ago, and 421 one year ago. The gas rig count is 160, compared to 158 one month ago and 99 last September.

TCI Business Capital is a leading provider of accounts receivable factoring for oilfield service companies. Factoring is a type of financing many companies use to get immediate cash for their open receivables.

If your oilfield services company is being held back by slow cash flow, or if you need money to meet those daily expenses, call TCI Business Capital at 800-707-4845, or contact us via the web.

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After a year in which dollars and oil from drilling rigs flowed freelyinto Colorado, the nine major drillers on the Front Range are slashing 2015 spending by 30 percent, about $2 billion.

The number of rigs running has already dropped by a third in five months to 44 at the end of February, according to the oil field services company Baker Hughes.

So far, the cutbacks haven’t had a severe impact on the state or on Weld County, the heart of Colorado oil country, partly the result of a diversified economy and continued big-dollar commitments by operators — even after the cuts.

“Hotels and restaurants still look to be full,” said Eric Berglund, CEO of Greeley-based Upstate Colorado Economic Development. “Beyond drilling, there is a large oil and gas industry presence here.”

There are thousands of existing wells that still need to be serviced, pipelines are being built, and gas processing and water recycling plants need employees, Berglund said.

“We haven’t seen any uptick in unemployment claims in the oil and gas sector,” said Bill Thoennes, a spokesman for the Colorado Department of Labor. “This may be something coming down the road, but we haven’t seen it yet.”

The two largest operators, Houston-based Noble EnergyInc. and Anadarko Petroleum Corp., based in The Woodlands, Texas, say they have no layoff plans.

Some of the job losses tied to the decline in rigs will end up in the unemployment reports of the rig companies based in Texas and Oklahoma, Berglund said. A rig employs about 110 people.

Statewide, the oil and gas sector employs just 1.2 percent of the workforce and losses in that sector may be offset by growth in others, said Mark Vitner, an economist with Wells Fargo Securities.

“The price of oil isn’t going up to $100 anytime soon,” Vitner said. “So we’d expect the slowdown to be more pronounced later this year. … But the industry is not going away.”

The nine operators — which, based on state data, produced at least a million barrels of oil each in 2014 — are projected to spend up to $4.6 billion in Colorado in 2015, down from $6.6 billion last year.

In addition to the spending cuts, operators are trying to improve their efficiencies — focusing on drilling in the areas with the best yields and getting better prices for materials and services.

Most operators hire oil field service companies, such as Baker Hughes and Halliburton, for drilling and hydrofracturing, or fracking, which pumps pressurized fluids into wells to crack rock and release oil.

The combination of horizontal drilling and fracking in tight shale formations has enabled Colorado to more than double its oil production in the past four years to about 82 million barrels in 2014.

The activity is centered in the Denver-Julesburg Basin, which stretches from Denver to the Wyoming border, and the Wattenberg field, within the basin.

Operators are now getting lower prices for materials and services, said Craig Rasmuson, chief operating officer of Platteville-based Synergy Resources Corp.

“The services companies are giving better prices and are willing to have smaller margins to keep operating and keep their people employed,” Rasmuson said. “We are all sharing the pain.”

Synergy is the one company among the nine big drillers planning to increase its capital spending in 2015. Company officials expect to boost spending to $180 million this year from $160 million in 2014.

“The Wattenberg continues to be one of the more attractive assets in our portfolio,” Chuck Meloy, an Anadarko vice president, said during an investor conference call Tuesday.

Noble had 10 rigs running in 2014. The company is projecting four rigs in 2015, and they will be working in northeastern Weld County— far from residential areas.

Synergy estimates that drilling near homes adds 3 to 5 percent to the cost of wells because of extra noise mitigation and landscaping requirements, Rasmuson said. On the high side, it can add 10 percent to the cost.

In addition to focusing on high-yield areas, Stover said the company will increase the length of some of its horizontal wells to as much as 9,000 feet.

Depending on the length of the well and the number of stages needed to complete it, a frack job can cost between $1 million and $1.7 million, according to figures cited by companies in their presentations.

Houston-based Carrizo Oil and Gas is cutting activity and deferring some completions, company CEO Sylvester Johnson told stock analysts in a February conference call.

Calgary-based Encana Corp., the third-largest Colorado operator, plans to spend $170 million to $200 million in 2105, about a third less than last year, said company spokesman Doug Hock.

Faced with oil at $50 a barrel, bringing on more production “just doesn’t seem to make good business sense,” Bill Barrett CEO Scot Woodall told analysts in a February call.

Bonanza Creek Energy, based in Denver, is trimming spending by 36 percent overall, with just under $400 million for its Wattenberg operation, according to a company presentation.

Quoting T. Boon Pickens, Bonanza Creek CEO Richard Carty told stock analysts “it has become cheaper to look for oil on the floor of the New York Stock Exchange than in the ground.”

An oilfield services company laid off more people Thursday in northeast Colorado, making a total of 88 jobs cut there since oil prices collapsed and pandemic restrictions started.

