Pacific Northwest Refiners Face Crude Sourcing Setback in 2020

Pacific Northwest Refiners Face Crude Sourcing Setback in 2020

IMO 2020 rules restricting sulfur content in marine fuels will force refiners to find new sources of crude

With the International Maritime Organization’s (IMO) restrictions on marine fuels with sulfur content greater than 0.5% coming into effect in January, refiners around the world should be well on their way toward adjusting their operations to mitigate the impact on their business. For some, the transition away from high-sulfur fuel oil to low- and ultra-low-sulfur blends will be less difficult than for others. For example, many refineries along the U.S. Gulf Coast should be well positioned for the change given the relatively high complexity of refinery configurations in the region and growing access to supplies of sweet crude. Other refiners, such as those in the Pacific Northwest (PNW), face steeper challenges.

PNW Refiners Face ANS Crude Conundrum as IMO 2020 Takes Hold

In its heyday, crude from the Alaskan North Slope (ANS) made up over half of PNW refiners’ crude slate. However, this dominant share of the market was substantially reduced over the past 10 years as deliveries of Bakken crude by rail from North Dakota became commonplace. Despite its diminished status though, ANS still makes up close to one-third of the PNW’s crude slate today.

This is going to be a problem in a post-IMO 2020 world because ANS makes a very high-sulfur vacuum resid (see chart below), and in large quantities. Indeed, roughly 20% of the ANS atmospheric distillation column goes to producing heavy residual fractions. Compare that to 6.9% for Bakken and less than 1% for most Canadian synthetics. This wasn’t a problem when the sulfur specification for marine bunkers was 3.5%, but it will be a problem in a post-IMO 2020 world when that threshold is reduced to 0.5% for many vessels still not fitted with scrubbers.

In the chart below, you can see that this high-sulfur vacuum resid contributes significantly to the production of bunker fuels that will not meet the IMO 2020 specification. In contrast, refiners that run a diet of mostly Bakken, Canadian syncrude, or even a conventional Canadian sweet like Mixed Sweet Blend (assuming you could get it to the PNW) would have no trouble hitting the IMO 2020 spec. Of course, what we are presenting here is a simplification as refiners seldom run just one grade of crude. The point we are trying to make is that PNW refiners have a clear incentive to substitute some amount of ANS in their slates for something that will help them reduce their production of high-sulfur marine fuels. The challenge is going to be in the logistics.

PNW Crude-by-Rail Options Limited by Government Restrictions

Given the lack of local crude production and tight availability of sweet crude grades in the Pacific Basin, bringing in more light sweet Bakken crude by rail to substitute for ANS seems like the logical solution. Unfortunately for PNW refiners, legislation ratified by the state of Washington in July complicates matters significantly.

The stated intent of Washington’s crude by rail law was to improve public safety by restricting inbound volumes of crude grades the state government deemed to be dangerously volatile. A common measure of volatility for petroleum liquids is Reid Vapor Pressure (RVP), and the new crude by rail law put the RVP cap at 9 psi. Federal transportation guidelines are not that stringent, and the state’s safety concerns are disputed by industry groups as well as the states of North Dakota and Montana.

Right or wrong, the law is in effect, but rail offloading facilities that were either constructed or permitted before Jan. 1, 2019 have been allowed to continue receiving greater than 9 psi RVP crude. There is just one catch: each of the grandfathered rail offloading facilities is limited to receiving no more than its 2018 average volume plus 10% (or roughly 181 MBbl/d for the state of Washington as a whole).

Unfortunately for refiners, the letter of the law does not differentiate between grades of crude oil or their respective RVPs when assessed against that volume limit. Once a facility exceeds its 2018 average plus 10% gross volume limit (regardless of RVP), the facility has two years to phase out all receipts of crude oil with an RVP greater than 9 psi. Due to this stipulation, the Washington crude-by-rail law effectively puts a cap on all crude by rail (even low-RVP grades from Canada) unless the refineries attached to the grandfathered rail offloading facilities are willing to forgo high-RVP Bakken once the two-year clock runs out. This is not a desirable position for any refiner to be in as it constrains their options and reduces operational flexibility.

