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EVOLVE Conference 2023: Four takeaways for those that work in energy

In case you missed it, Enverus virtually hosted EVOLVE, our flagship conference, May 16-17. The event included two full days of presentations, panels and keynotes, distilling the most relevant data and thoughts on the industry today.

Below Andrew Gillick, managing director and energy sector strategist at Enverus Intelligence Research, breaks down four key takeaways from the conference for players in the energy industry.

(NOTE: Links in the post below are only accessible to existing Enverus Intelligence subscribers. Not a subscriber yet? Fill out the form below to get started.)

All eyes on macro

Some of the best attended presentations focused on the macro, as investors and operators alike are trying to figure out how wrong the curve really is – it’s always wrong, but is it wrong by 10%? 50% or more? and which way? When will we see oil demand peak? Does starving hydrocarbons of investment lead to a faster energy transition or worse energy security? The general consensus suggests long-term oil and gas demand will remain intact, although maybe not robust. Shale will be around for a while but don’t expect returns to improve until commodity prices are higher, as core inventory dwindles. PE is seeing compelling opportunity in second and third tier basins; however, at $70WTI/$3HH, public E&P equities are not all that compelling.

Who has the inventory?

For those interested in oil and gas, the focus was on inventory. Who has it and whose is getting worse? Between US Oil Supply – Twilight in West Texas, Tracking Shale Resource Degradation, and E&P Benchmarking – Separating the Best from the Rest, the team gave clients an excellent view of the remaining potential across basins. Names we liked were PXD, OXY, OVV, CTRA, PR, PDCE, CHRD, AR, RRC, TOU, ARX… although post-merger Monday deals, that might change, CHRD for XOM Bakken, working though the math and CVX for PDCE … fine, that’s an easy one. These Day 1 presentations can be found here in the vault. And if you would still like to see the live presentations you can click here.

Energy transition vs. energy security?

The discussions around energy transition vs energy security were also quite robust (my working thesis is energy transition is actually about energy security as Arjun Murti discussed in our fireside chat). And what turned out to have far more consensus than 12 months ago was something about how we are still going to need these hydrocarbons for many years to come. We heard many times that the energy transition is going to be very expensive, difficult to fund (AKA messy) and would take longer than expected. The debate then turned to, will it be worth it? Should we all just learn how to swim? Ok… no one suggested that was the best path, but swimming is a good life skill. The IRA is extremely uneven/inconsistent from a cost of carbon abatement standpoint and investors are skeptical and unwilling to bet on long-term subsidies. But don’t worry, natural gas is here to stay and consumption in power generation will be flat in the U.S. over the next decade even with a strong renewable build, details here.

Investment opportunities abound as renewable generation costs decline

This conference was not all about why hydrocarbons are still king. The ET train has left the station for better or worse, and whether it’s about the environment or energy security there are and will continue to be lots of great opportunities for profitable investment in the new energy economy. This presentation shows how the cost of renewable generation has declined exponentially over the last decade. Battery costs have declined by a factor of seven over the last 13 years (see here). And this NET Power company seems to be getting a lot of attention as technologies that combine fuels with zero carbon initiatives become uniquely attractive. It was really a sort of coming out party for our Energy Transition Research platform.

More to come on the different ways we evaluate the electron and molecule opportunities, but for now, if you are an Enverus Intelligence subscriber, log in to the vault for the presentations or back to the website conference for the replays. Let us know if you have any questions. Not a subscriber yet? Fill out the form below to get started.

NOTE: The content in this post was originally published in the Morning Energy email series written by Andrew Gillick, managing director and energy sector strategist at Enverus Intelligence Research.

Enverus selected for NET Power’s commercial initiative

AUSTIN, Texas (May 31, 2023) — Enverus, a leading energy-dedicated SaaS platform, is pleased to announce that clean energy technology company NET Power has selected it as its trusted data source for its business intelligence and analytics functions. Under terms of the commercial agreement and strategic collaboration, NET Power will leverage the full suite of Enverus’ offerings, including Enverus Fusion® Connect, Enverus PRISM®, Enverus Intelligence® and access to Enverus’ leading technical team.

Danny Rice, NET Power’s incoming CEO, said, “NET Power’s power plant technology uses natural gas in an oxy-combustion process that generates power and inherently captures carbon dioxide ready for sequestration. As preparations begin to deploy our utility-scale plants, we need to combine ‘surface intelligence’ with ‘subsurface intelligence’ to best understand where NET Power plants make the most commercial sense across North America and globally. I’ve leveraged the insights from Enverus’ data to help grow Rice Energy into one of the largest energy producers in North America, and I’m excited for this collaboration once again with Enverus to build a suite of tools and unique insights that will help us deploy NET Power plants in the right areas.”

“Through our disruptive industry-leading energy transition and oil and gas solutions, clients can make quick and confident decisions. NET Power can accomplish their carbon-free power initiative by utilizing products such as Fusion Connect, Intelligence, and our core data and analytics platform,” said Enverus President Manuj Nikhanj. “We are humbled to be selected by NET Power, who is uniquely positioned to drive and deploy their unprecedented technology forward.”

Enverus was selected for its suite of people, products and services covering power and renewables, oil and gas, and carbon capture and sequestration segments, making it the leading provider of data analytics and software solutions. The collaboration between the two companies will leverage the capabilities of Enverus’ Fusion Connect, enabling NET Power to integrate its proprietary data inside PRISM, Enverus’ energy decision-making platform.

About Enverus
Enverus is the most trusted, energy-dedicated SaaS platform, offering real-time access to analytics, insights and benchmark cost and revenue data sourced from our partnerships to 98% of U.S. energy producers, and more than 35,000 suppliers. Our platform, with intelligent connections, drives more efficient production and distribution, capital allocation, renewable energy development, investment and sourcing, and our experienced industry experts support our customers through thought leadership, consulting and technology innovations. We provide intelligence across the energy ecosystem: renewables, oil and gas, financial institutions, and power and utilities, with more than 6,000 customers in 50 countries. Learn more at Enverus.com.

About NET Power
NET Power is a clean energy technology company whose mission is to globally deploy affordable and reliable zero-emissions energy. The company invents, develops and licenses clean power generation technology. Founded in 2010 and headquartered in Durham, North Carolina, NET Power has received strategic investments from key industry partners including 8 Rivers, Constellation, Occidental and Baker Hughes. Learn more at netpower.com.

Jon Haubert | 303.396.5996

NET Power Media Contact:
Bryce Mendes | 919.443.9638

Enverus releases annual Top 100 Private E&P Operators list

CALGARY, Alberta (May 24, 2023) — Enverus Intelligence Research (EIR), a subsidiary of Enverus, has released a list of the most prolific 100 private oil and gas producers in the U.S. based on gross operated production last year. Continental Resources, Ascent Resources, Mewbourne Oil, Aethon Energy and Endeavor Energy were listed as the top five private E&P companies, according to EIR.

The list, compiled utilizing Enverus Foundations data, also includes a breakdown of liquids and gas production, total company well counts, recent rig programs and comparison to their rankings the previous year. It was a portion of the most recent Upstream Pulse from Enverus, a bi-monthly report that covers exploration and production, deals and capital markets for the North American and global oil and gas sector.

“Enverus is uniquely positioned to provide a list of private companies that investors and operators need to pay attention to. Public companies disclose capital plans and production volumes in regular financial filings, but private operators can fly under the radar. Private companies deliver a large proportion of domestic production and keeping a finger on their pulse can help forecast regional supply/demand imbalances,” said Gibson Scott, head of Intelligence at EIR.

“Information on private companies can be limited, but not for Enverus. We’ve spent more than two decades innovating and developing solutions to become the leading energy-specialized technology partner with unrivalled analytics and network applications delivered across the entire energy ecosystem,” Scott said.

Members of the media should contact Jon Haubert to schedule an interview with one of Enverus’ expert analysts.

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About Enverus Intelligence Research
Enverus Intelligence Research, Inc. is a subsidiary of Enverus and publishes energy-sector research that focuses on the oil and natural gas industries and broader energy topics including publicly traded and privately held oil, gas, midstream and other energy industry companies, basin studies (including characteristics, activity, infrastructure, etc.), commodity pricing forecasts, global macroeconomics and geopolitical matters. Enverus Intelligence Research, Inc. is registered with the U.S. Securities and Exchange Commission as a foreign investment adviser.

Media Contact: Jon Haubert | 303.396.5996

How to capitalize on refinancing

In the current landscape of heightened environmental and social consciousness, upstream oil and gas companies face significant challenges in achieving favorable refinancing for their existing credit facilities. These challenges are compounded by the recent volatility in the debt markets and instability in commodity prices, making it even harder for CFO and treasury teams to find favorable lenders.

A few implications of failing to secure the best possible terms during credit facility refinancing include:

Higher interest costs
Increased debt burden
Restrictive negative covenants

These consequences can strain an upstream operator’s ability to operate effectively and return capital to shareholders.

Refinancing in the dark

The refinancing process is plagued with data sprawl and obscured information.

The process requires the use of industry-specific information that is not commonly documented by many financial data providers.
Modern upstream credit facility agreements include covenants and terms such as production volume targets and ESG metrics that significantly impact debt pricing and interest rates, but often remain hidden deep within the agreements.

