News and Opinion

I have been directly involved in this part of the market for over 10 years, and I can tell you, nothing makes me happier than $80 oil we’ve had for the past month. 

Before I exclaim why, let’s talk about the dynamics of low and high oil prices and how it affects the upstream market as a whole.

Lease Acquisitions

Sure...if you’re a Buyer, $40 oil sounds like a good time to buy producing leases. But good luck finding it! Many Operators drill/re-enter/rework their own leases when oil price is low. Low oil market price is also correlated to prices of oilfield services and tangibles. If there no plans for development, many Operators will simply slow down or shut-in production until oil prices go up. This means Buyers really must hunt to find these leases.

For some reason, when oil hits $100, both undeveloped and producing leases go sky high in price beyond what can be expected for small to medium developments/holds.  Buyers are wary (and should be) because historically those who purchase leases at this high rate lose lease value unless they increase production right away in the $100 space.

Lease Development

Let’s revisit $40 oil. For development, your AFE (authority for expenditure) is appealing. An Operator and Working Interest Investor can certainly get in on the ground floor on labor and materials. And if the economics work where an Operator can make profit at $40, then it’s great! The issue is when the oil price stays at this level for more than 6 months. Both labor and materials start disappearing as service companies cut back on employees and bulk materials orders. It takes a while for the supply side to ramp back up to meet demand in this space when oil does go back up.

When oil reaches $90, good luck finding either labor or materials! Everything is pretty much spoken for! 

Why I love $80 Oil

· Producing lease supply is high – Sellers and selling, Buyers are buying...plain and simple.

· Producing Lease acquisitions get done – I cannot tell you how many times I’ve seen where deals fall apart when oil is above $90 and the market fluctuates even 15% either way (although most agreements have a 20% clause for price negotiation during due diligence period). Buyers can become skittish. I rarely see this at oil $80 or below.

· Oilfield services and tangibles supply and demand are optimized – When $$ is flowing steadily from Investors and Operators for lease development, both services and materials providers can count on contracts for new hires and bulk orders.

· Profit margins – If you can make $40 oil work, $80 oil is fabulous...and any Operator can make $80 oil work on paper today!

Most important – Energy in the upstream sector is high, optimistic, and stable

I’ve seen the highest highs and lowest lows being in the industry either directly or indirectly my entire life.  If you are looking to invest or sell, you won’t find a better time to see what $80 oil provides tangibly and psychologically for the sector. 

We are in the “sweet spot”. 

Bank of America last week is predicting Brent will go up to $120 a barrel in Q2 2022. Main reasons stated were current supply chain problems and an uptick in demand from China. Other reasons are the Administration lack of financial support for the entire industry despite uptick in product demand coming out of Covid.

Let’s get to why we don’t see $120 oil...

· Distribution: We believe both infrastructure and export chains will be pretty close to pre-Covid balances by end of April next year. Regulations are relaxing at ports to help break the gridlock and pipelines are still being built.  The Permian solved their problems back in Q4 2019 and other large producing formations already have infrastructure in place.  

· Investor $$ being swayed to go to “green” counterargument: The article states a “climate-inspired slowdown in investment in new sources threatens to allow reserves to wither”. I agree with that on larger production plays. The new Infrastructure Bill does have some sexy incentives for those who choose to go into the space with all of the incentives. However, on the market side, opinion-makers will ease escalation oil price predictions soon and potentially pocket a potential short. This will help keep most investment $$ rolling into the space in Q2, especially when confronted with actual demand. Renewables delivery and timelines to payout have much more accurate economic and depreciation models than past trends, and smart money always diversifies when presented with better data..

· Sellers get Greedy: For some reason, when oil hits $100, both undeveloped and producing leases go sky high in prices beyond what can be reasonably expected for small to medium developments/holds.  Even hedge funds and large oil companies are wary of purchases in this space. They’ve held the bag too many times on buying oil at ridiculous prices for refined and unrefined product in the past to forget the beating they took on the market in less than a year typically. Deals simply disappear, which will eventually drive down market price, despite demand.  Producers will simply squeeze more out of their current leases by developing PUDs and testing POSS.

· MOST IMPORTANT: Ramp Up Capabilities: Almost all domestic oil companies onshore (and small operators) have access to technology that can quicky extract both PDP and PUDs at near the lowest prices in history.  You can ask Russia and OPEC about this from the run they tried to pull off a few years ago.  Of course, we’ve been seeing labor and equipment shortages, but this has been the story for the past year, even at $50 oil. People and supplies will be back in the fold when the weather starts to warm up. 