If Not Rail, Then What are the Alternatives for Shipping Crude to PNW Refiners?

With rail options limited just as the new IMO rules come into effect, the only other ways to deliver Canadian light sweet grades in the PNW market is by barge or via the Puget Sound pipeline (240 MBbl/d), which receives crude from the Trans Mountain system (300 MBbl/d). Unfortunately for refiners looking for incremental supplies from Canada, Trans Mountain is already operating at capacity, and this has kept the Puget Sound pipeline operating below nameplate. In other words, the PNW is already receiving as much Canadian crude as it can get.

This situation will change when Trans Mountain’s capacity is expanded to 890 MBbl/d in 2022. Not only will this allow for more capacity to be utilized on the Puget Sound pipeline, but the expansion at the Westridge marine terminal also would provide more capacity for waterborne movements down the West Coast. In the meantime, PNW refiners appear to be over a barrel and will likely need to source incremental sweet barrels from farther afield (such as West Africa) as they substitute out ANS. This will come at a high cost given current freight rates. Although PNW refiners may see their margins squeezed due to IMO 2020 and the higher cost of crude supply that will result from the need to find alternatives to ANS, these costs will ultimately trickle down to consumers of motor fuels.

All in the Family

All in the Family

With public and private upstream operators looking at alt funding to continue growth of operations, private equity-backed companies are also taking alternative approaches to their business.

After the downturn of 2016, private equity jumped into the oil patch to the tune of more than $100 billion and counting. Some of the most active quarters over the past few years have seen more than $20 billion deployed. Arbitrage was seen between the low prices of upstream assets that companies were unloading versus their inherent value; investing the time and money was a no-brainer for most funds.

The problem that private equity has always had: exit strategy. If timed correctly, they will jump into the market at, or near, a low to provide liquidity to the market and then jump back out as public companies have the capability to acquire. This was prevalent over the past few years as we saw upstream transactions reach more than 300 deals in 2018 alone, representing more than $80 billion. However, we live in a cyclical market, and if not timed correctly, private equity can be caught holding the bag.

Figure 1: Private equity raises through Q3. Enverus Capitalize.

As capital has dried up for public E&Ps due to hedge funds and investors demanding a return to profitability and banks shunning risk inherent to the sector, private equity has had a harder time cashing out. This is both due to a scale and liquidity issue. Consolidations for many larger E&Ps require what is known as “moving the needle.” This is a scale few companies reach (generally $1 billion and greater) as a standalone portfolio company.

On the other side, small and mid-cap operators don’t have the balance sheets to acquire due to the multiples being demanded for private equity to satisfy investors. Private equity is also less likely to take a stock transaction, which is easier for small- and mid-cap companies, as it is hard to show value to their investors if they become tied up in a public market with flighty retail investors.

The risk is more inherent on companies that received funding more than four years ago, as the typical fund has an initial life span of five years, with an extension of up to an additional five if investors so choose.

As the end life of a fund becomes clearer, the investment committee is less likely to allow capital to be deployed for fear of not getting a significant return prior to redemption notices. Now, some funds can roll forward and many have investors OK with an extension of the fund life. However, the writing is on the wall right now that many of these companies will not have an exit anytime soon, begging the question, “How does private equity exit?”

The short answer is they don’t. Instead, they flip the script.

Instead of buy-and-flip, they become operators themselves. The return to this strategy goes back to the days of DrillCos and joint ventures, where investors’ returns were more based on cash flow of exploiting the asset and tax deductions from drilling and completion expenses, rather than a quick flip. It is a different type of risk than buy-and-flip but is a time-proven model for good cash on cash returns.

Figure 2: Count of private equity-backed companies by basin. Enverus PE Database.

Figure 3: Total committed private equity capital by basin. Enverus PE Database.

The negative of this buy-and-operate model is that you need less portfolio companies within the fund to exploit assets under management. More private equity sponsors are starting to consolidate their portfolio companies to lower overhead expenses, but also to grow the asset base and drilling program potential for what will become their hold strategy.