Transparent capital sourcing solution

It is critical to expose this data from the shadows, so treasury teams can have all the information and insights needed to identify the best refinancing terms relative to their peers. Enverus Capitalize provides a comprehensive dataset and industry-specific insights that treasury teams can leverage to streamline the lender identification and negotiation process. The platform’s actionable insights are instrumental in securing favorable refinancing terms, especially given the current market conditions and variables that influence refinancing decisions.

Credit facility A redetermination example

Let’s consider the case of a theoretical treasury team at an upstream operator in the process of extending their credit facility maturing in 18 months, leveraging Enverus Capitalize. First, the team identifies the refinancing terms, such as interest rates and operational covenants of their peers, and uncovers which lenders were actively increasing exposure to their peers.

recent-m&a-transactions-and-critical-valuation-metrics-from-enverus-capitalize-m&a-analytics — *Figure: Recent M&A transactions and critical valuation metrics from Enverus Capitalize (M&A Analytics)*

Next, once they are armed with this information, they can work closely with these lenders to negotiate the most optimal credit agreement and set up the most business-friendly bank group.

example-of-credit-facility-allocation view-for-multiple-operators-from-enverus-capitalize-ma-analytics — *Figure: Example of credit facility allocation view for multiple operators from Enverus Capitalize (M&A Analytics)*.

Finally, the team confidently secures their refinancing agreements with a clear view of the terms and covenants.

Conclusion

Enverus Capitalize plays a crucial role for treasury teams hoping to navigate the opaque and intricate landscape of credit facility refinancing. By helping treasury teams avoid terms and conditions that lead to negative investor perceptions, future covenant violations and credit rating downgrades, Enverus Capitalize helps maximize the potential for increased returns to shareholders.

To learn more about Enverus Solutions, learn more here

Unprecedented wildfire season singes Alberta oil production

Wildfires that have already scorched more than double the average annual fire destruction across Alberta forced the shut-in of more than 300,000 boe/d while threatening future shuttering of output from the so-far largely unaffected oil sands region. Record temperatures saw 92 active wildfires, 28 of which were out of control as of May 17, forcing nearly 40,000 people from their homes as evacuation orders spread primarily in the province’s northwest and into northeast British Columbia. Extreme heat and air quality warnings were in effect across much of Alberta in mid-May and, barring a significant shift in weather that brings a lot of moisture, it could be months before the fires are brought under control, according to provincial officials.

Several oil companies reported production shutdowns through the first half of May as some wildfires were contained and others ignited, though reported damage to facilities was minimal. Citing Refinitiv data, Reuters said some 319,000 boe/d, or 3.7% of Canada’s production, had been shut in, while consultancy Rystad Energy said nearly 2.7 MMbbl/d of oil sands production was at risk in “very high” or “extreme” wildfire danger rating zones. In a note, Enverus Intelligenceâ | Research (EIR) said about 500,000 boe/d could be at risk of curtailment, with roughly 10,000 producing wells affected. Production in the Deep Basin was the most impacted, with some companies shutting in more than 60% of their total production bases. The blazes bolstered the price of natural gas at AECO more than 20% while the discount for WCS oil narrowed to levels not seen in over a year.

Climate change “is proceeding right in front of our eyes,” Joseph Shea, an associate professor in environmental geomatics at the University of Northern British Columbia, told the CBC, adding that heat dome events are only going to become more frequent.

Among the companies that have announced shut-ins, Cenovus Energy shut in multiple producing conventional fields and brought down processing plants May 4, resulting in about 85,000 boe/d, primarily dry gas, impacted in the Rainbow Lake, Kaybob-Edson, Elmworth-Wapiti and Clearwater areas. Crescent Point Energy shut in its Kaybob Duvernay production. While a portion was reactivated, Crescent Point shut back in the remainder of its 45,000 boe/d because of changing wildfire conditions.

NuVista Energy shut in and depressured all operations proximal to wildfires at Grande Prairie, impacting about 40,000 boe/d. Paramount Resources advised that the third-party Wapiti gas processing facility and the company’s fields producing to the facility were again shut down May 12, with about 45,000 boe/d at Grande Prairie and Kaybob curtailed as of May 14.

Whitecap Resources reported about 26,000 boe/d was shut in over the first two weeks of May. Pipestone Energy said May 15 its operations in the Grande Prairie area are again being impacted by wildfires because of the shut-in of third-party infrastructure, with about 20,000 boe/d curtailed since May 12. Baytex Energy said wildfires impacted Peace River and Peavine operations in northwest Alberta, with about 20,000 boe/d curtailed and about 4,000 boe/d cut because of the shut-in of third-party infrastructure.

Obsidian Energy took Peace River area fields at Seal, Walrus and Nampa offline and reported about 1,200 boe/d of production would remain temporarily curtailed. Obsidian was able to restore 2,500 boe/d at Pembina as of May 17, leaving 8,500 boe/d offline in the area. In total, roughly 9,700 boe/d of the company’s production was curtailed across Peace River and Pembina.

Vermilion Energy reported that it restored about 60% of the 30,000 boe/d temporarily shut in in west-central Alberta and production guidance of 82,000-86,000 boe/d remains unchanged. Kelt Exploration shut in about 5,000 boe/d (77% gas) as of May 15 and reported it had drilled three of its budgeted five Montney wells at Oak, with drilling operations suspended. It expects to drill its remaining two wells in June.

Tourmaline Oil reported seven of its nine southern and western Deep Basin gas processing facilities previously shut in had resumed operations. Two of the facilities, West Wolf and Columbia, were undamaged and ready to resume operations awaiting final start-up clearance, with net production of about 16,000 boe/d shut in. Athabasca Oil Corp. shut in two facilities at its light oil operations at Kaybob and estimated 2,300 boe/d of temporary production downtime.

Kiwetinohk Energy announced the shutdown of production from its Placid field because of wildfires in the Fox Creek area. Its Simonette and Placid facilities remained shut in until third-party infrastructure is operational.

TC Energy said May 17 it continues to run its NOVA gas transmission and other pipeline systems in western Canada and that the Coastal GasLink project continues to progress with the project route safely away from current wildfires. It was able to complete the controlled restart of compressor units at all locations that were previously shut down because of wildfire precaution. Pembina Pipeline facilities previously shut down because of the wildfires have resumed operations.

The wildfires’ location and severity were imported into PRISM using Enverus Fusion® to analyze risks to producing wells and processing facilities. Click for more (available to EIR subscribers)!

About Enverus Intelligence Publications
Enverus Intelligence Publications presents the news as it happens with impactful, concise articles, cutting through the clutter to deliver timely perspectives and insights on various topics from writers who provide deep context to the energy sector.

CCUS | Risky business?

CO2 containment risk has become one of the most popular topics among our clients evaluating CCUS projects. Operators need to understand and evaluate subsurface features that could trigger CO2 migration and containment losses as well as introduce additional safety, reputational and financial risks. These considerations are also important aspects of the Class VI application process for permanent CO2 sequestration.

FIGURE 1 | CO2 containment risks from existing well infrastructure

*Source | Enverus Energy Transition Research*

Highlights from Energy Transition Research

CCUS: Location, location, location
Energy Transition Pulse is published every two weeks by Enverus and covers the renewable energy sector, including projects, the deal market, finance and new technologies.
PE P&R Deal Activity – International diversification a key focus
This PRISM Signal reviews recent private equity sponsorship trends across power and renewables portfolio companies utilizing the Private Equity Database from Enverus.
2023 Thematic Outlook
This report provides a list of themes we expect will shape energy markets in 2023.

Check out last week’s blog on A lifetime without charging in public

Energy is changing. Connect weekly with the ideas that are leading the way.

About Enverus Intelligence^®| Research
Enverus Intelligence Research, Inc. is a subsidiary of Enverus and publishes energy-sector research that focuses on the oil and natural gas industries and broader energy topics including publicly traded and privately held oil, gas, midstream and other energy industry companies, basin studies (including characteristics, activity, infrastructure, etc.), commodity pricing forecasts, global macroeconomics and geopolitical matters. Enverus Intelligence Research, Inc. is registered with the U.S. Securities and Exchange Commission as a foreign investment adviser. Click here to learn more.

A lifetime without charging in public

Anyone who thinks spending time at a public charging station is a blocker to buying an electric vehicle (EV) might want to consider the numbers behind EV and internal combustion engine (ICE) vehicle refueling times. The answer is that it really depends on your use case and primarily these two questions:

• How many long-distance trips do you take each year?

• Do you take them during winter and live in a colder climate?

FIGURE 1 | Annual time spent charging by long-distance trip

*Source | Enverus Intelligence Research*

Figure 1 breaks down the math on annual fueling times between the various alternatives. Differences in battery chemistry impact charge times as well as weather-dependent range. Most drivers take less than one trip per year outside the range of modern EVs and will actually save time spent at public fueling stations with an EV over an ICE. “Weekend warriors” and “road trippers” will most likely realize the effects of range limitations the most as their time spent at public charging stations could be longer. They would benefit most from high nickel chemistries that increase energy density and vehicle range.

Highlights from Energy Transition Research

Electric vehicles – A call on capital
This report examines demand for key minerals and areas, particularly in mineral recycling and battery technology where innovation is most impactful.
Power Generation BeatBox 1Q23 – VST, IDA and NRG positioned for big beats
This report series attempts to predict beats and misses on consensus revenue expectations for public power producers using our proprietary data-driven quantitative model.
CAISO solar challenge – Exponential growth degrades prices
This report explores the impacts of the Inflation Reduction Act on the development of CCUS projects in the United States.