Fort Worth, Texas-based Basic Energy Services Inc. informed 26 more staffers by mail on Thursday that they’d been laid off from its Fort Morgan office, the company said. The layoffs add to previous downsizing there between March 23 and April 16 in which the company shed 62 jobs.

“The company, like all oilfield service providers, is currently facing a significant decrease in the amount of service orders from its customers,” Basic Energy Services wrote in a letter to state labor department officials, “and it anticipates additional significant decreases in demand for its services in the near future.”

Colorado’s oil and gas industry, like companies across U.S. crude oil exploration and production, have been rocked by plummeting oil prices and an unprecedented loss of demand triggered by workplace closures and stay-at-home orders enacted to stem the spread of the Covid-19 respiratory virus.

Basic Energy Services maintains wells, operates workover rigs, manages water disposal and conducts other services for oil companies that own well and produce crude. The company has worked with oil producers that have a major presence in Colorado’s Denver-Julesburg Basin, including the two largest producers in the state, Occidental Petroleum Corp. (NYSE: OXY) and Noble Energy Inc. (Nasdaq: NBL).

Basic Energy Services classified the layoffs in Fort Morgan as permanent in its letter to the Colorado Department of Labor and Employment, but it said it hopes to hire the employees back when oil prices recover and it’s again receiving enough work from oil production companies.

Denver-based Liberty Oilfield Services Inc. (NYSE: LBRT) laid off 183 from its Adams County field office on April 3, part of cuts it made nationally in which the hydraulic fracturing services business laid off several hundred employees.

Enverus provides timely information pertaining to drilling activity in the United States, and the Gulf of Mexico for the oil and gas industry. With more than 25 years of experience, Enverus reports have supplied important information on the life of the well as detailed by its permits, the actual drilling and completion activities, up through its current production profile.

Enverus publishes reports on a daily, weekly or monthly basis as well as providing continuous access to our extensive data through subscription web-based services.

With access to Enverus, you can identify new sales leads, plan visits to drilling rigs, determine market share, identify exploration trends, find available rigs, identify new production, monitor competitive activity or define sales territories. Our survey team talks with hundreds of specialists each week to verify our data as well as ensure it is fresh and as detailed as possible for your use.

Thousands of oil and gas industry professionals depend on Enverus reports for every day decision making. We strive to meet your unique needs with a variety of options offering different frequency of access and subscription costs, all made available with the end user in mind.

BROOMFIELD, Colorado, Dec 20 (Reuters) - In a Denver suburb, an oil drilling rig plumbs the earth near a wealthy enclave framed by snow-capped mountains. The site is quieter, cleaner and less visible than similar oil and gas operations. It might just be the future of drilling in the United States.

Oil firm Civitas Resources designed the operation to run largely on the city"s electric grid, eliminating daily runs by more than a dozen diesel fuel trucks. The electric rig has none of the soot or sulfur smell of diesel exhaust and is muffled enough that rig hands can converse without yelling.

As investors and lawmakers push the oil industry to lower its carbon emissions, this drill site and others run by Civitas offer one model for drillers looking to migrate to low- or no-carbon emissions operations.

An extra incentive for Civitas is that it must be mindful of neighbors of its drilling sites in relatively affluent suburban areas, where it also has easier access to the power grid.It is unclear whether drillers in more remote areas will be able to adopt the same technology as easily.

Civitas, Colorado"s largest oil and gas producer, says it is the state"s first "carbon neutral" producer. To get there, it has eliminated some diesel-powered pumps, makes modifications to drilling and hydraulic fracturing equipment and its production sites. It also buys carbon credits to offset remaining emissions.

A few miles away, another Civitas pad with 18 wells is hidden behind an earthen berm, largely invisible to the surrounding community. It has dozens of air-monitoring sensors to detect greenhouse gas emissions. Its pneumatic controls have been adapted to avoid methane leaks. It is Civitas" first facility to do away with oil and waste water storage tanks.

"Everything is piped directly off location. There is no dust, no truck traffic necessary to produce the hydrocarbons,” said Matt Owens, Civitas" chief operating officer.

Colorado, among the top oil producers among U.S. states, also has some of the toughest state emissions regulations. It has told energy firms they must cut methane emissions from drilling by 2030 to less than half of 2005 levels. More drillers also face stricter mandates as President Joe Biden"s administration enacts tougher federal methane rules.

"Electrifying drilling, upgrading pneumatics and going tankless are certainly steps in the right direction," said Deborah Gordon, a senior principal in the Rocky Mountain Institute"s climate intelligence group.

Colorado"s tougher regulatory environment has partially evolved from the industry"s proximity to homes and businesses. For Civitas, that suburban life means strong local electric power supplies.

"All the power lines that have been built out for urban expansion, we"re able to tap into those," said Brian Cain, Civitas" chief sustainability officer during a tour of a drilling site. He estimates switching from diesel to line power reduces emissions by 20% to 25%. "The landscape is a lot different than west Texas," where operators do not have easy access to the adequate electric power, he said.