By consolidating the portfolio companies, private equity sponsors are also making the assets more attractive to larger buyers that can still float bonds or equity to acquire assets. Consolidation is not limited to within the fund that the portfolio company is in. Cross-fund and cross-sponsor consolidation is also occurring to maximize the value of the assets these various sponsors hold.

Like many industries, buyout private equity has a large amount of dry powder to deploy, and with the recent shutting of capital markets to public companies, a new life has been given to private equity. Unlike a public operator, private equity can shift strategies to maximize returns based on what the prevailing market needs.

Capital deployment for upstream has started to shift focus to minerals and alternative lending strategies. By providing the liquidity the market needs to make deals happen and to allow operators without the capital availability to grow, private equity is more important than ever.

DrillCos are fundamental in allowing operators to prove up or grow an asset that is non-core compared to selling in a buyer’s market. Mineral acquisitions tied with upstream private equity-backed companies give additional value to acquisitions by providing higher net royalty interests and an alternative cash flow. These consolidated assets of minerals and producing properties are more attractive due to their long-term value in stacked plays. If an operator buys a private equity-backed company that owns the majority of minerals under its producing assets, you answer only to yourself where pooling laws exist and more revenue is retained, raising both net present value and internal rate of return.

We have seen less companies being funded in this transition to buy-and-hold as well as a rise in alternative funding. What is yet to be seen are the long-term implications on basins and offset markets, such as oilfield services, as we have more private operators developing assets.

Private equity tends to be more forward thinking, pushing the boundaries of basins, plays, and economics. They have spurred the growth and interest in basins such as the Permian, Powder River, DJ (Wyoming), Uinta, and Haynesville. Will the shift affect our growth as an industry and the movement to new undeveloped plays? Will we begin to see less exploration and exploitation onshore? Only time will tell how the public markets shunning of providing capital will affect the growth of our industry.

Figure 4: Rig market share, public vs. private. Enverus Rig Analytics.

Figure 5: Completion market share, public vs. private. Enverus Engineering.

As we look to the future of liquidity and capitalization within our industry, we must focus on both public and private markets. Private equity, like hedge funds, provide liquidity to markets when conventional avenues are closed. They are the innovation drivers for expanding plays and improving efficiencies like venture capital is to technology companies.

While public markets are going through a fundamental change in our ever-cyclical market, private equity will fill the gap to ensure that we as an industry move forward. For public companies that are facing financial headwinds, private equity will be the one coming to their aid. It might not be this quarter or next, but as companies start to feel the pressure, or face selling an asset at a lower than needed multiple, private equity will be there.

Public companies come and go, PE will always be around. If you don’t believe it, look at how much money the largest funds have raised over the past year in anticipation of future exploits, more than $100 billion in 2019 alone that will be deployed over the next five years.

Following the money isn’t the easiest. Enverus has tracked more than 6,000 private equity events over the years to keep an eye on these trends, more than 600 of which are shown in Figure 6 depicting the fund raise and closure over the past few years.

Figure 6: Closed and announced raise of private equity funding by quarter. Enverus PE Database.