Check out last week’s blog on “Securing domestic supply of lithium”

Energy is changing. Connect weekly with the ideas that are leading the way.

Recession fears weigh bullish oil fundamentals down, higher natural gas prices needed

CALGARY, Alberta (May 9, 2023) — Enverus Intelligence Research (EIR), a subsidiary of Enverus, the most trusted energy-dedicated SaaS platform, has released its latest quarterly FundamentalEdge report focused on global drivers for oil and gas prices to 2030, the five-year oil and gas supply and demand outlook, as well as price forecasts.

“Current prices are weighed down by recession fears despite bullish oil fundamentals. We anticipate the anxiety around the possibility of extreme recessionary conditions to fade and oil prices to appreciate into triple digits in the back half of 2023,” said Al Salazar, senior vice president at EIR.

“Following $3-4/MMBtu pricing in 2024-25 we expect higher natural gas prices are needed to incent the considerable amount of natural gas needed to feed LNG facilities slated to come online mid-decade,” Salazar added.

Key takeaways from the report:

India’s growing oil demand offsets the weaker demand seen in the U.S. Y/Y. Strong oil demand from India and China is expected to drive demand growth through 2023.
LNG is the primary source of natural gas demand growth through the decade. More than 10 Bcf/d of LNG demand forecast to come online by 2030. There is significant commercial momentum, and EIR only sees upside to its LNG demand forecast.
U.S. crude production forecast to grow to 12.9 MMbbl/d by the end of 2023, with growth slowing to 0.2-0.3 MMbb/d every year after before plateauing in 2028.
L48 dry gas production forecast to grow to 101 Bcf/d by the end of 2023.  Lowered completion activity is expected to persist through 2024 keeping production growth limited until it is needed to grow for the LNG demand coming online mid-decade.

Members of the media should contact Jon Haubert to schedule an interview with one of Enverus’ expert analysts.

Media Contact: Jon Haubert | 303.396.5996

Enverus Blog - 6 tax preparation tips for mineral and royalty managers

Confidently acquiring minerals in a complex market

Recent years have been a roller coaster for mineral buyers, from record low commodity prices to highs for oil and natural gas in the last year. Going forward, challenges and opportunities will be plentiful.

We expect oil prices between $80 to $120 in 2023 with prices settling around $90 for the year as U.S. production is slow to respond to global demand and the war in Ukraine continues. For mineral owners looking to sell or hedge investments with a partial sale of producing oil assets, the current pricing environment is a good bargaining chip. However, the excessive multiples of 2017 and 2018 have yielded to steadier profit margins with royalty interests attracting 7x on average EBITDA cash flow multiples.

Coming from 2022’s strong prices, natural gas is now on a lower glide path due to ample supply. The center of gravity is shifting from the Haynesville to the Permian, where the economics of associated gas production do not always benefit mineral owners (e.g., Wahab prices have hit negative territory). All signs point to the U.S. transforming into a major exporter of LNG in the next few years, providing sound opportunities in the long term for mineral buyers who can acquire in prime acreage positions that will benefit down the road in Appalachia, Louisiana and Texas.

Mineral buyers face myriad challenges and risks in such a complex market. Determining fair market value for oil and natural gas assets is critical to acquiring at the best price and uplifting margins. Complexities in leases and mineral ownership make it imperative to perform due diligence on every deal, not just big ones. Mineral buyers must also contain acquisition costs as they verify ownership and ensure that costly title defects don’t creep into their portfolios.

Let me share just a few simple strategies and Enverus tools that will bring tremendous firepower to your search for quality acquisition targets and due diligence.

Reaching the Right Mineral Sellers With the Right Revenue

Beginning with the end in mind, mineral buyers need a targeted list of prospects, whether that’s a short list of mineral owners on a tract or a spreadsheet for an entire county to take to the USPS bulk mailing service. Given the volumes of public data to sift through and lack of clarity into fair market value, setting up efficient and profitable outbound lead generation has historically been time, labor and cost intensive.

Enverus Texas Mineral Appraisals is a cloud-based solution that enables mineral buyers to rapidly map, find and evaluate the most valuable mineral, royalty and working interest opportunities, from the Permian and Eagle Ford to the Barnett and Haynesville Shales. It allows acquisition teams to gain a deeper understanding of well production, assess current fair market value, determine the right multiples for acquisitions or divestitures and, finally, export the target list to power prospect outreach.

Additionally, the lease level production reported by operators to the state is allocated to the well level by Enverus, which can then be rolled up for a more accurate analysis of property value.

Verifying Mineral Ownership and Interest Type

With mineral ownership constantly changing hands due to inheritance, conveyances or A&D, interest decimals are split time and again, underscoring the need for mineral buyers to verify a prospect’s ownership and determine if royalty checks are from a lease or non-participating royalty interest. Overlooked title defects and issues are difficult to unravel and time consuming and expensive to fix, so it’s better to figure it out upfront with a simple title check to know exactly what you will be in pay on.

Texas Mineral Appraisals offers comprehensive ownership history that helps with verifying decimals. Extend your pre-acquisition due diligence with Enverus Courthouse, which currently includes documents from 150 Texas and New Mexico counties, with many dating back to sovereignty and continually expanding coverage.

Armed with Courthouse, your team can move rapidly on a deal and gain first mover advantage by searching an abstract survey, section, lot or block to find ownership records. Easily pull up titles in an AOI, search for name references and drop key data on a map, such as mineral deeds in the last six months, conveyances, plats, easements, right of ways and probates. Additionally, Courthouse can be leveraged for competitor research to gain insights on who is buying and aggregating.

Shrinking Your Acquisition Costs

In today’s complex minerals market, running title should be considered no matter the deal size. In the past this meant that mineral buyers needed to personally visit county courthouses to research ownership or hire landmen to run title. Enverus Courthouse provides access to real property records, simplifying and accelerating running title, which leads to lower costs.

For larger or more complex title checks involving multiple landmen and attorneys, Courthouse allows everyone involved to collaborate around runsheets. By working more efficiently with digital courthouse records at their fingertips, land and legal can be more productive, driving a new level of transparency and cost efficiency for mineral buyers.

Watch a recent on-demand webinar with Silas Martin and CEO of Tract, Ashley Gilmore as they share tips and workflows to rapidly verify mineral ownership and identify the right mineral asset.

Efficiency Matters: Track and Evaluate Mineral Ownership in Minutes | Enverus

Key Takeaways

With the right approach, data and tools, land professionals and mineral buyers will better navigate today’s complex market. Texas Mineral Appraisals and Courthouse empower you to:

Easily pinpoint quality acquisition targets for lead generation
Establish fair market value and revenue multiples
Rapidly screen for risks using digital courthouse records
Quickly and accurately verify ownership through real property records
Minimize capital expenditure and time by streamlining title process

For a deeper dive into market drivers that influence mineral investment strategies, download a copy of the 2023 Minerals Market Report. You can also learn how to find the best investment opportunity and allocate resources better with fast mineral valuation and title research. Click link to learn more: Fast-Track Mineral Ownership Research

To talk to an expert and get a live a live demo of Mineral Valuation and Title research solutions, please fill out the form below.

Powering through outage season: A breakdown of PJM’s WHUB/NIHUB spread

It’s that time of year when generator and transmission outages are at their peak in PJM. The first half of April has not disappointed volatility-wise as the WHUB/NIHUB spread has set new 30-day highs largely driven by congestion.

Figure 1: Day-ahead WHUB/NIHUB MCC spread for the last 30 days with the constraints driving this spread split out below

Among the top constraints to impact this spread are CHIC_AVE – PRAXAR (138KV) and WEED-MAHO (138KV) in northern Illinois, which discount NIHUB when binding.

Figure 2: Top three day-ahead binding constraints impacting NIHUB for the last 30 days

Using MUSE’s decomposition views to breakdown the drivers of these constraints by transmission outages, generation and load, we can quickly see if outage season is the driver behind these constraints.

Looking at constraint flows and decompositions for CHIC_AVE – PRAXAR (138KV) we can see the frequency of DA binding has increased with two outages that began in March. These outages don’t roll off until May, indicating this may continue to be a driver of the WHUB/NIHUB spread.

Figure 3: MUSE constraint decomposition for CHIC_AVE – PRAXAIR (138KV)

Next, let’s dive into WEED-MAHO (138KV), wherewe can see day-ahead binding events increasing in frequency with two outages that began in March. Recently, however, an additional outage has started that is relieving this congestion, decreasing the frequency of DA binding events. This gives a signal that the congestion may alleviate and, in turn, reduce pressure on the WHUB/NIHUB spread.

Figure 3: Real-time/day-ahead shadow prices for WEED-MAHO (138KV) with base decompositions below

Outage analysis on WEED-MAHO (138KV) is possible due to MUSE PJM’s new Base Decomposition feature. With this feature, you can now understand the impact of transmission outages on congestion for any constraint, even ones without constraint flows, giving you a leading indicator for decision making this outage season.

Do you have other spread you would like to analyze? Want to see how MUSE could help you make faster, more confident decisions? Let us help you be the first to know exactly why new constraints bind.

