For years, oil and gas investors have relied on antiquated means of obtaining the capital they need to fund their operations. Reserve-based lending for years now has been one of the only options for getting the funding you need quickly, but it often leaves little to be desired. That’s why at Advance Royalty Company, we came up with a better solution we call the Advanced Royalty Program. In today’s blog, we take a closer look at what sets the Advanced Royalty Program apart from other methods like reserve-based lending. Keep reading to learn more. And, if you are interested in obtaining smarter funding using your mineral rights royalties, contact us at Advance Royalty Company today to learn more.


Let’s start off by comparing the mean of qualification between reserve-based lending and Advanced Royalty Program with Advance Royalty Company (ARC). With traditional reserve-based lending, the only way you will receive funding is if you already have an existing operation that produces $20 million...


The turmoil in the energy space has been fast and unprecedented. Historically, as oil and gas investors, we have always experienced periods of price shock. This has primarily occurred during uncertainty on the supply side — fundamentally or politically. However, in the past four weeks, we have had extreme variables in both supply and demand. We will discuss these variables and how they have impacted oil and gas as an industry, oil and gas investors, and oil and gas royalties.

Five weeks ago the oil market had fallen below yearly low by dipping into the mid $40 range. This represented roughly a 10 percent decline from this previous range of $50 to $65. This was due, in part, to the growth on the supply side, but also the early Coronavirus fears played a part. Then over a weekend, we learned of the price war between Saudi Arabia and Russia. With Saudi Arabia pushing more oil into an already saturated market, that Monday we experienced an extreme price collapse. With uncertainty on the supply side weighing heavily on the oil market, the inverse began to build concern on the...


WTI (West Texas Intermediate) has fallen to a near 20-year low. On March 18th, just a few days ago, the price of WTI crude went down to $20/bbl. The last time prices were in this range was back in 2002.

Since the Corona Virus has sent nearly all global travel to a screeching halt. This virus has dealt a significant blow to many industries, but perhaps more so for oil and gas. As government officials world-wide continue to encourage people to restrict gathering and travel, global oil demand will likely continue to plummet.

It is predicted that the global demand for oil in March and April will be down around 10 million barrels per day. This leads to a predicted oil surplus of up to 1 billion barrels for the first six months of this year. The largest, six-month surplus over the last 100 years was around 350 million barrels. Oil prices are expected to drop to as little as $10/bbl.

The impact that the Corona Virus is having on the oil and gas industry will soon ripple out and affect millions of people worldwide. Many producers will default on their loans and many...


We have spoken at length on the fundamental balancing act that drives commodity prices – supply and demand. Earlier this month the industry experienced 2 simultaneous black swan events that hit both sides of this equation. First, COVID19 knocked off a major amount of demand for oil (5-6mm bbl/d) and then ROPEC announced that they cannot get along and that they are all going to produce at full bore to protect market share (5-6mm bbl/day). So supply went up and demand went down, leaving a roughly 10-12mm bbl/day surplus overhang of oil on the market, storage is quickly filling up. Prices have collapsed by 60%, with the balance of 2020 pricing in the mid $20 range.

There are very few projects in North America that can economically operate at these levels. This means that for every unhedged barrel of oil operators are losing money. Many of the operators have a break-even in the mid $40s. Here is their major risk, debt burden, their revenue has fallen by 60% but their debt and interest payments have remained the same. So they are now stuck, they cannot increase revenue because...


The oil-to-gas price ratio has hit its highest point in six years. There’s no doubt about it, the market is certainly going through a change. Recently, the level of oil-to-gas ratio reached 30-to-1 and is expected to increase further. With this ratio, analysts are expecting the average price of gas to drop for the second consecutive year. This would lead to gas prices being the lowest that they’ve been in over 20 years.

Why is this the case? Well, the reality is that most U.S. drillers are not searching for gas. Now, drillers are seeking out more valuable oils and natural gas liquids. When drillers seek out these types of liquids and oils, they wind up finding gas inherently. Because of that, major oil corporations aren’t hurt by the dip in gas prices.