The Week Ahead For Crude Oil, Gas and NGLs Markets – November 11, 2019

The Week Ahead For Crude Oil, Gas and NGLs Markets – November 11, 2019

CRUDE OIL

  • US crude oil inventories increased by 7.9 MMBbl last week, according to the weekly EIA report. Gasoline and distillate inventories decreased 2.8 MMBbl and 0.6 MMBbl, respectively. Total petroleum inventories posted an increase of 3.9 MMBbl, generated primarily by the crude build. US crude oil production was unchanged from the previous week, per EIA, while crude oil imports were down 0.62 MMBbl/d to an average of 6.1 MMBbl/d.
  • WTI prices extended the gains from the previous Friday, showing some strength early in the week on continued optimism from the US economy, the expected confirmation of a Phase 1 deal between the US and China in the tariff disputes, and the upcoming OPEC+ meeting coming in early December. Prices also got support from the third-quarter earnings reports from the US E&P companies, which have been pointing toward lower capex plans in the coming year.
  • Over-supply concerns continue as the OPEC World Oil Outlook report provided a grim forecast of non-OPEC production (led by the US) outstripping demand over the next five years. The upcoming IEA World Energy Outlook (scheduled release November 13) should shed more light on the upcoming supply and demand situation in 2020.
  • The optimism early in the week was muted by the inventory release on Wednesday with the large gains in crude. This capped the gains from early in the week, but prices recovered most of the declines by the end of trade on Friday, in spite of the bullish recovery of the US dollar during the week.
  • Internal price relationships continue to show the prompt month maintaining a significant premium to the 2020 strip, confirming concerns regarding the supply and demand balance in the future.
  • The CFTC report released Friday (dated November 5) showed a support in the movement between the speculative expectations, with the Managed Money long sector increasing positions by 9,335 contracts, while the Managed Money short positions reduced by 9,414 contracts. This provided enough buying to maintain the strength early in the week.
  • Market internals last week brought a neutral with a slightly bullish bias, with prices closing up on the week with higher volume and gains in open interest.
  • Prices continued in the recent range between $53 and $57 while expanding the higher end of the range. Further extensions of support will take prices above the commonly traded 200-day moving average ($57.24 today), and a breakout above that level on a daily closing basis will send prices toward the highs from September between $58.49 and $59.39. It was this moving average zone that limited last week’s gains and where sellers were found. Bearish input from concerns about the global economy or hold-ups in the US/China trade deal could bring another test at the low end of the range at $53, which will likely find buyers.

NATURAL GAS

  • Natural gas dry production increased 0.07 Bcf/d last week as production came back from the weather-related issues. Canadian imports increased 0.12 Bcf/d on the week.
  • Res/Com demand increased 6.04 Bcf/d, while power demand decreased 1.33 Bcf/d and Industrial demand increased 0.56 Bcf/d. LNG exports declined 0.39 Bcf/d, while Mexican exports decreased 0.03 Bcf/d on the week.
  • These events left the totals for the week with the market gaining 0.20 Bcf/d in total supply while total demand increased by 5.09 Bcf/d.
  • The storage report last week showed the injections for the previous week at 34 Bcf. Total inventories are now 530 Bcf higher than last year and 29 Bcf above the five-year average. Current weather forecasts from NOAA in the near term (coming week) have below-average temperatures from the Midwest to the East, including eastern portions of Texas, with above-average temperatures in the West. The 8- to 14-day forecast shows warmer temperatures from the central Midwest and the Eastern Seaboard with normal temperatures in the Mississippi Valley.
  • The CFTC report released last week (dated November 5) showed a continuation of the short covering process by the Managed Money short position, as positions were reduced by 72,718 contracts, while Managed Money long positions increased by 10,777 contracts.
  • The market internals now have a neutral to slightly negative bias as prices rallied to a new high (only to correct lower) on higher volume, but open interest and remained relatively flat for the week. The week ended just about where it started; after trading to a new high, it is not bullish.
  • The extension of the previous week’s advances sent prices to the highest level since the end of February ($2.905). From that advance there was a steady amount of selling, and with the large gap opening today ($2.755-$2.716) offsetting the large gap last Monday, the trade has developed an “island top” for traders to consider. With the flip in the weather forecasts, declines between $2.575 and $2.52 should occur in the coming weeks. Any reversals stronger than that will run into sellers at the gap formed today between $2.716 and $2.755.

NATURAL GAS LIQUIDS

  • NGL prices were up week-over-week. Ethane was up $0.010 to $0.203, propane up $0.023 to $0.516, normal butane up $0.038 to $0.679, isobutane up $0.007 to $0.813, and natural gasoline up $0.012 to $1.167.
  • US propane stocks gained ~320 MBbl for the week ending November 1. Stocks now sit at 100.17 MMBbl, roughly 15.64 MMBbl and 22.97 MMBbl higher than the same week in 2018 and 2017, respectively.