Get Started

April’s energy outlook: Analyst insights you can’t miss

May marks a new month, and it’s essential to assess the energy landscape of April. Our Enverus Intelligence® | Research (EIR) team has scrutinized critical trends and advancements, delivering to you insightful analyst takes that can shape your business decisions. Being well-informed will enable you to leverage upcoming energy opportunities in 2023. Continue reading and uncover the latest energy market insights.

Oil equities reign supreme: However, long-term opportunities in gas or hybrid equities (April 20, 2023)

Our near-term outlook for commodity prices favors oil equities over the next 12 months, but we continue to like long-term opportunities in gas or hybrid equities following the U.S. LNG buildout. Lower leverage across the space has reduced oil price beta differentiation across peer groups. We estimate that a $10 improvement to WTI prices increases our median valuations by approximately 25% for both large-cap and SMID equities. Investors focus on inventory quality and depth is reflected in trading multiple premiums amongst the peer-groups with inventory-advantage large-caps trading at a premium to SMID peers.

Big players, big opportunities: Large-caps win out on core Permian inventory deals (April 20, 2023)

We expect upstream M&A will build on an active start to the year as more oil-focused E&Ps join the fray to secure a dwindling number of high-quality inventory opportunities. Pricing for core Permian inventory has already topped $2 million per location and a deal pricing at $3 million and up is likely this year. Given the need to also keep deals accretive to financial metrics, core opportunities will likely go to large-caps with premium equity valuations. Meanwhile tier two or three Permian inventory, which has been selling for $1-2 million per location, plus smaller and cheaper bolt-on opportunities, will be targeted by SMID-caps. Given a focus on undeveloped DSUs, combined with a likely willingness to sell, we see Ameredev, CrownQuest and Tap Rock as among the top targets in the Permian. Equal quality inventory outside the Delaware and Midland basins is similarly priced but rarer to find. More assets in other plays are weighted towards locations with breakeven pricing at $50/bbl or more and are transacting at production value only or a modest premium for upside. The Eagle Ford is ripe for more M&A of this type, especially by new entrants Baytex Energy and INEOS.

From Golden State to duck curve: The changing landscape of solar power in California (April 18, 2023)

California used to be a golden state for solar power producers, but exponential solar growth has led to a timing imbalance between peak demand and solar generation, referred to as the “duck curve.” This has caused a decline in net power demand during peak solar hours, leading to a discount in the capture price for solar projects in the California ISO. However, this could be a boon for projects with co-located battery storage, as they can charge with discounted power during the day and discharge during evening peak pricing. These flexible resources will be critical in maintaining system reliability as renewable penetration increases to meet state-mandated goals of 100% zero-carbon energy supply by 2045 (read more here).

First oil achieved: A look at Mad Dog Phase 2’s journey (April 14, 2023)

After dealing with start-up snags for six months, BP, WDS and CVX eventually achieved first oil at Argos platform in Gulf of Mexico. Mad Dog Phase 2 features 14 producer wells and is expected to reach its 140 kboe/d capacity by the end of this year. On a development-forward basis, we estimate the 750 MMboe project requires a $47 WTI price to break even. Commencing production on schedule, in late 2021, would lower the breakeven by $4/boe.

Dairy RNG facility delayed after devastating explosion at Texas farm (April 14, 2023)

South Fork Dairy in Dimmitt, Texas, exploded on Monday killing an estimated 18,000 of the approximately 19,000 cows onsite, which the county sheriff believes was caused by a manure vacuum overheating which ignited methane in the air and allowed a fire to spread to where the cows were held. Construction had recently started on a dairy RNG facility at the South Fork Dairy that was going to be operated by CLNE, but that project was unrelated to this tragedy. It was forecasted to produce 2.6 million GGEs per year of ultra-low CI RNG once completed but will likely be delayed now if not completely scrapped. CLNE has traded flat since the announcement on Monday (April 14, 2023) evening.

Uncovering the hidden treasure trove: Montney’s underreported liquids production (April 12, 2023)

We estimate that approximately 40% of cumulative Montney wellhead liquids production, equivalent to approximately 302 MMbbl, has been underreported in raw public production data since the start of horizontal well development. After correcting for the underreporting, the entire Montney fairway emerges as an extremely competitive and profitable player among North America’s top plays (read more here).

OVV’s bold move: Tripling its inventory and doubling its life with EnCap’s portfolio (April 04, 2023)

OVV’s bold move to buy all three of EnCap’s marketed portfolio companies (Black Swan, PetroLegacy, Piedra) resulted in a 12% rally in its stock price, more than double the XOP. The outperformance was warranted in our view as the $4.275 billion worth of Midland properties that also contain among highest percentage of undeveloped DSUs nearly doubled OVV’s corporate inventory life of sub-$50/bbl breakeven locations from around three years to nearly six. EnCap may have come out even better as it was able to unload around 700 core locations at more than $2 million each after we fully valued the high-decline production base at PV-10. On the other side, EnCap portfolio company Grayson Mill scooped up OVV’s Bakken asset for PDP PV-20 in our view and got around 100 locations (half sub $50/bbl breakeven) for free. The relative pricing is a sign of the market with few big, strategic opportunities left to buy inventory and multiple companies that need them while PDP-weighted opportunities are more plentiful.

Powering the future: Why lithium, copper and nickel demand will skyrocket with EV adoption (April 3, 2023)

The rapid adoption of electric vehicles (EVs), with a projected 65% market penetration by 2030, is poised to significantly impact the lithium, copper, and nickel markets. As integral constituents in EV batteries, the demand for these metals is anticipated to experience a remarkable surge. Our recent report emphasizes this escalation in demand will render the markets for these critical metals tight until 2035. EIR foresees factors such as diversified battery technologies, metal substitution and recycling will mitigate potential supply constraints, ensuring the availability of metals for battery production and bolstering the widespread adoption of EVs. Investors and stakeholders in these metal markets should prepare for noteworthy growth opportunities, specifically in copper markets where commodity price is yet to reflect anticipated tightness.

OPEC’s surprise cut: Shockwaves through oil markets (April 3, 2023)

To the surprise of many, OPEC announced a plan to cut their output by 1.16 MMbbl/d from February production levels beginning in May and lasting until the end of 2023. Russia has also agreed to extend their cut of 0.5 MMbbl/d which was set to expire this summer to the end of the year. We have previously noted that we expect OPEC to respond if prices remained below $85/bbl for a longer period of time but are surprised by how soon the response came. This surprise cut from OPEC provides fundamental support for our call of $100 oil by 3Q23. (click here to learn more)

Green, but not green enough? Canada’s clean tech plan compared to the U.S. (April 1, 2023)

The Canadian government unveiled its 2023 budget, featuring a $21 billion Made-In-Canada plan aimed at bolstering the nation’s presence in the clean technology sector. The plan primarily focuses on electrification, clean technology and hydrogen, with 78% of funding allocated to these areas. The introduction of “Contracts for Difference” to support future carbon and hydrogen prices is a key component in de-risking CCUS investments and fostering competition with the IRA’s 45Q tax credit. While the budget provides competitive investment opportunities in battery manufacturing and zero-emission technology supply chains, it is our view that the U.S. still offers superior incentives for RNG, hydrogen, biofuels and EV charging network infrastructure.

Keeping up with an evolving industry

With the energy sector constantly evolving, staying ahead of the game is crucial, and keeping up with new developments is key to success. To stay informed on the energy industry, we invite you to subscribe to EIR’s LinkedIn page. Thank you for taking the time to read through our latest energy industry update, and we look forward to continuing to provide valuable insight into navigating today’s ever-changing energy landscape!

About Enverus Intelligence Research
Enverus Intelligence Research, Inc. (“EIR”) is a subsidiary of Enverus and publishes energy-sector research that focuses on the oil and natural gas industries and broader energy topics including publicly traded and privately held oil, gas, midstream and other energy industry companies, basin studies (including characteristics, activity, infrastructure, etc.), commodity pricing forecasts, global macroeconomics and geopolitical matters. Energy Transition Research is a research division of EIR focused on topics including Power & Renewables, CCUS, Low-Carbon fuels and Emissions. Enverus Intelligence Research, Inc. is registered with the U.S. Securities and Exchange Commission as a foreign investment adviser. See www.enverus.com/disclosures for additional information.

Top 3 pitfalls of using acreage math to calculate remaining inventory

Inventory is king in 2023. Operators and investors alike are more concerned than ever about remaining inventory – who has it, where is it, and will it be economic? To answer these questions, most turn to the tried-and-true, but also tedious and time-consuming method of calculating future well locations – acreage math.

Acreage math has long been the industry-standard approach to calculate the future potential development on a given area of interest by engineers and analysts. While it is straightforward, there are pitfalls because development styles and patterns have changed since acreage math was popularized.

Three main factors that cause errors in acreage math calculations are:

Not considering offset wells and cube style development.
Geologic complexity can’t be written off with a blanket viability risk factor.
Acreage orientations and sizes can result in laterals that aren’t placed to optimize the area.

As development styles have changed, so should your approach to calculating inventory. Leveraging technology for speed, and analysts for quality control, Enverus Placed Well Analytics helps to avoid these pitfalls and increase accuracy of remaining inventory evaluations- all in a matter of minutes.

Pitfall 1: Not Accounting for Offset Wells

With the shift to multi-well and cube style development in recent years, acreage math can result in an overestimation of sticks.