These oil-to-gas ratios are at the highest that we’ve seen since 2013. Since then, the average ratio that we’ve seen for oil-to-gas is 19-to-1. This ratio has changed drastically because of the rise in oil prices and the drop in gas prices. Ultimately, this is what has held the gas industry back.

Analysts have...


It is no secret that the energy industry has gone through massive fundamental changes over the past decade. Some of the consequences of these changes are yet to be realized. With the advent and rapid adoption of shale drilling, massive amounts of debt were raised to put the technology to work in plays across North America. In addition, millions of acres of land that had marginal oil and gas activity came to the forefront as hotspots for drilling. These two factors have created new opportunities for innovative financial products to be developed. Companies that have high amounts of debt, and are being pressured to improve their free cash flow, are using royalty interests as an asset to help remove some of that burden.


This summer, a popular theme in the industry, when speaking about macroeconomic trends, is the question of well productivity declining. The basic theory is in two parts. The first comes from the last commodity price collapse of 2014, when producers decided to drill only their most productive acreage, increasing their capital efficiency (fewer dollars spent per mcf or bbl of production), but also setting the bar very high for productivity. Productivity gains in 2015-2016 were very large, in part due to the high grading of acreage development. The second part, that our friends at NGI call “the bigger hammer,” was the development of longer laterals and increased proppant per lateral foot. This both created capital efficiencies as well as increased production in wells due to increased fracturing of the reservoir rock. In virgin rock, this strategy works quite well (no pun intended). However, producers are finding when going back to drill second and third wells (known as child wells), their productivity is not as great as the first well (known as a parent well), and even sometimes,...


We have spoken before about institutional money (Wall Street) pulling back from investing and making loans in the oil and gas space. This is due to a need for producers and ancillary companies to operate with positive profit margins. Before the finance pullback, you did not necessarily need to be profitable to survive, just issue more debt or equity to fund growth. This principle has changed, and the industry is now expected to start creating excess profits. This paradigm shift has manifested itself in some interesting ways. The takeover of EQT by Toby Rice, the Carrizo acquisition by Callon, and the Anadarko-Occidental merger have all been motivated by increasing free cash flow (distributable earnings to shareholders) through one strategy or another. In addition, in Appalachia, we have seen private operators stop drilling due to low commodity prices, Montage resources and JKLM have both announced the shuttering of rigs. We have touched on how the Appalachian capacity build-out was likely to improve regional price differentials, but depress Henry hub pricing, this has occurred....


Independent producers and mineral aggregators have always been in the market for unique finance solutions. Recently, however, traditional banking alternatives have become less attractive.

In March, law firm Haynes and Boone LLC released their Spring 2019 Energy Roundup. In it, they discuss the shifting dynamics that have led to banks taking a more conservative approach to energy lending.


U.S. producers are likely to face a “conservative but not knee-jerk response” by banks as they begin spring borrowing base redeterminations, according to a survey by Haynes and Boone LLC.

The law firm’s Spring 2019 Energy Roundup issued this week compiled responses to its borrowing base redeterminations survey, which exploration and production (E&P) companies face twice a year as banks review their debt levels.

Redeterminations for the spring are following somewhat mediocre earnings results for the fourth quarter of 2018 following the drop in oil prices late last year. The survey, the ninth by Haynes and Boone since April 2015, polled...


United States oil prices are rallying thanks to an unexpectedly large draw (12mm barrel draw versus a 2mm barrel forecast) in oil inventories this week. Not to be forgotten, Iran and the Middle East weigh heavily on the mind of global crude traders as well. Touching $59.93 today, the U.S. benchmark oil index, West Texas Intermediate Crude OIl settled at $59.38/BBL.


I am writing this from the Florida Keys right now waiting for the wind to die down so I can go fishing offshore. Generally, when that happens, the only thing that brings solace is a cold bottleneck. Unfortunately, the bottlenecks that we will be focusing on today can bring a lot of pain to oil and gas prices. We will be continuing the trend of talking about the two biggest production basins for their respective commodities: the Permian and Appalachia.