SHIPPING

  • US waterborne imports of crude oil rose for the week ending November 8, 2019, according to Enverus’ analysis of manifests from US Customs & Border Patrol. As of November 11, aggregated data from customs manifests suggested that overall waterborne imports increased by nearly 600 MBbl/d from the previous week. The increase was driven by higher imports into PADD 5, which were up 650 MBbl/d from the prior week. PADD 1 and PADD 3 both fell slightly, down 13 MBbl/d and 40 MBbl/d, respectively.

  • West Coast imports of Nigerian crude have been strong in 2019, averaging more than 60 MBbl/d ytd. The highest month so far was August, when imports were over 110 MBbl/d. November looks like it will be a strong month as well, with imports over the first 10 days nearing the monthly totals for September and October, closing in on 2 MMBbl for the month. On a per-day basis, they are at 190 MBbl/d. This has been roughly split between Erha and Bonga grades, both medium sweets. The Bonga cargo appears to have been taken by Marathon’s Carson refinery while the Erha was split between Phillips 66 Los Angeles and Phillips 66 Ferndale. Vessel tracking data analyzed by Enverus shows that this might be the last Nigerian cargo received on the West Coast this month. The next tanker from Nigeria headed to the West Coast appears to be the Pentathlon, a suezmax capable of holding 1 MMBbl of crude, which departed the Agbami terminal 18 days ago and is showing an ETA to Richmond, CA, of December 1, 2019. Chevron took the last cargo of Agbami to Richmond in late June.

Injection Lower Than Market Expectation, Prices Rise

Injection Lower Than Market Expectation, Prices Rise

Natural gas storage inventories increased 34 Bcf for the week ending November 1, according to the EIA’s weekly report. This is lower than the market expectation, which was an injection of 43 Bcf.

Working gas storage inventories now sit at 3.729 Tcf, which is 530 Bcf above inventories from the same time last year and 29 Bcf above the five-year average.

Prior to the storage report release, the December 2019 contract was trading at $2.811/MMBtu, roughly $0.017 lower than yesterday’s close. At the time of writing, after the report, the December 2019 contract was trading at $2.860/MMBtu.

The start of the winter season is officially here, and volatility already is making an appearance. During the last few trading days of October, the December 2019 contract gained ~$0.17/MMBtu from October 25 to October 31 to reach $2.633. The gains have not slowed down during November, as the December 2019 contract closed on November 5 at $2.862, the highest close for the contract since September 16. This rally can be attributed mostly to the weather forecasts adjusting to show cooler temperatures in the northern Midwest. However, weather forecast changes likely do not explain the entire rally. Initial stages of short covering were seen on the CFTC report, dated October 29, as the Managed Money short positions decreased 21,951 contracts, while the long positions increased 12,085 contracts. This short covering was brought on by the price rally with the weather forecast changes. As prices increased, traders sold off their short positions, adding fuel to the price rally.

See the chart below for projections of the end-of-season storage inventories as of April 1, the end of the withdrawal season.

 

This Week in Fundamentals

The summary below is based on Bloomberg’s flow data and DI analysis for the week ending November 7, 2019.

Supply:

  • Dry production increased 0.07 Bcf/d on the week. Most of the increase came from the South Central (+0.36 Bcf/d) and the East (+0.20 Bcf/d), with an offset coming from the Mountain region (-0.53 Bcf/d). The Midwest and Pacific saw small gains.
  • Canadian imports decreased 0.06 Bcf/d.

Demand:

  • Domestic natural gas demand increased 5.69 Bcf/d week over week. Res/Com demand accounted for most of the increase, rising 6.39 Bcf/d. Industrial demand also increased 0.69 Bcf/d, while Power demand decreased 1.39 Bcf/d.
  • LNG decreased 0.21 Bcf/d, while Mexican exports decreased 0.02 Bcf/d.

Total supply increased 0.01 Bcf/d, while total demand increased 5.64 Bcf/d week over week. With increased demand and relatively flat supply, expect the EIA to report a weaker injection next week. The ICE Financial Weekly Index report is currently expecting an injection of 4 Bcf. Last year, the same week saw an injection of 39 Bcf; the five-year average is an injection of 10 Bcf.