Acreage math cannot account for what has already been drilled and lacks the sophistication to distinguish drillable acreage from uneconomic acreage due to well degradation. It lumps all the non-drilled acreage together and assumes that a certain number of wells can be placed into the open space, compounding inventory counts exponentially.

The Solution: Consider existing wells

Enverus Placed Well Analytics places sticks to be offset from existing wells at four or five different spacing scenarios per play. It can also take existing wells into account and ensure there is enough “buffer room” to place sticks around them in a DSU. Sticks will not be placed within 100 ft of the DSU boundary. To ensure that stick counts stay up to date and accurate, existing wells are updated monthly so that any undrilled location that sees drilling activity is converted to an actual well.

*Figure 1*: *Enverus Placed Wells (pink) for the Wolfcamp A and Lower Spraberry in the Midland Basin accounting for producing wells, drilled uncompleted (DUC), Completed well status.*

Pitfall 2: Overestimating in Complex Geology

Geologic complexity is often left out of the equation because it can add weeks of work to acreage math to properly risk off. This means that sticks could be placed in zones that are not geologically viable, whether due to reservoir quality or structural features. With acreage math, we commonly see a simple percentage applied to risk off the total, but it doesn’t get specific enough to determine which zone is at risk or what should be avoided.

The Solution: Consider well-level geo properties, spacing, infrastructure and economics together

In calculating inventory with Placed Well Analytics, the user can interact with well level geological properties, while also layering on spatial positioning and economics. It is also important to note nearby activity in case your future inventory plan coincides with an offset neighbor. Not knowing offset activity could cause delays due to shut-in wells. Future inventory tie-ins with existing pipelines and facilities must also be considered in your analysis.

Having all aspects of development in a single view means that instead of applying a blanket risk factor to your calculations, you can clearly define what the future potential development of your AOI could look like – in under an hour. This interactive and dynamic methodology allows for a smooth and transparent workflow when compared to acreage math, which relies on arbitrary risk factors and manual Excel workflows, often losing precision and granularity in the process.

geo-tags — Figure 2: Geologic complexities in the Delaware Basin can contribute a significant amount of risk to future inventory locations which Placed Well Analytics can make understanding that risk faster by having wells tied to geologic properties and geologic grids in one platform while calculating inventory.

Pitfall 3: Not Accounting for Acreage Orientation

Acreage orientation and size can also cause complications in optimizing future locations for certain lateral lengths. It can result in errors or be an extremely manual and time-consuming process to account for.

Acreage math lacks the ability to take the spatial setup into account. It sums up all unused acreage and considers it as “fair game” for development. Inevitably in the process, credit is ascribed to tiny and awkward areas of land that can only fit minimal lateral lengths and will probably never be drilled. This failure to account for correct acreage orientation can inflate remaining inventory counts by up to 50%.

The Solution: Plan based on future development

Placed Well Analytics prevents the inflated stick counts yielded by acreage math by giving a spatially realistic view of what future development will look like. A standardized set of DSUs, crafted by Enverus analysts with basin-specific expertise set the precedent for future well orientation. To reflect realistic development, sticks follow the azimuth trend of these DSUs, and the longest lateral possible is placed at the selected spacing scenario.

dsu — *Figure 3: Placed Well Analytics accounting for DSU orientations in the Midland Basin – Howard County.*

Conclusion

Inventory is the single most important factor going into every company evaluation in 2023. Make sure you are adapting your methods away from acreage math, with its many pitfalls, to model future inventory faster and more accurately.

Ready to quit drawing sticks on a map to evaluate your remaining inventory? Discover Enverus’ expert workflows and gain valuable insights to de-risk your energy portfolio with our on-demand webinar.

About Enverus Intelligence®| Research
Enverus Intelligence Research, Inc. is a subsidiary of Enverus and publishes energy-sector research that focuses on the oil and natural gas industries and broader energy topics including publicly traded and privately held oil, gas, midstream and other energy industry companies, basin studies (including characteristics, activity, infrastructure, etc.), commodity pricing forecasts, global macroeconomics and geopolitical matters. Enverus Intelligence Research, Inc. is registered with the U.S. Securities and Exchange Commission as a foreign investment adviser. Click here to learn more.

Securing domestic supply of lithium

In last week’s issue of Energy Transition Today, we discussed the significant drop in solar capture prices in California over the past five years. This decline presents a valuable opportunity for solar projects to utilize co-located battery storage, charging them with affordable solar power during daylight hours and discharging the stored energy in the evening to capitalize on higher peak pricing. From co-located battery storage to electric vehicles, we see rising demand for battery production and battery metals like lithium, and by 2035 we anticipate lithium demand to increase by 350,000 tonnes from 2019 levels.

Currently, 95% of the global lithium supply is mined in just four countries: Australia, Chile, China and Argentina. The U.S. only contributes 1%, illustrating the need to secure local production as demand increases. Recent government policy changes offer hope, with the Defense Production Act allocating up to $1 billion per year to boost domestic mineral development and the Inflation Reduction Act introducing a 10% critical minerals tax credit on mining and refining.

However, bringing new mines online can take decades and evaporative salars have geographical limitations due to their need for extremely dry environments. This is where direct lithium extraction (DLE) comes into play. Currently being tested for commercial viability, DLE has the potential to extract lithium from large volumes of low-concentration lithium brines. If successful, DLE could unlock almost limitless domestic lithium production, either from dedicated brine resources or from the approximately 3 billion barrels of oilfield wastewater produced monthly in North America.

FIGURE 1 | Yearly Lithium Production and Revenue Potential

Figure 1 shows the potential for lithium extraction and revenue from wastewater for five operators in the Delaware Basin. With a total of 29,000 tonnes/year, generating $600 million in additional revenue at a $20,000/tonne spot price, the implications are clear. If DLE proves successful, it could not only meet domestic lithium demands but also generate significant revenue in the process.

Highlights from Energy Transition Research

A Simple Guide to Energy Transition Metals

This report presents a supply and demand outlook for metals that will be crucial in supporting the decarbonization of the energy system.

A Simple Guide to Synthetic Fuels

What will it take for synthetic fuels to play a significant role in the replacement of hydrocarbons in the transportation sector?

The Inflation Reduction Act – Impact on CCUS

This report explores the impacts of the Inflation Reduction Act on the development of CCUS projects in the United States.

Energy is changing. Connect weekly with the ideas that are leading the way.

Welcome to Enverus EVOLVE: The future of energy

Austin, Texas (May 4, 2023) — Enverus, the most trusted energy-dedicated SaaS company, is inviting members of the media to EVOLVE, its annual conference that will be held virtually May 16 and 17. Enverus EVOLVE is the only conference that explores the future of energy through a connected community where attendees will learn how to overcome the most complex, dynamic and challenging energy transition humanity has ever faced.

New this year will be the company’s acclaimed Play-by-Play presentations that include basin-level market insights. These analyst-led sessions will focus on how macro market trends fit in with energy transition, how oil and gas can compete, with most of the resource base known and massive quantities of data at our disposal and discuss renewable markets both now and in the future. Fusion Connect, Enverus’ hallmark energy decision-making tool that blends customer data in the PRISM platform, will also be prominently featured and utilized in real time throughout the conference.

Enverus will offer the opportunity for attendees to participate in its new Professional PRISM Certification course focused on Advanced Analytics & Asset Optimization during EVOLVE. By promoting their ENVERUS PRISM® expertise and showcase transformative skills applied across the energy value chain, L&D certificate holders distinguish themselves amongst other industry professionals.

Notable speakers

Greg Bensen, Head of M&A, BPX
Anthony Borreca, Senior Managing Director, Stonepeak
Anne Cameron, Co-Head, US Equities, Hartree
Michael Cohen, US Economist, BP
Frederick Eames, Partner, Hunton Andrews Kurth
Julio Friedmann, Chief Scientist, Carbon Direct
Andy Huggins, SVP, Southwestern Energy
Basak Kurtoglu, Managing Director, Quantum Energy Partners
Jordan Marye, Managing Partner, Trace Capital Mgmt
Arjun Murti, Partner, Veriten
Megan Oberly, Vice President, Marketing & Product Management, H&P
Tim Perry, Managing Director, Investment Bank Capital Markets, Credit Suisse
Billy Quinn, Founder, Pearl
Ash Shepherd, Director, Business Development CCUS, Talos Energy
Scott Tinker, Chairman, Switch Alliance
Chris Wright, CEO, Liberty Energy

Members of the media with questions or needing help to register for Enverus EVOLVE should contact Jon Haubert.

Media Contact: Jon Haubert | 303.396.5996

Upstream M&A slides to $9B in 1Q23

CALGARY, Alberta (May 2, 2023) — Enverus Intelligence Research (EIR), a subsidiary of Enverus, the most trusted energy-dedicated SaaS platform, is releasing its summary of 1Q23 upstream merger and acquisition (M&A) activity. In Q1, U.S. upstream M&A saw $8.6 billion transacted in 16 deals, with more than $5 billion in the Eagle Ford for a surprising resurgence in that mature play. While deal value is down about 20% versus the first quarter average since 2016, deal volume also continued its multi-year collapse with a disclosed volume of 80% less than the Q1 average. That resulted in an average deal size of more than $500 million.

“Last quarter was an outlier in terms of the deal targets and types for upstream transactions,” said Andrew Dittmar, director at Enverus. “Rather than public E&Ps focusing on buying undeveloped inventory in the Permian Basin from private companies, most of the deals targeted mature assets in the Eagle Ford and included more public-to-private transactions plus a corporate merger.”