RBN just made a writeup regarding the Appalachian buildout of transport capacity and the difference between nameplate and effective capacity. While the nameplate capacity is the number that everyone focuses on and models, the effective capacity is the stronger driver for market fundamentals and thus basis differentials on nat. gas pricing. Effective capacity focuses not on the amount of gas that can flow on a pipe, but how much gas can be used at the delivery point of the pipe. If a pipeline can deliver 4 bcf/day to another pipe, but that pipe only has room to take 1 bcf/day on average, then it is very likely that the 4 bcf...


I am not an optimist, but hopefully one day I will be.

With West Texas gas prices still under pressure, the timing of new natural gas pipelines from the Permian remains critical. This increased take away gives the optimist hope. However, questions remain if this will be enough to offset the increase in production. In response to the low prices, several producers have shut-in or deferred production until new infrastructure comes online. Additionally, Permian flaring continues to hit new peaks. However, if producers continue to grow unmarketed production, will Gulf Coast Express provide the needed relief to gas prices orts or just unleash a wave of new supply?


Advance Royalty Payment and Volumetric Production Payment (VPP)

These products give a royalty owner Advanced Royalty Program or a working interest owner (VPP) a payment upfront for a specific amount of production that will be produced in the future. These products have been designed for those who need a large amount of capital in the short term while continuing to retain their asset in the long term. This only other current option for this product is a sale of the asset, which destroys all the long-term value of a producing asset. These products also remove the risk, for a customer, of the price of their future oil and gas production falling, since they are paid upfront. These products can continually be renewed at the conclusion of each transaction, giving customers a great option for more clarity and security on the income of their oil and gas assets.

Gross Royalty Price Hedge

This product allows for a customer to lock in the gross price that they will receive on a royalty check each month. ARC will pay the difference to the...


Jose the Magician was doing his act when he tells the audience, “I will disappear on the count of three!”



…and he disappeared…without a “Tres.”

This reminds us of current spring weather natural gas demands — it has disappeared without a trace.

Energy trading professionals are nearly all amateur meteorologists, spending a significant amount of their workday, even nights and weekends, looking at weather forecasts. In the first half of April, the U.S. has experienced generally mild weather and the 6-10- and 11-15-day forecasts are projecting more mild weather to come. Weather can help – a hot summer creates natural gas demand when power demand increases to meet air conditioning demand (about half our power plants use natural gas as their main fuel).

Sometimes, an April cold snap can occur near the east coast population areas, creating heating demand. Also, it isn’t uncommon for the Southwest, Texas and the deep South to get an early hot spell.

However, in 2019 neither a cold East nor a hot South has materialized. This has...


Q. Why did the man fall into the well?

A. He didn’t see that well.

Makes us laugh every time.

On the theme of wells, as you have read in our recent posts, oil producers continue to drill, baby, drill. That brings online the usually valuable, but sometimes nuisance issue of natural gas and how to get it to market. Again, if there is no pipeline to take away the gas, producers have very few options with what to do with that gas. Oil in the $64 range at WTI inspires a lot of oil drilling, leaving some producers in natural gas pipeline-constrained regions stuck with natural gas and the penalties related to not being able to move it out of the region.

Changing gears before we tie it back together.

A quick primer on LNG and North America import fundamentals

A significantly bullish development in the North American natural gas market is our recent and growing ability to bring natural gas to a shiny new $50 billion facility built on one of our coasts, supercool it until it changes to a liquid state,...


I watched the movie No Country for Old Men last week for the second time. At first, it made me think about gas prices in West Texas, but then I was reminded of an old Texas oilman joke:

Oilman: “Well, I have some good news and bad news.”

Banker: “Well, what is it?”

Oilman: “The bad news is we didn’t strike any oil where we drilled.”

Banker: “Dang, what could be the good news then?”

Oilman: “We didn’t hit any natural gas either.”