Quick takeaways: Reserves are plentiful, technology can push out product quicker and cheaper to take advantage of current demand pricing, smart $$ will diversify, and supply chain should be back to normal by June.  Both demand and market price will be stable.  

We’ve seen this all before in some form...

So why invest today? Because both buyers and sellers make $$ in the current market. Most operators we promote can make $30 oil profitable! 

And...If you invest today in producing or development, and it goes to $120, guess who wins big?

As a lifelong fisherman from Alaska, I’ve learned 2 basic rules that will help you fill the freezer for the winter. 

Rule #1: Go to where the people are

Rule #2: Go to where the people aren’t

Sounds like confusing (if not contradicting) advise, right? Well, here’s how it applies to Oil & Gas Direct Investment...

Rule #1: The reason why this works because in geographical plays, it attracts the most energy and excitement ($$, labor, equipment, etc.). It allows a certain amount of risk reduction (either real or perceived) for the investor knowing that they are not the only ones putting funds into a play. The good thing about this is when the play is “hot”, it benefits all in the space. Once the hedge fund $$ come in and lease prices go up, it becomes more difficult to find programs with solid quick payouts. Gems can still be found...you just have to be a little more patient. 

Rule #2: There are a few advantages that going outside of the area pose for the investor. I mentioned a few of these in a previous article (play congruity,  Better NRI, potentially better payouts and ROI, etc.) but I want to add a little more to it...

Typically, we like to see Operators think beyond a “one and done” program in these areas. We look for them to secure additional adjacent acreage so if the wells are successful, we can go beyond a “Phase I”. The cheapest time to do to that is when there’s not a parade of landmen waiving blank checks in front of landowner’s faces. If the Phase I wells are producing as expected, not only will you have mailbox money, but many mid-majors and other investment groups will come knocking on the Operator’s door for the Big Buy Out. You now have 2 quick options of making your investment back. 

Saying that, we have programs in the Eagleford trend (Rule #1) and in Kansas (Rule #2) for your consideration. 

Unlike fishing, you can work both rules at the same time and there’s no bag limit!

October 2021  -  Beyond the Spotlight

We all know about the plays that get the most attention. 

We hear about them in the news. Either non-conventional or conventional plays that get this attention make it easier for operators to raise funds for exploration and development. Let’s admit, there’s a great feeling of safety for investors if they’ve heard the names of plays like “Permian”, “Bakken”, etc. or even whole states like Texas and Louisiana. 

Now, let’s talk about VALUE...

We like our Operators to also consider thinking beyond these “hot” plays for a variety of reasons

· Lease Availability – There’s simply more to choose from outside of hot geographical areas (HGA).  It’s also typically much easier for Operators or lease investment groups to acquire more acreage on the notion that the first phase of development will meet production estimates.

· Known formations – Even though we like leases outside of the HGAs, we still want to find good field data and any old well logs from the lease or surrounding leases. Blanket formations in the Mid-Continent stretch across various states and they are relatively un or under-recovered, like in Kansas and Oklahoma

· Pricing – Leases are simple cheaper outside of the HGA along with locking down surrounding leases for future development.

· Royalty – non-HGA leases tend to have lower royalties vs almost all other HGA

· Stranded reserves – Leases that have stranded wells in HGAs typically have been evaluated many more times over non HGA leases. Also, due to less enthusiasm to look at these stranded reserves, you can typically find more percentage remaining in non-HGAs. Simply put, the low-hanging fruit on HGA has most likely already picked.

· Movitaved service providers – this is critical. We find that service providers really don’t want to leave their hometowns for too long. If they can find work closer to their house, they will...and will do it for less money and quicker turn-around times.

In short, good programs can be found just about anywhere and, in many cases, have better appeal on paper.

Looking for some “out of the zone” plays? We have a few points remaining in an Indiana (Illinois Basin) play and a new program out of Kansas in the Mississippian Lime. Click Here to find out more.

  "Whoa There” Natural Gas! 

Natural Gas went from $3.90 last week to $5.27 today! That’s a 35% jump! Talking amongst friends in the industry, we don’t expect the price to stay above $5.25 for too long this month. But, it would not be out of the question to see it go to $6 in November due to seasonal demand. Not seeing a significant drop through Q4...maybe to $4.