Some environmentalists have said lowering greenhouse gas emissions from oil drilling is not enough, and instead advocate for moving society away from fossil fuel usage altogether. This year, the International Energy Agency said investors should halt funding to new oil, gas and coal supply projects if the world wants to achieve net zero emissions by mid-century. read more

While electrification offers a quick way to cut emissions from production, there are other hurdles. Civitas shifts work schedules to avoid overtaxing the grid during peak heating or cooling times, said Cain.

In Texas, however, top oilfields "tend not to be urban environments" with ample electricity, said Don Whaley, president of Texas retail power provider OhmConnect Energy.

The second-largest Texas producer, Pioneer Natural Resources (PXD.N), aims to electrify drilling, hydraulic fracturing and compression at pump stations within eight to 10 years, its chief executive vowed last week. The company has already begun switching out compression at pumping stations to move oil and gas for electric, said Chief Executive Scott Sheffield.

Pioneer is working with Texas transmission operator Oncor to boost capacity near the oilfield. It and other shale oil firms will likely cover some of the cost of upgrading power lines and substations to more quickly reduce diesel fuel use, Sheffield said.

Hydraulic fracturing, the pumping of water, sand and chemicals into well bores to release trapped oil and gas, is undergoing its own conversion. So-called electric fracks, powered by fossil fuels coming from nearby wells, are just emerging.

Top U.S. fracking provider Halliburton Co (HAL.N) this year said it successfully deployed a grid-powered fracturing operation, which sharply reduced its carbon footprint, according to a company report.

"When you move to electric fracks, that"s the white whale for us," said Cain, which he estimates could reduce emissions from completions by 20% to 30%. "That is a huge benefit for us in terms of total greenhouse gas."

The war in Ukraine has limited Russian oil and gas supplies and has the potential to cause a major shift in the world’s energy market. No one knows how long Russia intends to wage war in Ukraine or how much of its crude will be affected by sanctions or for how long. The uncertainty caused by the supply disruption has driven crude prices to multi-year highs. And anxieties persist that surging oil prices may rise so high that demand destruction will damage the global economy and cause a worldwide recession. However, Russia’s invasion of Ukraine is creating a new market for U.S. LNG producers, as product flows to Europe to replace Russian natural gas. The longer the conflict persists, the more entrenched U.S. LNG will become.

Fig. 1. Drilling activity in the U.S. increased steadily through the first seven months of 2022, but the rig count slowed and began to plateau in August and September. Image: Pioneer Natural Resources Company.

ESG impact. Although the U.S. petroleum industry faces continued pressure from President Biden and environmental groups about the imperative of reducing fossil fuel usage to slow GHG emissions, the drive for rapid implementation has lessened. However, the transition to renewables and clean energy alternatives has created an unprecedented reduction of investment in hydrocarbon-based energy, in favor of developing green resources. During 2021, global oil and gas discoveries hit their lowest level in 75 years. Total global discovered volumes in 2021 were calculated at 4.7 Bboe, the lowest tally since 1946. This trend is predicted to continue in 2022. A data-based comparison shows a significant reduction in recoverable oil resources that will drive commodity prices higher and further damage global energy security.

U.S. production surges. Despite a sizeable drop in recoverable resources, U.S. oil production remains on track for a record in 2023, even as output grows more slowly than anticipated amid increased costs and labor shortages in America’s shale fields. Output is expected to expand at an average 840,000 bopd next year, down from a prior forecast of 860,000 bopd, according to the EIA. While production is still seen reaching an all-time high in 2023, the government revised its forecast slightly lower to 12.7 MMbopd. The current, annual, U.S. record average is 12.3 MMbopd, set in 2019.

At the start of the year, production in the U.S. (11.7 MMbopd), Saudi Arabia (10.2 MMbopd) and Russia (11.0 MMbopd) was running at nearly full capacity. Brent and WTI were trading at $86.51/bbl and $83.22, respectively. When Russia invaded Ukraine on Feb. 24, 2022, the EU and international community reacted quickly by boycotting Russian supply. The embargo quickly pushed prices up, and in June, Brent was trading for $122.71/bbl and WTI hit $114.84/bbl, the highest price since August 2008. Prices retreated in July, down to $111.93/bbl for Brent and $101.62/bbl for WTI, due to rising interest rates and fear of economic recession, despite restricted Russian supply.

Demand to lessen. The global surge in the cost of fuel is starting to weigh on demand, according to Vitol Group, the world’s largest independent oil trader. Consumers are being impacted by the run-up in gasoline, diesel and other oil products said Mike Muller, head of Vitol Asia. There is clear evidence of economic stress being caused by high oil and natural gas prices, according to Muller.

The Baker Hughes rotary rig count stood at 588 units during the week ending Jan. 7, 2022. U.S. drilling activity climbed steadily for the next seven months, although it slowed in July and August, reaching 760 in the week ending Sept. 2, Fig. 1. Although the 172-rig increase represents a Jan.-Sept. increase of 29%, U.S. shale operators have resisted ramping-up drilling activity and remained relatively disciplined with their capital expenditures. The speed at which new rigs have been deployed to the field is considerably less than in previous up-price cycles. Most U.S. shale companies are still being conservative, as priorities remain focused on protecting balance sheets and generating free cash flow.