Funny how that is playing out again today and is not a new phenomenon. We saw Waha (West Texas) gas trading deeper into negative territory. The cause of this was based on multiple fundamentals we have highlighted in previous Royalty Interest Weekly articles. Weekend gas traded minus $2 with earlier days in the week trading as low as minus $9. More importantly to royalty owners is that the April index set at minus $.06, with May finishing the week at minus $.33 and June barely above zero. Even though operators transport a portion of their gas away from this regional price disaster, the remainder will be subject to...


When trying to understand how a commodity is priced, the best foundation is from a fundamental perspective. Simply stated, when supply is above demand, prices fall and when the inverse occurs, prices rise. However, this equation gets exponentially more complex for natural gas when attempting to parse our and quantify the demand side. Supply is much easier to look at, as we have very solid data on both production and storage figures.

Before LNG, demand was contained to North America, and thus the economic model for natural gas was much more straightforward. A lot of the demand came from heating buildings in the winter and its use as fuel for power plants. With power plants, you must compare the economic efficiency of natural gas with other fuel sources (coal, nuclear, etc.), and their corresponding prices, to accurately determine how high the demand for natural gas will be during any period.

Now that we are in the era of LNG, the demand types have not changed, gas is still being used to heat structures and fuel power plants. However, the locations that the gas can be...


Waha daily cash prices (Permian Nat. Gas Pricing Hub) traded down to $-.75 today. How can prices trade negative? The producer is paying the buyer to take the gas off their hands so that they can continue to produce more valuable production (Oil and NGLs). There may be relief in the near future as GXP (Gulf Express Pipeline), a Kinder Morgan project that is slated to come on this year, may be entering service early. With this, all of the gas in the Permian is going to make its way to the gulf coast. Like we talked about in an earlier post, similar to the Appalachian region, while this will improve the differential between Waha and Henry Hub, it will create downward pressure on the Henry Hub pricing, as more supply enters the region. The main uptake for all of the extra supply should be the LNG export facilities, however, much of that demand will only be there if it is economic to liquefy the gas, transport it to Europe or Asia and sell it in those destination markets. These netbacks between the destination market pricing, the expenses of LNG and the Henry Hub are...


Both Chevron and Exxon announced that they are seeing plus-30% returns at the current strip in the Permian. Exxon announced that they can profitably drill at $15 oil, making their operation cost-competitive with some of the lowest cost supply regions globally. A major driver behind this activity is scale that the majors are applying in the region. While many of the smaller producers are seeing their WTI differential collapse due to transport capacity bottlenecks, the majors are backing their own midstream projects, ensuring that they have the pipeline capacity to get their oil to market. For royalty and mineral rights owners in the Permian, bigger is better.

Similar to our discussion last week regarding the Marcellus, the midstream infrastructure build-out in the Permian will introduce price volatility into the market, as bottlenecks are relieved and new ones are created. As a landowner, these bottlenecks have major impacts on your royalty checks. Many wells have been drilled, but have not been able to produce, due to lack of infrastructure. As a landowner, it may pay...


In the recent history of the shale revolution, the Appalachian basin has been associated with huge amounts of natural gas production, and along with that, the need for interstate pipelines to get the gas to major demand regions (these regions primarily being the Northeast urban corridor, the southeast, and most importantly, the gulf coast). This pipeline buildout is the driver for the price difference between gas in the Appalachian region, and gas priced at the Henry Hub (in the trading world, we call this difference “basis”). Over the past year, this buildout has occurred, creating an excess amount of pipeline capacity between Appalachia and the gulf coast (Henry Hub), therefore the price difference has narrowed. With this, there has been an increased amount of supply reaching the gulf coast, to keep Henry Hub prices at the same historical level, increased demand must also occur. The largest part of this demand increase will be from LNG exports. Currently, and throughout 2019, new LNG facilities are coming on line to export more gas. The big question is, will the export demand...



If you like excitement, the energy markets are not disappointing right now! Next-day gas deliveries that utilities are buying in the Northwest is currently trading for $150/MCF! Yes, you read that right!