Will Oil Follow Natural Gas?

We feel that heating fuel demands plus domestic/geopolitical factors may push prices above $75 in the short term. Most will remember last year’s cold snap and order full tanks for their houses and businesses before the season starts. Holiday travel is a tough cookie to call at this moment to see if it will affect prices in a significant way. Easy call to predict the price won’t get above $80 nor below $62 in Q4. In the past, both products typically follow the same upward or downward trends when supply and demand are real and not market inflated. 

“So, what’s the Plan?”

Get investing! Major tax advantages for those who are sitting on too much $$ before end of fiscal year (for many).  Good time to look at quick re-entries or reworks to capture peak market price...we just happen to have a few to consider.

I met with an associate of mine in the industry last week who works directly for smaller operators.  This person told me that there are a lot of people from the larger cities purchasing land/homes in their area...many of these are second or third properties.  Some of these new landowners are putting pressure on operators who have producing leases on their land.  In some cases, it’s a matter of simple cleanup and maintenance, which is totally legit.  However, some of these new landowners are simply harassing beyond reason.  I heard stories about landowners telling operators to paint equipment, add “cute” fencing, only run equipment at certain times, etc. without monetary compensation.  

It goes beyond this...

Some are pushing legal limits of rights-of-way, lodging illegitimate complaints to governing bodies, and even using legal system “extortion” (serving papers to simply outspend them in legal fees) to force operators to plug and remove surface equipment just because the landowner doesn’t like how it looks.  Many of these landowners don’t even have subsurface rights!

Let me talk directly to new or those thinking about purchasing acreage with operating wells...

Most independent operators can make decent profits on marginal wells that large companies cannot because the Operator turn the wrenches themselves.   Most are salt-of-the-earth people.  Most marginal wells do maybe around $100 a day in gross revenue only.  Unnecessarily harassing an operator because you want an uninterrupted view on your lot on a 3-day weekend hurts families and the community directly. 

So, how should one conduct due diligence with producing wells on your prospective acreage?

• Ask your real estate agent about the relationship  with the current landowner and Operator.  See if there’s any complications or unwritten agreements.  
• Read up on the regulations before making a purchase.  Know your rights and an Operator’s.
• Ask to meet with the Operator(s) before you make purchases. Who knows? You may be coming in as a hero! 

In Conclusion....be good stewards of the land and the community.  Don’t be an Ass Hat.

  “What are the Risks?”

OK, we get this question from new and even seasoned investors. And it’s a good question. Every deal can have a unique set of risk, but the 2 big ones that pop into my mind are

A drilled or re-entered well is simply not economical to produce in any formation after testing

A drilled or re-entered well fails during completion efforts.

Let’s break these down into categories to explain further...

Formation

This mostly refers to geology and structure. Some formations are well defined where others are not (whether viable candidates for completion or not). 

These days, there is considerably less risk than in the past due to historical data and geophysics.  Blanket formations, proven fields or even leases (producing or non-producing) can be found quite easily, but even these have risk if there’s faulting or other localized geological phenomenon. 

You’ve may have heard the term “wildcat”. This pertains to a formation or localized anomaly that has been untested (though researched at a minimum) through traditional means. Risk of being non-productive is high, but they are fun (for some) and can give you bragging rights for decades if they hit big! 

Completion

You may have read a previous opinion explaining that completion is where the “rubber hits the road”. Even the most prolific and seasoned operators run the risk of the following: 

· Mechanical well failure (rods & tubing, casing, pumps)

· Unwanted water intrusion (pulling too hard or too low in a formation)

· Blowout – (too much bottomhole pressure)

· Lost or broken tools downhole

· Wrong drill mud

· Fracking misreads (both mechanical and chemical) 

So, how to mitigate risk in these 2 categories?

· Find prospects with multiple payzone candidates and/or leases with existing or historical production.

· Administer field proven completion methods with reputable operators familiar with the formations 

There are other risks and but there’s other ways to prevent a total loss of investment, but that will be another post.

Your best bet? Call us and we’d be happy to explain the pro’s and con’s as we see them per deal and, as always must be stated, DO YOUR OWN DUE DILIGENCE.

If you’ve never seen this acronym before? It means “Drilling, Testing, and Completion”.  Most newcomers don’t fully understand that most success in prospecting hinges not in the Drilling and Testing, but the Completion.