Leading off for deal size was the acquisition of Houston-headquartered Eagle Ford pure-play Ranger Oil by Calgary-based Baytex Energy. This deal, the first merger involving a U.S. operator E&P since Oasis Petroleum and Whiting Petroleum combined one year ago, brought Baytex into the Eagle Ford. Baytex was the second new entrant to buy its way into the Eagle Ford (and the second from outside the U.S.), as U.K.-based INEOS also made its debut as a North America shale operator with its purchase of Chesapeake’s South Texas assets for $1.4 billion.

“The Eagle Ford has a lack of home-grown consolidators and has remained fragmented,” added Dittmar. “Over the years, it has also been a reliable target for buyers from outside the U.S. drawn by its established production and ease of access to Gulf Coast markets. That is continuing with a modest gas acquisition by Mitsui already in April. We view the Eagle Ford as an optimal place to buy production-heavy assets, and some inventory, but it is generally not the ideal play for companies needing a big chunk of undeveloped acreage to be looking.”

For undeveloped land, companies will need to turn to the Permian Basin. Matador Resources was among the E&Ps looking to expand in the Permian and paid $1.6 billion for EnCap’s Advance Energy Partners with holdings in the Delaware Basin. The deal is part of a rush of private equity (PE) exits, with EnCap among the most active sellers. That also includes the early April divestment of three EnCap portfolio companies in the Midland Basin to Ovintiv for more than $4 billion.

“Most public companies are in need of inventory, and the land held by private E&Ps is where they can find it,” said Dittmar. “However, adding these locations comes at an increasing cost. Top-tier locations in the Permian nearly always garner more than $2 million each now, and some deals have approached the $3 million per location mark. We anticipate core locations will break the $3 million mark this year as the inventory situation for operators isn’t getting any better.”

The recent major Permian deals have gone to large operators with Matador, a sizable company with a market cap of nearly $6 billion, among the smaller buyers. These companies have the cash and favorable stock valuations to afford higher priced acreage. However, many smaller companies are in even more need of extending drilling inventory to satisfy investors. “It’s a catch-22,” Dittmar said. “Small operators need inventory to improve investor sentiment and get a higher multiple on their stock, but without the higher multiple they really can’t afford these deals and keep them accretive to cash flow. The solution lies in targeting tier 2 and tier 3 M&A opportunities, plus smaller bolt-on transactions that tend to be cheaper.”

Another potential, though not widely used, option is mergers of equals among SMID-caps. Corporate M&A, outside of the Baytex and Ranger deal mentioned above, has been a relatively minor part of the market since the end of 2020. While two SMID-cap E&Ps merging may not solve inventory issues, it would increase scale in a market where investors view bigger as better and potentially produce operational and administrative synergies that could help their stock price.

While public companies shop for private E&Ps to acquire, the remaining PE teams are also looking for non-core assets shed by public operators. WildFire Energy, backed by Warburg Pincus and Kayne Anderson, was among those PE buyers in Q1 when the team purchased Chesapeake’s Eastern Eagle Ford or Brazos Valley assets for $1.425 billion. More PE teams have been doing their buying outside the crowded Permian where rising prices for undeveloped land has made it hard to compete. By contrast, assets in plays like the Eagle Ford and Bakken can often be purchased for the value of existing production alone without having to pay anything for acreage. That was the case in the WildFire deal, and in a purchase of Ovintiv’s Bakken assets by EnCap-sponsored Grayson Mill that coincided with EnCap’s Midland sale in early April.

“M&A may have slowed, and shale may be in its later innings, but there are still opportunities to be had,” concluded Dittmar. “The scramble for dwindling inventory is on, and oil prices are in a good place for M&A where both buyers and sellers feel comfortable transacting. Gas deals are likely to remain challenged as pricing is low and volatile, a murderous combination. However, gas may be poised to pick up the slack in the future when buyers start eying recovering prices driven by increasing U.S. LNG exports and offer buyouts that are acceptable to sellers.”

Members of the media can contact Jon Haubert to request a copy of the full report or to schedule an interview with one of Enverus’ expert analysts.

Additional resources

Media Contact: Jon Haubert | 303.396.5996

What you should know about the future of mineral acquisitions

In the fast-paced world of minerals, timing is everything. With mature basins becoming the norm and no new shale plays on the horizon, mineral companies must embrace a forward-thinking mindset to stay ahead of the competition. In this blog post, Enverus will explore how an analytics-intensive approach can help mineral companies identify and seize M&A opportunities, build a strong portfolio and extract maximum value from their investments.

The state of the mineral market: Forecasting and investing into the future

Mineral and royalty assets attracted about $6 billion in deals last year. The Enverus Intelligence Publications team recently shared their thoughts on the first publicly disclosed mineral deal of 2023, Kimbell’s Midland Basin buy. Enverus expects to see a continued uptick in deal activity for this sector. However, finding transactions that are accretive to both yield and activity well levels will be challenging according to the Mineral Review report, “Mineral Review | Competitive M&A Market Set to Get Hotter,” (available to Enverus Intelligence® | Research (EIR) subscribers) published by EIR in December 2022.

mineral-royalty-deals-and-m-and-a-value-chart

Anticipating opportunities in a competitive minerals market

Minerals companies often find it challenging to keep a pulse on operator activity to anticipate opportunities. Traditional methods of monitoring permits and rig activity may not suffice in this hyper competitive environment. The winners will be buying ahead of the drill bit, using leading indicators of an operator’s development activity. In addition, to understand minerals upsides requires understanding proved developed producing (PDP) reserves and proved undeveloped (PUD) reserves or upside value.

These three focus areas are what will reveal leads early in the development cycle and help mineral companies effectively screen opportunities — making it more likely they make accretive investments.

Stay ahead of the drill bit with insights for minerals

Enverus offers mineral investors access to the most timely, accurate activity, production and revenue insights to find new opportunities before the competition even knows they are there. Tracking oilfield activity, such as pad detection and frac crew movements, is the key to knowing what will happen before others that use more traditional line of sight tracking methods.

Plus, with pre-built production forecasts, geologic zone and ESG insights, you get reliable estimates from new wells to generate competitive offers, stay informed about drilling and completion activity, and gain knowledge in areas with potential for development and which operators you want to work with.

Real-world application: The benefits of using Enverus insights for mineral investment

To understand how mineral companies can use Enverus insights to influence investment decisions for non-operating assets, Enverus spoke with Scott Rice, COO at Riverbend Energy Group, a multi-faceted investment firm focused on the energy sector.

Rice said, “We’ve used Enverus analytics and intelligence for 15 years. Without Enverus, we couldn’t get the information we need fast enough to stay on top of the market. We also couldn’t value deals as accurately or as quickly. The research and development Enverus does — where your researchers are constantly creating and updating new data feeds — allows firms like ours to scale.

“We are very process oriented to ensure we are really maximizing how efficiently we operate. If we tried to build an in-house solution that provided the same level of data accuracy, it wouldn’t be as robust. With Enverus, our team out in the field can bring opportunities to our engineers. Our engineers pull in Enverus analytics to our solution to do the technical evaluation of the asset so we can assign a proper value to it. This also helps us when we need to sell an asset.”

You can download the full Riverbend Energy case study here.

To understand the step-by-step analysis using these insights, take a look at the Enverus article, “Workflows to Forecast Higher Mineral Profits.”

Looking ahead: An analytics-intensive approach to mineral acquisitions

The future of mineral acquisitions will depend on mineral companies’ ability to stay ahead of the competition. With scarcer, undeveloped inventory and more mature basins, finding the right opportunities will require an analytics-intensive approach that leverages leading indicators of operator activity and an understanding of PDP acreage and PUD reserves. With timely and accurate insights from Enverus, mineral investors can gain a competitive edge and make informed investment decisions to extract the most value from these opportunities.

Want to learn more about Enverus Minerals Solutions? Contact us by filling out the form below.

About Enverus Intelligence®| Research
Enverus Intelligence Research, Inc. (EIR) is a subsidiary of Enverus and publishes energy-sector research that focuses on the oil and natural gas industries and broader energy topics including publicly traded and privately held oil, gas, midstream and other energy industry companies, basin studies (including characteristics, activity, infrastructure, etc.), commodity pricing forecasts, global macroeconomics and geopolitical matters. Energy Transition Research is a research division of EIR focused on topics including Power & Renewables, CCUS, Low-Carbon fuels and Emissions. Enverus Intelligence Research, Inc. is registered with the U.S. Securities and Exchange Commission as a foreign investment adviser. See www.enverus.com/disclosures for additional information.

Enverus Blog - A tale of 2 Canadian basins: Untapped value still remains

A tale of 2 Canadian plays: Untapped value still remains

The Wild West: Reporting Canadian liquids

The Wild West spirit lives on in Western Canada, at least when it comes to reporting condensate volumes in gas wells. Operators in the Western Canadian Sedimentary Basin (WCSB) do not consistently report these volumes due to the existing measurement and reporting guidelines for Alberta and British Columbia. This results in public disclosures that can be misleading and hinder a proper understanding of wellhead liquids production in some of the most important Canadian plays. Operators can interpret the guidelines as reporting “gas equivalent volume” in certain operating conditions, creating the appearance of a dry gas production stream.