There’s been lots of interesting price action as well in the Marcellus and Utica shale plays in Pennsylvania, Ohio, and West Virginia. December royalty values in all basins were considerably stronger year-on-year and January royalty checks will be generally better for most customers compared to January a year ago.

For Eagleford, Permian, Haynesville and Barnett customers, gulf pricing is showing some strength in all commodities. Feel free to call anytime and discuss. We love to talk about our commodity markets.


Advance Royalty Company is looking forward to meeting many of you at several different forums, conventions, and events this spring. We will be active with NARO, TIPRO and IPAA events all spring and summer from the Northeast to the...


It was a good week at NAPE and participation was very strong. Thanks to everyone who came by the booth to hear more about the Advance Royalty Payment!

As winter comes to a close, all eyes again are on the supply-demand dynamics. Many regional variables look to add to the volatility as natural gas demand declines with warmer weather and “summer” storage injections begin.

Concerns of distress in Texas and Southwest is weighing on the market. There is still too much gas in the region and not enough pipeline to move it out.

And, the Waha/Permian basin still has a large inventory of wells shut in, ready to come on line given any improvement in price.

If local oil prices stay strong, producers will likely increase crude production, inadvertently bringing along more gas production as well.

To add further issues, U.S. exports to Mexico are waiting for the Mexico downstream pipeline to get completed, which seems to constantly get pushed back. Prices in this region are low for the summer, but the further weakness is a real possibility in the coming...


The last week has had some very cold temps in the West and Northwest. This caused significant short-term pricing spikes in natural gas in the Rockies and other western hubs — $10 and higher! However, nationally, the futures prices continue to degrade into the mid $2 range for the summer. We still have a chance to see some late-season cold and that should excite the market to bid up to the future pricing. This should present an opportunity for royalty owners to lock in those prices for the remainder of 2019 and beyond. The real concern regarding further downward pressure is the lack of any more weather and the supply glut showing itself as we begin injection season. Crude oil has gently firmed and is migrating back up to the $60 level. Again, this should be a great time for royalty owners to take some price risk of the table. Like natural gas, crude supply in the coming months looks to put pressure on price for the foreseeable future. Taking advantage of an Advanced Royalty Program or other strategies is a great way for royalty owners to mitigate their risk and stabilize their...


We expect royalty owners’ checks this month for November production to be very similar to what they saw in October. But looking forward to the December production month, royalty owners will be very pleased. Due to the cold and significant rally in the natural gas market, natural gas heavy royalty owners should see a 25% to 50% increase in their check value relative to the previous month. Unfortunately, this will be short-lived due to the retreat in natural gas since the beginning of the year. We may see prices move back up for a time before the winter season wraps up. Now the focus will be on the summer fundamentals and weighing the possible weakness in price, especially in specific regions. Either way, the market anticipates continued volatility in price fluctuations. Crude oil has stabilized somewhat in the mid to low $50 range. Location dislocation volatility to WTI pricing looks to continue. With our tools, we have great options for royalty owners to manage and take advantage of this volatile market. See how Advance Royalty Company can help you make sense of your mineral...


Crude oil has taken a major tumble recently from recent highs in the mid $70 range. Oil-rich royalty checks have already been impacted by the discount to WTI in most producing regions. Now with the WTI price decrease, the further value of royalty payments will see a reduction of 30-40 % over the coming months. Fortunately, in natural gas, prices have remained steady late in the injection cycle, across various basins. This translates into stable check values for the balance of the year, as opposed to the previous two years with late summer and early fall prices falling significantly. The advent of new pipeline take away especially in the Northeast Basins and NGL demand have helped stabilize prices this season. This stability is in question for next summer as production increases and may see the supply side weigh on pricing as it has in the past. For now, we look to early winter to see if the weather can move natural gas prices higher to give royalty owners a great opportunity to initiate an Advanced Royalty Program to capture the better value and will be watching for oil to...