Based on technology and historical field data, it’s hard these days to completely screw up drilling and find non-economical payzones when testing.  Once drilling and testing is done, then the real work begins...

Completion of any well are dependent on many variables like material type (shale, limestone, sand, etc.), porosity, permeability, initial hydrocarbon showings, water content, possible water intrusion, and well depth.  These variables have to be understood before any plan is put into place. That’s where things get started.  This could take me all day to write on this, but this is a good place to start if you want to do a deeper dive.  (https://deepdata.com/well-completion/)

So what’s does Completion have to do with program evaluation?

An AFE (authority for expenditure) can have Completion costs that vastly outweigh what Drilling and Testing is.  Ideally, what we like to find are operators that have proven methodology to complete wells in a defined payzone in a given area (infield production).  The next best thing is to find prospects where the completion methodologies are established (almost industry standard) for those payzones.  If the completion methods are well defined, the chances of AFEs going beyond scope are significantly reduced, therefore keeping within program budget and avoiding cash calls.

Check out our opportunities ..our working interest programs meet either criteria above.

About a year ago, we were approached by an operating company out of the Illinois Basin for promoting working interest. As a group that had topical knowledge of IL Basin geology, the infrastructure, and have been burned in KY about 10 years ago, we were very hesitant about anything out of the TX-LA-OK area. 

After some due diligence we decided to promote their deal based on the following:

· NRI of 85% (TX is around 75-80%NRI)

· Shale payzone only needed 3-4 frack stages (other shales in US require at least double digit)

· $20 BO breakeven once in production

· Promised weekly updates

· And the big one...they have drilled 9 successful wells in the Basin in the target payzones

Well, it took a while (due to vendor and supply delays) but here’s the great news:

· The first well completed is on choke doing 180 BOPD (open is estimated at 300 BOPD) (not in shale)

· Second and third well already drilled and awaiting frack (out of 10)

· They’ve ACTUALLY delivered on weekly updates

· With oil at $70, this first well should pay off in 3 months

Based on the success of this lease so far (and another one we privately promoted in-house), we are encouraging you to check out these 2 new offers from the Operator:

· Working interest in a 2 well drilling program on a different lease in IL. Great entry price and potential ROI, much like the above. ID 1211

· WI the lease above in wells 4-10 .  ID 1202

As much as I like TX, I’m starting to fall in love with the IL Basin!

At the beginning of the year I write an opinion regarding where we think the industry will be domestically for a calendar year and where the advantage may be from an investment standpoint.  I like to revisit this around July to see how things stand.

I’m not going to pat ourselves on the back on what we got right...you can read our opinion in January for that. Let’s review where we “missed”.

• Rig count and stockpiles should be fairly stable throughout the year as world and domestic demand is only seen to rise no more than 5%. Rig count may have a higher percentage of re-entry vs exploration.

Rig count in TX alone went from 161 in January to 221 today.

• Some oil economists are predicting market price increases with volatility especially in Q1. It may create an artificial price spike with WTI and natural gas pricing in Q2.

Price increases are not artificial. It’s here to stay through the year.

• Lack of exploration makes for a scenario for increased demand and prices in 2022 with supply “chokes”. 

We’re seeing these “chokes” now!

• We’re predicting no lower than $45 WTI/ $2.70 natural gas and no higher than $73 WTI/$3.30 natural gas for 2021 for extended periods. WTI is $52 today and gas is $2.70...

WTI @ $73 and natural gas @ 3.60 today.

So, What Happened?

Current Administration: As predicted, we knew that administrative actions would elevate prices (closing Keystone and gov’t lease development were easy calls). However, we were thinking more “Obama”.  What we didn’t account for was federal unemployment extensions beyond Q1, causing massive labor shortages along all lines of manufacturing, distribution, and services. This has pushed all supply chains as demand is not being met because of...

Unprecedented consumer demand: We predicted that consumption would be coming up from demand, especially on transportation side (goods transport, office travel, tourism rebound, etc.) as the economy start to open up from our artificial shut-down. What we didn’t expect was the amount of cash being thrown around by consumers and extremely low bank financing rates...causing unprecedented inflation on all goods and real property, affecting directly and indirectly pricing.

Scorching Hot Weather: Early summer high heat has produced significant strain on the electrical grid. Records were broken this week all over the West. Renewables cannot keep up and hydro is falling rapidly as a reliable source. This mean all fossil fuel electrical producers are producing at full capacity.