This conservative approach, along with high oil prices, has enabled shale companies to reduce their debt burdens in the second quarter, signaling room for them to pay dividends, buy back shares or make acquisitions. A metric commonly used to measure companies’ ability to pay down their borrowings has widely improved among oil and gas producers, as they repurchase some bonds and pile up cash amid ballooning profits.

Net debt reported by a group of independent operators, including ConocoPhillips and Pioneer Natural Resources, averaged less than 0.6 times their annual earnings before items such as interest and taxes in the second quarter, down from 1.7 times a year earlier. Many companies have reached their debt target. Energy companies have made great strides toward repairing and reinforcing their balance sheets and are in a much stronger position to handle another downturn in commodity prices.

With WTI trading between $85/bbl and $95/bbl, U.S. shale producers are on course to generate $200 billion this year, enough to make the industry debt-free by 2024 and potentially fund a pivot toward more natural gas production (Deloitte). High oil prices and disciplined capital spending mean U.S. shale producers are on track for their most profitable year on record, part of a global trend that will see the oil and gas industry generate a record $1.4 trillion of free cash flow. After paying down debt and rewarding shareholders, U.S. producers will likely focus more on natural gas production, due to high demand and prices around the world. Producers will also make record profits from U.S. LNG operations. They are expected to generate $59 billion this year, double last year’s amount and easily recouping the $45 billion of losses from 2013 to 2020.

Fig. 2. As shown in this all-time U.S. drilling chart, activity for the last two years has grown slowly but steadily since bottoming out during 2020. If the forecast holds, U.S. drilling will be up nearly 50% in 2022, compared to the low point two years ago. Chart:©World Oil.

Due to sustained higher oil prices, World Oil forecasts a noticeable uptick in drilling activity for the remainder of the year, projecting 18,600 total wells for 2022—a 34% increase from the 2021 count of 13,877, Table 1. Total footage is projected to increase from 191.5 MMft in 2021 to 256.4 MMft in 2022—an increase of 34%. During 2022, 8,769 wells are estimated to have been drilled during the first six months, while 9,831 are expected to spud in the second half of the year, for a half-to-half increase of 12.1%. A 14.9% increase in footage is expected in the last six months.

Oil prices have been rising since the start of 2021, bolstered by restricted Russian supplies and recovering demand. However, upstream M&A activity, which typically follows oil prices, remains well below pre-pandemic levels. The total count and value of U.S. upstream deals during the first eight months of 2021 were down 30% and 46%, respectively, from the same period in 2019.

While the ongoing capital discipline of operating companies is the primary reason behind the slowdown in upstream M&A activity, limited visibility of buyers into the carbon profile of sellers’ assets is a growing factor. Companies pursuing their net-zero goals are either looking to acquire low-carbon-intensity barrels or divest the high-intensity ones, implying that there might be an acreage consolidation or portfolio restructuring on the horizon (Deloitte). But a large resource size and an attractive offering price may not be enough to elicit a response from a buyer focused on meeting its net-zero targets. Therefore, M&A activities would need not only to be financially accretive, but also to support ESG goals.

Devon Energy agreed to acquire Validus Energy for $1.8 billion in cash, to expand in the Eagle Ford shale play in South Texas. The deal will add to Devon’s cash flow and earnings in the first year, and boost its variable dividend by up to 10%, based on current oil futures prices. Devon also said the transaction will enable the acceleration of the return of cash to investors via its existing $2 billion stock buyback program. Buying Validus will add 42,000 net acres adjacent to Devon’s existing leasehold in the Eagle Ford. Validus’s production is approximately 35,000 boed, with volumes expected to increase to 40,000 boed over the next year.

EQT to buy Marcellus assets. EQT Corp, the largest U.S. natural gas producer, agreed to acquire THQ Appalachia, a privately held company, in a $5.2 billion deal to expand holdings in the Marcellus shale. The company purchased the assets from Alta Resources for $2.9 billion. It also acquired Chevron’s assets in Appalachia for $735 million in 2020. THQ Appalachia produces nearly 800 MMcfgd in West Virginia. The company has about 11 years of inventory at maintenance capital levels. EQT is expected to produce the equivalent of 5.5 Bcfd this year.

Fig. 3. Drilling levels in the U.S. Gulf of Mexico will be up about 8.5%, compared to 2021’s activity. Second-half 2022 drilling will be up only slightly from the first half. Image: Transocean.

Heading into 2022, most operators expected pricing to increase for nearly all service lines but seismic. Labor, tubulars, fracturing/stimulation, and transportation were the areas of greatest concern. A modest 15% expected pricing to remain stable, including nearly 39% for completion equipment, 35% for other services, and 33% for drilling. Further pricing concessions were expected by a modest few for seismic services and tubulars.

Further pricing increases are expected in the second half of 2022, with limited availability of OCTG and casing potentially curtailing spending revisions. Overall spending in OFS is expected to remain about 25% below 2019 levels until 2025. With margins at the mercy of another price cycle and reduced spending, many OFS companies are crafting a new strategy for the future of energy. With a broadening decarbonization mandate across industries, companies have an opportunity to lead the way for customers by fully re-engineering traditional OFS business models and solutions outside the traditional oilfield services and to other industries.