For investors who rely on public production data for analysis, such reporting inconsistencies can lead to an underestimation of wellhead liquids, negatively affecting net present value calculations. This renders the data useless for meaningful analysis. Currently, there are limited solutions available at scale in the market, leaving customers with no way to perform meaningful well analytics unless they use production data from their own wells. These flawed systems and processes can impede progress and success, leading to frustration, cynicism and a lack of trust in the effectiveness of institutions. It highlights the need for transparency and accountability in both government and industry.

As a result, some prominent Canadian plays are receiving less attention and investment, which leads to reduced exploration, delayed technological development and fewer optimization opportunities. In this blog, we will focus on two Canadian plays that Enverus Intelligence® | Research (EIR) considers highly competitive and among the most profitable plays in North America: the Montney and the Duvernay.

The two plays: Montney and Duvernay

The Western Canadian sedimentary basin is renowned for its diverse endowment of unconventional oil and gas resources. The Montney play is found in Northeast British Columbia and Northwestern Alberta, while the Duvernay is situated in Central Alberta. Both plays are highly sought after by the Canadian unconventional oil and gas industry, with Montney being rich in natural gas, oil and natural gas liquids from the Early Triassic period, and Duvernay boasting high-quality light oil and liquids-rich natural gas from the Devonian age. Their abundant resources and potential for growth have made Montney and Duvernay the primary drivers of unconventional oil and gas production in Canada, making them the industry’s focal points.

Want to learn more about how to optimize and monetize your Canadian portfolio?
Click here to watch a free webinar from Enverus.

The misunderstood play: The Montney

EIR reported at the beginning of 2023 that despite its high profile, the Montney play, a significant unconventional play, remains the least delineated across North America. Despite being well-known and highly regarded in the oil and gas industry, its potential reserves and economic extents are not well understood or well defined. This lack of knowledge contrasts with other similar plays in North America. Over time, EIR has developed its own liquid correction models to provide a more precise estimation of the actual liquid composition and estimates that around 40% of Montney wellhead liquids production has been underreported in raw data since horizontal well development began almost two decades ago. This underreporting has led to an overestimation of the breakeven price in some areas of the play, potentially by up to 50%. However, if this issue is resolved, the entire Montney fairway is considered highly competitive and among the most profitable plays in North America.

“We estimate that approximately 40% of cumulative Montney wellhead liquids production, equivalent to approximately 302 MMbbl, has been underreported in raw public production data since the start of horizontal well development. After correcting for the underreporting, the entire Montney fairway emerges as an extremely competitive and profitable player among North America’s top plays,” said Trevor Rix, senior vice president at EIR.

Enverus can improve your well analytics and reporting in Canada by providing accurate condensate allocation to wellbores. This precise allocation allows for a comprehensive analysis of all available analytics in Enverus PRISM®, making the data more meaningful. Enverus uses proprietary variables derived from in-depth analysis to fuel its model-based allocation process. This process is calibrated to real-world data from clients, ensuring greater consistency and accuracy in reporting.

Want to learn more about how to optimize activity in the Montney Basin?
Click here to watch a free webinar from Enverus.

The smaller, but still strong, Duvernay play

On April 17, the EIR team released a report titled “Duvernay economics | Better, not the best,” which acknowledges the challenges of extracting oil from the Duvernay Shale in central Alberta but highlights its significant value. Unlike the Montney Formation, the Duvernay is composed of deeper, less-porous rock, making oil extraction more capital intensive. However, the belief that these challenges are insurmountable can hinder innovation and risk taking, limiting the potential of the industry and the Duvernay play to achieve its goals.

“Duvernay economics have been quietly improving throughout the last few years, but they still lag behind that of the Montney because of the greater depth of the formation and the proppant required for hydraulic fracturing,” said Rix.

In the last eight years, the Duvernay Shale has seen a reduction of around one-third in its median half-cycle breakeven, making it more competitive against other plays. Additionally, recent mergers and acquisitions involving major operators in the play suggest that the Duvernay will likely experience more substantial growth in the medium term.

Canadian basins still have a lot to offer

Unfortunately, due to the higher costs, the Duvernay has some ground to make up if it is going to catch up to the Montney. However, with investors seeking long-term exposure to deep natural gas inventory and the increasing accessibility of North American LNG egress, the basin’s growth will be profitable. Despite advancements in play understanding, drilling and completion technologies, and cost efficiencies, the Duvernay still falls behind the Montney in terms of half-cycle discounted well economics. Additionally, based on analog well cost data from U.S. plays, it seems unlikely that the length-normalized capital costs will decrease any further in the Canadian play.

In conclusion, the inconsistent reporting of condensate volumes in gas wells in the WCSB has a significant impact on the analysis and evaluation of wellhead liquids production. This problem is compounded by the lack of meaningful solutions available in the market, leaving investors with limited options for reliable data analysis. The implications of this flawed reporting system can have a significant impact on the success and progress of plays in the region, leading to less investment in exploration, technological development and optimization. While the Montney and Duvernay plays are highly competitive and profitable plays in North America, the current reporting guidelines and measurement systems must be improved to promote further investment in these two areas.

Appalachian E&Ps see opportunities for savings later this year

Natural gas prices have been trending downward since August, with Henry Hub spot dropping from more than $9/MMbtu to around $2/Mmbtu. Enverus Intelligence® | Research’s most recent monthly Macro Forecaster report, available to EIR subscribers, predicts continued weakness, with Nymex gas averaging around $2.50 this summer and remaining in the $2.50-$3.00 range until winter 2024-2025. These price levels will inevitably drive a reduction of activity in gas-focused plays. However, some public companies operating in the Appalachian Basin see a silver lining, predicting that softening demand for oilfield services and materials will drive cost reductions in the back half of this year.

Range Resources COO Dennis Degner said on a Feb. 28 earnings call that he was already seeing service costs stabilize and anticipates opportunities for savings this year, following announcements from U.S. operators that they were slowing their drilling programs to maintenance level. “If you look at an example, where fuel prices are today versus maybe where they were in the back half of 2022, that could present an opportunity to shore up, let’s just say, some savings for the balance of the year, along with tubular goods starting to see some relief,” Degner said. “So, we would expect the deeper you get into the year, there would be some opportunities that would further present themselves for service cost reductions.”

EQT CFO David Khani said Feb. 16 that he, too, anticipates a decline in gas-directed drilling this year to drive opportunities for price relief in H2. CEO Toby Rice noted that EQT had locked in its rig and frac crews for most of the year, a move several larger Appalachian operators have made to mitigate service cost inflation. He said he’d seen some “signs of loosening there on price” for steel, which the company has procured through the end of H1, which could result in savings in H2.

Chesapeake Energy is already reducing activity levels, with one Haynesville rig dropped in Q1 and one each being taken out of the Haynesville and the Marcellus in Q3. It is also seeing a pullback by other Haynesville operators, especially private companies, Chesapeake COO Josh Viets said on a Feb. 22 earnings call. He expects operators to “start pulling back with the weakness in the gas pricing we see today.”

However, Viets noted that he’d not seen “much softening in service cost to date” because of the continued strength of the oil market. Without a softening in oil prices, he said, “We’re not baking any material cost inflation as we work into the back half of this year.” Even with lower activity, Chesapeake expects well costs per foot to rise 10% YOY in the Haynesville this year, but less than 5% in the Marcellus.

Coterra Energy operations SVP Blake Sirgo echoed Viets’ sentiments on a Feb. 23 earnings call, saying, “It’s hard to pin a service cost to a commodity price. I mean it’s really ultimately a function of activity and how much services are available on the market.” However, he noted that the company is seeing some price softening.

“I’m happy to say we’ve seen a little bit in rig rates here recently, and that’s a good sign,” Sirgo said. “We’ve seen a softening in casing — our OCTG going out three to six months — we’re starting to see some price coming down and that’s a good sign. But ultimately, it’s going to be a function of activity across the Lower 48. All rigs and crews have wheels, and they will travel, so we’ll see where activity goes.”

Strong oil prices could limit service cost savings for operators in gas plays. Click for more (available to Enverus Intelligence Publications subscribers)!

Introduction to power purchase agreements for renewable energy

Power purchase agreements (PPAs) are an essential tool for traditional and renewable developers and buyers. A PPA is a contractual agreement between a generator and a buyer that outlines the purchase of electricity or ancillary services for a set time period. Developers can benefit from PPAs by securing a long-term revenue stream for their projects, while buyers can achieve reliable supply and sustainability goals by purchasing renewable energy.

What are PPAs used for?

PPAs can be used for any type of energy source, including traditional, solar, wind and energy storage. In PPA agreements the buyer is the direct user of energy generated. However, virtual power purchase agreements (VPPAs) are specific to renewable energy sources. VPPAs allow buyers to purchase renewable energy credits (RECs) from renewable projects to offset their carbon emissions. In this case, the power generated by the developer is not directly used by the buyer. This can help buyers achieve their sustainability goals and support the growth of renewable energy projects.

Sellers and buyers of electricity in PPAs

In most cases, a renewable energy developer would sell the electricity generated from their project to a utility or large industrial buyer for a long-term period. The utility or buyer would then distribute the electricity to end-users. PPAs can also involve independent power producers (IPPs) generating and selling directly to a user, which in most cases is for industrial use.