The good news is that the oil and gas industry will have steady domestic demand for the entire year. The trick will be how E&P companies can streamline their labor to be more efficient and how savvy they can be to find equipment.

We estimate now WTI @ $85 by September and Natural Gas @$4.20 by November.

Best bet? Look for shallow exploration and re-entry programs, where equipment is already on the lease or is in greater supply for purchase. 

And yes, we have those!

When considering investing in E&P oil ventures, it is understood that it has global demand. The typical evaluation process goes from geology; reserve and production estimates; and cost to drill, test, complete (DTC); taxes and royalties; then lifting costs.  Who picks up the oil is on the list, but not critical as prices are relatively consistent between vendors.

However, natural gas prices are much more subject to regional demand and infrastructure.

For Natural Gas prospects, we start the evaluation at the "end" of the list by asking these 3 questions:

                         Who is the buyer and what is the contract price and terms?

This is the first question we ask, therefore most important. It is extremely helpful if local industry is a major player for the demand. We have seen leases that could net significant dollars from large production...if only there was a local market for it with a decent price in the area. We’ve also seen leases where natural gas is at premium demand in which even a nominal producer can be very viable (as low as 10 MCF). Having a contract price and terms in place assures your product has a place to go. If not in place on larger plays, it’s a “stop” for us.

                                              How far is the closest pipe to the buyer?

Natural gas is transported off a lease via pipeline while most oil is picked up in trucks. In many cases, distance between lease and buyer pipeline can be THE determining consideration. In Texas, it is rich in pipeline infrastructure. However, there may be only 1 gas purchaser in the area. This could drastically affect the price per MCF you can negotiate. Also, you have to build the pipeline and appliances to hook up into their pipeline. There may be right of way issues that must be addressed as well.

                                                      What’s the quality of the gas?

Natural gas can be quite different in BTU and condensate percentage. Higher values of both usually make your product more valuable. Another factor that can affect net revenue is whether it needs to be “scrubbed” to remove unwanted gases (hydrogen sulfide). This requires additional equipment on site. 

After we have these questions answered, do now we go through a typical evaluation.

I prefer gas leases with a mix of shut-in wells and production and most infrastructure in place.  Gas re-works and re-entries are typically less risky than its equivalent in oil.   We have a few mid-majors who are looking to unload such leases and operators ready to bring them up to speed.  Simply put, we can create custom packages to meet most investment criteria.

 Most fossil fuel investors are strictly oil. Those that invested in lease production programs early in the year are seeing big gains from buying in on cheap costs. West Texas Intermediate as gone from $48 to $70...a 45% jump in price. 

But finding undervalued deals on oil development is getting tougher.  Simply put...supply is shrinking and break-even is pushing out.

You know what else has gone up in price this year? Natural Gas! It’s up 33% this year.

I’m keen on natural gas right now for many reasons:

· Natural gas is used for both electrical generation – year-round demand

· Very reliable heating fuel source in cold months (unlike renewables) demanding higher prices 

· A great deal of workover and lease improvement inventory compared to oil leases

· Infrastructure in many areas is very solid for quick delivery

· Condensate can add a little extra $$ without additional costs

I’m predicting a higher ceiling percentage on natural gas in the upcoming year. Lights are already flickering throughout Texas due to burdens on the grid.  Renewables cannot simply keep up.

Now I get it...calling yourself a “Gas Man” is a lot less boastful than “Oil Man”...but your significant other won’t mind too much if your monthly revenue checks are bigger!

So, if you don’t have natural gas in your working interest portfolio, now’s the time to seriously consider investing. 

Check out our opportunities at KnikEnergy.com. We have flexibility on production and upside combination programs for all budget considerations.

             At the  beginning of the year I like to write an opinion regarding where we think the industry will be domestically for a calendar year and where the advantage may be from an investment standpoint. We've been MOSTLY accurate (taking out 2014) in the past, have felt confident we can make a decent prediction with some caveats.

To recap 2020, our prediction was fairly close...if you don’t count the pandemic!

                            So let’s talk about what we saw in 2020 on the world  market

• Rig  count was down by at least 40% throughout the world. Lots of layoffs from top producers up and down the chain.

• The United States was STILL the strongest player on the world oil and gas market. The US controls both imports and exports in their hemisphere and  what they will and can take from the Middle East.