Many large service providers have diversified beyond core services. One large company has restructured its business by launching cloud and edge computing services, whose rate of growth is expected to outpace that of their O&G business in a few years. Similarly, Halliburton and Baker Hughes are partnering with start-ups and academic institutions, through their Halliburton Labs and Baker Hughes Energy Innovation Center, respectively, to accelerate technology development for diverse energy and industrial applications.

However, digitalization will only help to a certain extent. Providing integrated solutions for decarbonizing upstream projects, implementing subscription-based revenue models or diversifying into the low-carbon space, such as hydrogen and CCUS, are key to future growth.

The number of licensed blocks and total acreage fell to near all-time lows, as the sector struggles to shake off the effects of the Covid-19 pandemic and the ensuing oil market crash (Rystad). Only 21 leasing rounds were completed globally through August this year, half of the 42 rounds held in the first eight months of 2021. The acreage awarded so far this year has shrunk to a 20-year low of 320,000 km2. Global leasing rounds are expected to total 44 this year, 14 less than in 2021 and the lowest level since 2000.

Global spending on exploration has been falling in recent years, as oil and gas companies seek to limit risk by focusing on core producing assets and regions with guaranteed output, aiming to streamline their operations and build a more resilient business amid market uncertainty and the threat of a recession. The political landscape is also contributing to the decrease in license awards, with many governments pausing or halting leases and encouraging companies to wrap up exploration activity within already awarded blocks. This trend is likely to continue, as governments are less eager to invest in fossil fuel production and instead look ahead to a net zero future.

The onshore exploration sector is a significant contributor to the decline in awarded acreage. Total onshore acreage awarded in leasing activity has plummeted from more than 560,000 km2 in 2019 to a mere 115,000 km,2 so far this year. Offshore leased acreage hit a high point in 2019 before dropping off a cliff in 2020 and has remained relatively flat in the past two years. Concluded leasing rounds have dropped significantly in the U.S., driven primarily by the cancellation of Lease Sales 259 and 261 in the Gulf of Mexico and Cook Inlet in Alaska.

Employment in the U.S. oilfield services and equipment sector rose by an estimated 6,865 jobs to 648,914 in August, according to data from the Bureau of Labor Statistics and analysis by the Energy Workforce & Technology Council. Gains in August make OFS employment the highest since the Covid-19 pandemic began, but they are still off the pre-pandemic mark in February 2020 of 706,528. Overall, U.S. employers added 315,000 jobs, down from July numbers but still representing a strong pace of growth.

Fig. 4. Symbolized by this picturesque wellsite close to Signal Peak bluff in the Midland basin, near Big Spring, Texas (Howard County), drilling in the Permian region is at its highest level since 2019. Image: Latshaw Drilling Company.

North American spending is forecast to increase 33% from 2021 levels, which is an acceleration from 20.6% growth projected in a December survey and builds on the modest 1% increase experienced in 2021, according to James West, senior managing director at Evercore ISI. The increase is driven by a 1,260 bps acceleration in the U.S. to 36% growth, which more than offset a 2.8% decline in spending in 2021 excluding the historical capex of distressed companies that have since been acquired or privatized. Private and independent operators are leading the recovery, with capex accelerating by 1,440 bps and 1,550 bps from the December survey to 56% and 42%, respectively, and also accelerating from 41% and 5% growth in 2021. More modest growth of 25% and 19% are anticipated from the majors and NOCs, both of which contracted further in 2021.

While the majors have more than offset declines in 2021 despite recent divestitures—with Evercore’s projected 2022 spending nearly 7% above 2020 levels—spending from the NOCs remains 25% lower, to account for less than 1% of total U.S. spending (vs. almost 2% in 2020). Overall, the majors account for almost 30% of U.S. capex, down from 36% in 2020, while the independents, including privates, account for 70% of all spending, up from 62%. U.S. capex is on track to recover within 25% of pre-pandemic levels and approach levels last seen in 2009 before the start of the oil shale revolution.

There could be modest upside to NAM spending in in the second half of 2022, with current spot prices above the $84/Bbl WTI and $5.18/MMbtu HH average basis for establishing 2022 budgets. While half of survey respondents would maintain their budget, regardless of changes in the oil and gas price, one-third are willing to flex capex higher for rising cash flow. However, Evercore believes upside is likely to remain muted, as activity could be constrained by the availability of goods, services and labor.

Operators have been highly disciplined over the past year, as commodity prices increased. Yet, a new round of consolidation may drive spending higher, if commodity prices stabilize at a significantly higher range and confidence in the duration of the cycle increases. From a lower base, Evercore believes the set-up is positive for growth in 2023 and beyond.