Elements of a PPA

PPAs for purchasing renewable energy typically include the following elements:

Location of power assets

Developers must identify suitable land locations for their renewable energy projects based on capacity factors, land topology characteristics, policy and land ownership.

find-suitable-land-for-renewable-projects-with-prism — Source: Enverus PRISM®, parcels and suitable land analytics.

Electricity price and project

Developers and utilities negotiate the price of electricity generated by the renewable energy project for the duration of the project lifecycle based on locational marginal pricing, years the asset is in service and other factors.

Design and construction

Developers are responsible for designing and building the renewable energy project. They must contract with engineering, construction and procurement parties and obtain necessary permits, leases and tax credits.

rated-power-pvdesign-shows-renewable-project-site — Source: RatedPower pvDesign.

Point of interconnection

Developers must design and construct infrastructure, including transmission lines, to connect the renewable energy project to the power grid. They must also adhere to ISO standards during the interconnection queue phase.

Mitigating risk

Both buyers and sellers use various methods to reduce risk, including contractually and through due diligence in each phase of the PPA agreement. This may include analyzing past agreements, successful completion of the project and reasons for the failure of other projects.

mitigate-risk-of-renewable-power-projects-with-prism — Source: Enverus PRISM®, project tracking analytics.

Terms and conditions

PPAs typically include terms and conditions in the event of project delay or abandonment, including the consequences for the developer’s inability to design, construct and deliver power to the utility or direct user.

Meet your sustainability goals

PPAs are an essential tool for renewable energy generators and buyers, enabling them to secure a long-term revenue stream and achieve sustainability goals. Renewable energy buyers should consider VPPAs to offset their carbon emissions, and both buyers and sellers must understand the elements of a PPA to negotiate a successful agreement.
Enverus Power & Renewables solutions can help you at each step of the power and renewables asset lifecycle. We can help you:

Understand where you fit in the energy transition to help you invest intelligently.
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Plan and optimize the design and engineering of your photovoltaic project.
Maximize the value of your asset with real-time analytics to optimize your power trading strategy.

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The Texas power market evolution

Performance credit mechanism

In a decision that could reshape Texas’ power market, The Public Utilities Commission of Texas (PUCT) voted Jan. 17 to adopt the performance credit mechanism (PCM) market design, a strategy developed by consultant E3 in partnership with the commission. The PCM mechanism aims to provide payments to power units that are available during peak conditions, incentivizing reliable capacity and retaining generator assets at risk of retirement. Although resembling capacity mechanisms in deregulated markets such as California’s CAISO, the PUCT emphasized that PCM is not a capacity market feature.

Bridging solutions

As the PCM market design takes shape, discussions have focused on bridge solutions for the transition given that the redesign will take several years to implement. With the long timeline, the Electric Reliability Council of Texas (ERCOT) board recently voted in conjunction with the PUCT to enact a bridging mechanism. The bridging solutions involves changing of the operating reserve demand curve (ORDC). In lieu of a capacity market like most other deregulated independent system operators (ISO), the ORDC mechanism adds money to ERCOT’s real-time prices when the buffer of capacity available to react to large system disturbances fall below a certain reliability limit. This buffer of online idle generating capacity is often called operating reserves, or online reserves.

Historically, these adders were a function of an exponential curve and at higher levels of reserves are mere pennies; however, as the reliability limit ERCOT establishes nears, these prices skyrocket to the price cap. The changes reflect two new characteristics to the curve. At an operating reserves level (PRC) at or below 7,000 megawatts a price floor to the curve of $10/MWh, at or below 6,500 megawatts, a price floor is increased to $20/MWh.

graph-showing-current-and-future-reserve-price-curves

To understand why this level is important, one can look back to historical operating conditions. This newly adjusted range is where operating reserves spend a significant amount of time exhibited in the yellow bars in the histogram below.

ERCOT expects the adjustment will add $500 million annually to the cost of power. This change has an asymmetric benefit to thermal units over renewable units which are known to push operating reserves well above the 7,000-megawatt floor. The original ORDC curve still allows prices to exceed these price floors as PRC decreases, which eventually reaches the $5,000/MWh price cap as reserves fall enough. This bridging solution is expected to take four months or longer to develop, so not a risk for this summer’s trading but will potentially impact fall/winter 2023 as maintenance outage season begins again.

graph-showing-ercot-average-hourly-operating-reserve-levels

More on PCM

The Texas House State Affairs Committee convened March 1 to discuss grid reliability and the proposed PCM design. The Committee heard testimonies from ERCOT CEO Pablo Vegas, Zach Ming of E3, PUCT Chairman Peter Lake and other industry representatives. As the 88th Texas Legislature Session approaches its conclusion May 29, PCM appears poised to pass with minimal additional legislative scrutiny.

Senate Bill 6

In parallel, Senate Bill 6 (SB 6), introduced Jan. 19, 2023, proposes the Texas Energy Insurance Program and the Texas Energy Infrastructure Fund, providing financial assistance for new thermal generation and infrastructure improvements. A revamped version of the “Berkshire Hathaway bill,” SB 6 aims to address reliability concerns following Winter Storm Uri by establishing 10,000 megawatts of “reliability assets” outside the ERCOT market structure. The estimated cost of $8-16 billion will be passed directly through to consumers. Eyebrows were raised as the Lower Colorado River Valley Authority (LCRA) appeared to be throwing their hat in the ring to build these units, which would likely require it to change its status from a public non-profit in charge of waterways to some unknown new business entity.

While ERCOT supports the bill for grid reliability, critics argue it may increase costs, impact the ERCOT wholesale market and limit future investment. SB 6 also restricts eligible participants for new plant construction, potentially benefiting only the largest power generators and river authorities like LCRA.

After passing the Senate Feb. 15, 2023, SB 6 is under consideration by the House Energy Resources Committee. The committee is currently considering it on agenda items and should soon begin discussions on items from the Senate given the close of the legislative session. If passed, it will proceed to the full House, Senate conference committee and, potentially, the governor’s desk.

The proposals signal a potential shift in legislators’ thinking on the Texas power markets. Historically, free and open markets have driven renewable and technology expansion. Stakeholders, including market participants, private equity firms and market analysts, are raising important questions about the bill’s implications. A key concern is the uncertainty about who would be responsible for building the next power generation plant if the bill is enacted. The outcome of these legislative efforts will shape the future of Texas power markets.

Keep your eye on the House committees and the Texas State Legislature over the coming weeks!

We discuss many important topics for power traders and developers in our Flash Publication 90-Day Reports which come out every two weeks for CAISO, ERCOT, PJM, MISO, Mid-C, NYISO, ISONE and SPP.

Learn more about how Enverus’ Power Market Publications can help you navigate the Texas power market evolution.

Life at Enverus

Refinancing in the dark

Transparent capital sourcing solution

Credit facility A redetermination example

Conclusion

Highlights from Energy Transition Research

Highlights from Energy Transition Research

Reaching the Right Mineral Sellers With the Right Revenue

Verifying Mineral Ownership and Interest Type

Shrinking Your Acquisition Costs

Key Takeaways

Oil equities reign supreme: However, long-term opportunities in gas or hybrid equities (April 20, 2023)

Big players, big opportunities: Large-caps win out on core Permian inventory deals (April 20, 2023)

From Golden State to duck curve: The changing landscape of solar power in California (April 18, 2023)

First oil achieved: A look at Mad Dog Phase 2’s journey (April 14, 2023)

Dairy RNG facility delayed after devastating explosion at Texas farm (April 14, 2023)

Uncovering the hidden treasure trove: Montney’s underreported liquids production (April 12, 2023)

OVV’s bold move: Tripling its inventory and doubling its life with EnCap’s portfolio (April 04, 2023)

Powering the future: Why lithium, copper and nickel demand will skyrocket with EV adoption (April 3, 2023)

OPEC’s surprise cut: Shockwaves through oil markets (April 3, 2023)

Green, but not green enough? Canada’s clean tech plan compared to the U.S. (April 1, 2023)

Keeping up with an evolving industry

Three main factors that cause errors in acreage math calculations are:

Pitfall 1: Not Accounting for Offset Wells

The Solution: Consider existing wells

Pitfall 2: Overestimating in Complex Geology

The Solution: Consider well-level geo properties, spacing, infrastructure and economics together

Pitfall 3: Not Accounting for Acreage Orientation

The Solution: Plan based on future development

Conclusion

Highlights from Energy Transition Research

A Simple Guide to Energy Transition Metals

A Simple Guide to Synthetic Fuels

The Inflation Reduction Act – Impact on CCUS

Notable speakers

Additional resources

The state of the mineral market: Forecasting and investing into the future

Anticipating opportunities in a competitive minerals market

Stay ahead of the drill bit with insights for minerals

Real-world application: The benefits of using Enverus insights for mineral investment

Looking ahead: An analytics-intensive approach to mineral acquisitions

The Wild West: Reporting Canadian liquids

The two plays: Montney and Duvernay

The misunderstood play: The Montney

The smaller, but still strong, Duvernay play

Canadian basins still have a lot to offer

What are PPAs used for?

Sellers and buyers of electricity in PPAs

Elements of a PPA

Location of power assets

Electricity price and project

Design and construction

Point of interconnection

Mitigating risk

Terms and conditions

Meet your sustainability goals

Performance credit mechanism

Bridging solutions

More on PCM

Senate Bill 6

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