• Large US producers evened out supply and demand for the most part by end of Q3

• Continuing sanctions on Iranian oil and pressure on their typical buyers to refuse delivery has certainly helped. It has helped stabilize the entire oil economy in the Middle East.

•       Anyone who shorted oil in Q1 got killed in early Q2 (but a good time to pick up some commodities).

• A “little” blip where you had to pay someone to pick up oil from West TX in April!

               What do we see on the domestic and international realm on a whole today?

• Rig count and stockpiles should be fairly stable throughout the year as world  and domestic demand is only seen to rise no more than 5%. Rig count should have a higher percentage of re-entry vs exploration.

• OPEC+ members will be coming back to play “ball” with the US markets...keeping all commodities stable...for about 6 months. (Russia went after Trump and US...didn’t really pan out for them)

•  Although their demand will grow, neither China nor India should develop enough new demand to outpace supply based on their current overall economic conditions.

• LNG and crude/refined product export market will slightly increase with a new China trade deal.

                                             What role does politics plays into this year?

This year, we anticipate that we will see similar policies implemented by the Federal Government side as we did in the Obama Years. This will create the following:

      • Little to no support for new domestic infrastructure (think Keystone       Pipeline)
     • Little to no new development support on any Federal lands or existing       leases
     • Open LNG business to China
     • Iran may come back into play as supplier
     • Federal Tax incentives being left alone

Leading to: Federal lease interest with ANY type of polarity (environmental action groups) will NOT be pursued by major oil companies (ex: ANWR bids were abysmal) AND mineral rights on private land may be valued higher.

                                  What can be expect for the domestic prices as a whole?

We’re predicting no lower than $45 WTI/ $2.70 natural gas and no higher than $73 WTI/$3.30 natural gas for 2021 for extended periods. WTI is $52 today and gas is $2.70.

Of course, there are possible factors that could fluctuate prices rapidly.   Some oil economists are predicting market price increases with volatility especially in Q1. It may create an artificial price spike with WTI and natural gas pricing in Q2. There is also the possibility that OPEC+ countries may go rogue and dump product on the market.

                  What does this mean for the direct domestic oil and gas investor today?

We are anticipating no fire sales of leases, production, equipment, nor any soaring prices of operating expenses. With little demand for exploration, it will keep lease and oilfield services and availability in check.

Lack of large exploration today makes for a scenario for increased demand and relatively diminishing storage in late Q4.

We are predicting a statistically significant price jump in both Brent and WTI by Q3.

We see some significant short and medium gains to be made for those who get in early into programs that have good potential for production and solid site management practices. especially in Q1.

Don't be in "I should have invested" boat...check out the programs we have today or call us to customize your investment criteria in this  space, including leases for sale.
____________________________________________________________

This  is not an offer to buy or sell securities. We are not a United States Securities Dealer or Broker or United States Investment Adviser. This is an opinion article and should be treated as such. Do your own due diligence and consult with a licensed professional before making any investment decisions.

©2021       Knik Energy | Ft. Worth, TX 

Knik Energy Inc. is officially announcing the halt of promotion of investment programs for well development or improvement offered by  Kelly Buster and/or assigns (Union Asset Management, LLC.  Strawn Partners Operating, LLC Holland Asset Partners, LLC, etc) .

And the Winner is: USA! 

The US has become the strongest player on the world oil market. 

The biggest reasons for this declaration are due to improvements in completion technology (fracking shale) helping to release more reserves, lifting of the crude oil export ban in 2015, the SURPRISING fiscal responsibility of large producers after the 2014 crash, and the fall or distaste of oil-producing countries’ product due to their corruption. 

The US has been the largest producer of oil for the past 2 months and its companies deliver on product promised. This has helped maintain a stable hydrocarbon global economic environment for those who “play nice”.

So, what’s does this mean to upstream investors like yourself?

It means that we can anticipate oil prices to stay relatively stable as well as expenses for drilling, testing, and completion for the foreseeable future. In this market, you will see very few “fire sales” and price gouging will be kept at minimum unless you’re selling over 1000 bopd leases. Some predictable circumstances for seasonal oil price fluctuation or increased field costs are delayed pipeline development in West Texas, weather (Texas had it’s rainiest October ever, halting almost all field activities in areas), and labor shortages. 

Being stable is being happy...and allows everyone to sleep peacefully. If you want this feeling from your investments, check out our opportunities page.

John Mink