The EIA’s Short-Term Energy Outlook, published September 2022, reports that STEO is subject to heightened uncertainty resulting from Russia’s full-scale invasion of Ukraine and how sanctions affect Russia’s oil production. Also contributing to uncertainty is the production decisions of OPEC+, the rate at which U.S. oil and natural gas production rises, and other contributing factors. Less robust economic activity in the STEO forecast could result in lower-than-expected energy consumption.

Oil price forecast. Russia’s full-scale invasion of Ukraine has resulted in shifting trade patterns, leaving Europe to find substitutes for Russia’s oil. This change has driven up the price of Brent contracts to a level high enough to reduce Asia’s imports of Brent and to retain more oil in Europe. EIA forecasts the spot price of Brent crude will average $98/bbl in the fourth quarter of 2022 and $97/bbl in 2023. The possibility of petroleum supply disruptions and slower-than-expected crude oil production growth continues to create the potential for higher oil prices, while the possibility of slower-than-forecast economic growth creates the potential for lower prices.

Fig. 5. With plenty of drilling occurring in North Dakota during the last 12 to 15 years, and many wells like this one put onstream, there is a concern that the Bakken’s sweet spot has reached maximum infill development. Image: ConocoPhillips.

Crude production forecast. U.S. crude oil production is forecast to average 11.8 MMbopd in 2022 and 12.6 MMbopd during 2023, which would set a record for the most U.S. oil output during a year. The current record is 12.3 MMbopd, set in 2019.

Natural gas prices. In August, the Henry Hub spot price averaged $8.80/MMBtu, up from $7.28/MMBtu in July. Natural gas prices rose in August because of continued strong demand for natural gas in the electric power sector, which has kept natural gas inventories below their five-year (2017–2021) average. EIA expects HH price to average $9/MMBtu in in the fourth quarter of 2022 and then fall to an average $6/MMBtu in 2023, as U.S. natural gas production rises.

Natural gas production. Dry natural gas production has been rising relatively steadily since the first quarter of 2022, when it averaged 94.6 Bcfd. EIA forecasts U.S. natural gas production to average 99.0 Bcfd during fourth-quarter 2022 and then rise to 100.4 Bcfd in 2023.

Given the restricted Russian supply, demand recovery and resulting increase in crude prices, operators working the various U.S. plays plan to noticeably increase drilling activity for the remainder of 2022. Overall, activity in the Texas shale plays will improve in the second half of the year, with the exception of District 7B, District 8 and District 8A, which will suffer slight second-half losses. However, drilling on the Texas side of the Haynesville is projected to improve 26% on a y-o-y basis. Gulf of Mexico activity will increase 8.4%, but a decline of 70% is forecast offshore California, both on a y-o-y basis.

Gulf of Mexico. Higher oil prices should help boost activity slightly in the GOM, and it appears that offshore operators are poised to resume limited development in 2022-2023 after last year’s decline, Fig. 3. World Oil’s survey results and federal officials’ predicted well counts show a slight increase during second-half 2022. World Oil forecasts that GOM activity totaled 63 wells in the first half of the year, with another 65 scheduled to be drilled during second-half 2022. The projected 128-well total will be 8.4% higher than 2021’s figure of 118. Footage drilled should be up 6.6% on a y-o-y basis.

Texas. Most of the shale plays in the Lone Star State are gaining ground during 2022. On a half-over-half basis, World Oil predicts Texas wells will gain 11.6%, with the 2022 total being 39% more than the 2021 figure. In the Permian basin (Fig. 4), District 8 will be up 8% in the second half, buts its total will be 26% higher than wells drilled in 2021. Districts 7C and 8A will enjoy much-improved drilling activity, with gains of 33% and 172% respectively, compared to their 2021 totals.

The Eagle Ford forecast is also good, with District 1 forecast to improve 30% in the second half and up 64% on a y-o-y basis. District 2 will experience a 4% gain in activity in the second half, and is also projected to be up 26% on a y-o-y basis. District 4 in the Eagle Ford will experience a 47% increase between the two halves and post a massive 157% gain from 2021’s level. The reason that District 4 is surging is more gas-related activity. Of the 12 Railroad Districts, 10 are forecast to experience gains, with only two losing ground on a half-over-half basis. Again, more gas drilling is a factor, especially in RRC 6, with the Haynesville up 36% y-o-y.

DUC wells decline. According to EIA’s July 2022 tally, the DUC total stood at 4,277, a reduction of 1,680 wells since July 2021, a reduction of 28%. In the Permian basin, operators have completed 1,092 DUC wells during the July 2022-July 2021 interval, a reduction of 48%. All other regions declined too, with the exception of the Haynesville, which added 80 DUC wells up to 477, a y-o-y increase of 20%.

Oklahoma. Although the SCOOP and STACK plays are not as prolific as the Permian or Eagle Ford, acreage in Kingfisher, Canadian, Blaine, and Grady counties continues to attract interest for hydrocarbon development. But the region’s inconsistent geology and less-than-ideal shale formations have produced unpredictable results, reducing ROI. However, with higher oil prices, the plays have become more attractive, and we predict a major increase in Oklahoma’s activity. World Oil forecasts companies will drill 79% more wells in 2022 than last year’s total. Total footage will also surge forward 75%, with operators making 15.7 MMft of hole.

Louisiana. In the state’s northern portion, we forecast operators developing Haynesville shale gas will drill 25% more wells in 2022, than they did in 2021, with total footage up approximately 17%. With natural gas prices at near-record highs, the increase in activity could continue, similar to the Haynesville play in Texas RRC District 6. Despite near-record high natural gas prices, DUCs in the Haynesville were up to 477 in July, a jump of 20%. In the mature, shallow oil plays of southern Louisiana, we expect operators to drill 46% more wells compared to last year. Well footage is expected to increase 29% on a y-o-y basis.

North Dakota. The Bakken is running out of steam. Although transportation issues remain a challenge in this oil-rich shale play, a greater concern is that the sweet spot has reached maximum infill development, Fig. 5. However, higher oil prices will help negate the cost of drilling the 21,100-ft wells. Considering these factors, along with data from state officials and World Oil operator surveys, we forecast that drilling will be up a disappointing 4%, with footage increasing 2.9%, y-o-y, in the Peace Garden State.

Northeast (Pa./W.V./Ohio). In the Northeast, Marcellus activity is on an upward trend, similar to other U.S. shale plays, Fig. 6. Improving natural gas prices and increased LNG exports from Dominion Energy’s massive Cove Point facility are helping drive activity higher in the region. According to survey results, operators tapping the high-quality reservoir in Pennsylvania will increase the number of wells drilled this year by 18%, compared to the number drilled in 2021. Total footage for 2022 is forecast to jump 16.5%.

In Ohio, operators working the Utica play plan to focus on growth and capitalize on higher gas prices, with this year’s total well count expected to finish 30% higher than last year’s level. Footage is forecast to increase 31%. In West Virginia, World Oil forecasts operators will drill 84 more wells than the number spudded in 2021, up 62%. We also forecast a 64% surge in total footage in the Mountain State. Despite surging gas prices, operators working the shale fields of Appalachia were able to reduce the region’s DUC count by only eight wells in July on a y-o-y basis, a reduction of just 11%.

Midwest (Illinois/Kansas). There are approximately 32,100 oil and gas wells, 10,500 Class II injection wells and 1,750 gas storage wells producing from 650 fields in Illinois. These wells are controlled by 1,500 operators. There is oil production in 40 of the 102 counties, mainly in the southern part of the state. Drilling will surge, with a 61% increase in wells forecast for 2022, compared to 2021’s level. Although the wells are relatively shallow, they provide work for the oilfield community and the drilling crews. We forecast a 59% jump in total footage.

In Kansas, much of the shallow drilling in the Hugoton basin appears to stay below the Baker Hughes rig count radar. But according to the Kansas Corporation Commission, drilling in the Sunflower State is projected to increase 24% in 2022, compared to the 1,005 drilled in 2021. Total footage is forecast to jump 24%.

Rocky Mountains. The Denver Julesburg basin has experienced a constant decline since production peaked in November 2019. Reversing this trend will depend on the capital allocation from major operators in the region. The DJ basin accounted for 7% of oil and 6.6% of natural gas production in the Lower 48 in 2021 (GlobalData). While other U.S. basins have increased their rig count with the rise in commodity prices. Operators, like Oxy and Chevron, are earning better returns from investments in other basins, but could grow production in the DJ by completing their DUC backlog.

In Colorado, officials continue to attempt to ban, or severely limit, drilling in the state. In 2019, the state passed Senate Bill 118, “which fundamentally altered the oil and gas industry’s future in the state,” according to Colorado Governor Jared Polis. However, it appears companies intend to push back and continue operations on existing leases, as World Oil expects operators in Colorado to drill 40% more wells in 2022, compared to activity during 2021. Total footage is projected to increase by 40% on a y-o-y basis.

In 2019, a federal judge ordered a halt to exploration on 300,000 acres in Wyoming, saying the government must account for its cumulative effect on climate change. The ruling came in a lawsuit filed by a pair of environmental groups, challenging the BLM’s decision to lease federal lands for energy development in the state. Given that nearly 50% of all lands in Wyoming are owned by the federal government, a ban on federal leasing would decimate the natural gas industry and Wyoming’s economy. Despite the ongoing lawsuit, operators working in the state plan to increase drilling activity by 24% in 2022. World Oil predicts footage will increase 25%.

Canadian Overseas Petroleum received a resource report prepared by Ryder Scott that confirmed its deep oil discovery on lands in Converse and Natrona counties, Wyoming. The report confirms the deep discovery has total original oil in place of 993.5 MMbbl. This supports the company’s conclusion that the Frontier 2 and Dakota discoveries are large stratigraphic oil accumulations encompassing the reserves at the company’s Cole Creek field. The report outlines 118 horizontal well locations to exploit the identified Frontier 2 and Dakota reserves. COPL plans to drill one Frontier 1 well and two horizontal Frontier 2 wells as part of its 2022-2023 drilling campaign, commencing in fourth-quarter 2022.

Acreage in New Mexico has become as desirable as land on the Texas side of the Permian basin. Increased completion efficiencies in the Bone Springs formation will help support activity, as drilling in the Land of Enchantment is forecast to increase 23% on a half-over-half basis and 30% y-o-y for 2022. Total footage will increase 33% y-o-y.

In California, we expect onshore operators to spud four fewer wells in 2022, compared to 2021. But with no new discoveries, operators working the Golden State are forced to survive by maintaining less-attractive heavy oil fields and residual acreage from long-ago discoveries. However, considering the mature nature of these fields, onshore footage is forecast to climb 15% (y-o-y), suggesting deeper total depths as operators squeeze out more oil from these old fields. Drilling offshore California will drop dramatically, with only three wells expected in 2022, a y-o-y decline of 70%. Accordingly, footage is forecast to drop 65%.

In Alaska, the U.S. DOJ filed a brief defending the Willow project, an energy development within the NPRA on Alaska’s North Slope that has been halted by litigation. The Biden administration announced it would review the Willow plan, approved in 2020 by the Trump administration, for consistency. The project is proposed by ConocoPhillips, and if approved, the project will provide 100,000 bopd, $10 billion in revenue for state, local and federal governments during its lifespan, 2,000 construction jobs, and 300 permanent jobs. It appears the prospect of opening new acreage is having the desired effect. Offshore work will surge 109% in 2022, 12 more than spud in 2021. Onshore activity on the North Slope is projected to increase 67%, with total footage up 67%.

Others. Activity in non-core producing states will also enjoy a jump in activity. Drilling will increase on a y-o-y basis in Alabama, Arkansas, Montana, Nebraska and New York.

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The commodity price downturn is prompting price reductions among well service contractors in the greater Rockies outside the Williston Basin. In mid-January 2015, service providers report rates down about 10% quarter-to-quarter, similar to reports elsewhere in the oil patch as operators push the service sector for cost reduction. Meanwhile, larger service providers worry about further rate cutting from local, privately-held contractors. Rate reductions have not yet translated to reduction in wages for hands, although expectations are that pricing is going to drop further on the basis of lower commodity prices.

Among Survey Participants:Rig Demand Down QTQ [See Question 1 on Statistical Review]. Seven of the eight respondents said that demand had dropped in 1Q15 vs 4Q14 and all but one blamed lower oil prices for the slowing. One respondent that had seen a slowdown in demand said it was because they had finished all of their completion work. The respondent who had not seen an effect on demand said that their work was steady, but they were hearing of others slowing down.Mid-Tier Well Service Manager: “We are seeing demand slow for rigs and prices are being reduced. Operators are asking for 20% reductions, some are asking for 30% and they may get it. The greater reductions will be from people who are local because they don"t have the overhead expense. The service won’t be as good. On average, operators may get 15% of that 30% they are seeking in reductions.”

Number of Rigs Sufficient [See Question 2 on Statistical Review]. Six of the eight respondents said that the workover rig inventory is excessive for the current demand, while two said that it is sufficient but tipping toward excessive.Mid-Tier Operator: “Operators here are basically focusing on the higher production wells and going to ignore the lower ones. We have heard companies are laying down workover rigs. One company is going from 17 to 13.”

Well Service Work Weighted Toward Standard Workovers and Routine Maintenance [See Question 3 on Statistical Review]. Among all respondents, standard workover work accounts for 34% on average, routine maintenance accounts for 34%, plug and abandonment (P&A) accounts for 16% and completion work accounts for 16%.Mid-Tier Well Service Manager: “Our work slowed because we finished our completion work so the client gave us some production work to keep us steady till we finish this fracking job.”

Hourly Rates Consistent Among HP Series [See Question 5 on Statistical Review]. Most workover rig horsepower falls within the range of the 500 series. The 500 HP hourly rates average $310 to $400/hour depending on what ancillary equipment is contracted. See Table II for Average Hourly Rates.

No New Competition [See Question 7 on Statistical Review]. All respondents said that competition had not increased QTQ, and they were not anticipating it would, given lower oil prices.Mid-Tier Well Service Manager: “We worry about the small local companies undercutting prices but we are not seeing anything now.”

2015 Rates Under Pressure [See Question 8 on Statistical Review]. Five of the eight respondents said 2015 would see further reductions in demand and hourly rates and even labor rates if the price of oil did not rise. One respondent said that “iron would start laying down” if oil prices did not rise. One respondent said he expects that work demand would come back up after a couple of months as everyone adjusted.Manager for Mid-Tier Well Service Company: “As a company, we have backed off our growth budget for 2015 and our capex has been nixed. We implemented a 10% reduction in our rates. We are just going to lower rates not wages, because we can buy equipment and leave it sit, but if you do that with people, they starve.”

Hart Energy researchers completed interviews with nine industry participants in the workover/well service segment in areas of the Rocky Mountains outside of the Bakken Shale play. Participants included one oil and gas operator and seven managers with well service companies. Interviews were conducted during January 2015.

3. Looking at your slate of well service work - on a percentage basis - how much of it is workover vs. routine maintenance vs. plug & abandonment (P&A) vs. completion work?