The Rise of Alt Lending

The Rise of Alt Lending

According to a recent study by The Economist, more than 44% of home mortgages in 2018 originated from non-bank lenders, compared to just 9% in 2009. It seems everywhere you look alt lenders will loan money at lower interest rates and in quicker time than a traditional bank. While banks have layers of bureaucracy to go through, and for good reason, alt lenders only have their financial backers to answer to.

Some alt lenders crowdsource their funding so all risk is on the individual, much like an investment vehicle. In reality, consumer alt lending is new to the market, but business alt lending is not. Oil & gas companies have always had creative, and sometimes confusing, alt lending structures such as DrillCos, overriding royalty interest (ORRI), and asset-backed securitization (ABS). Let’s take a look at these three structures to better understand where the market is heading in terms of alt lending for oil & gas.

Figure 1: Study on alt lending rise within the mortgage industry.

Figure 2: Alt lender PayPal growth of consumer loans.

DrillCos

DrillCos are the oldest alt lending products for oil & gas. With the enormous amount of “dry powder” private equity (PE) has, and poor alternatives operators have to fund drilling, these have seen a resurgence recently.

Even larger independents use this structure on non-core assets that they don’t want to deploy capital or time to. It allows them to maintain ownership of the asset while lowering costs by turning the acreage to held by production (HBP) status. A DrillCo is where a financier will pay up to 100% of the costs to drill and complete a well for a certain percentage of the working interest that is reduced as hurdles are met. They will maintain a minority ownership stake in perpetuity, or it will convert to an override after hurdles are met. This allows them to receive the tax advantage of drilling a well with a long tail payout. A simple example is a financier providing 100% of the capital to drill and complete a set of wells for 75% working interest. This would mean the operator has a carried interest of 25% until hurdles are met. Once the hurdles are met, the financier’s interest is reduced until it is a minority interest, or it can convert to an override.

EOG employed this strategy in their Ellis, Oklahoma, acreage which allowed them to prove up the asset without deploying much of their own capital. If the DrillCo is structured correctly, there is a lot of upside left for the operator after the initial wells are drilled, holding acreage and lowering unit costs as infrastructure and locations are already proven. Other DrillCos announced include CRC Resources, EP Energy, Eclipse Resources (now Montage), and Ascent Resources. Some PE firms have raised exclusive funds for the deployment within DrillCos; GSO Capital Partners used $500 million in funding for Sequel Energy II which focuses on DrillCos.

For PE firms, a DrillCo allows them to put capital to work without the overhead management of internal teams. Their capital isn’t going toward grassroots leasing or the crowded world of bidding on an asset; instead it is being directly deployed into an asset and well. This creates instant value for investors and allows them to use tax advantages in regards to drilling expenses to further bolster returns.

Figure 3: Dry powder (committed) among all private equity companies.

Overriding Royalty Interest

Canadian E&Ps have used overriding royalty interest (ORRI) as a form of alt lending for decades, while this is just starting to take hold for public E&Ps in the U.S. Compared to a loan, an ORRI allows for the operator to shift some risk to the override buyer. With a loan, operators pay a fixed rate regardless of overarching commodity prices.

More operators are floating longer-term bonds to try and reduce near-term commodity and interest rate changes. An override for cash today, eliminates the commodity and changing interest rate environments as you pay a fixed amount of cashflow. This places more risk on the owner of the override and allows companies to remain flexible and not have to take on additional debt. Now, over time the override can be more expensive than a traditional bond or equity issuance, but since that market has been stagnant, operators must find other ways.

The prime example of an operator using an override to reduce debt is Range Resources. They have issued 3.5% ORRI, in total, for more than $1.15 dollars. In the near term, this will not affect much of their cashflow as the override is on 350,000 acres, which is not fully developed. In total, the cost net to them in year one will be approximately $85 million, but will allow them to reduce debt by $1 billion. The two buyers of the ORRI will continue to see their cashflow increase, or at the very least maintain, as Range continues to drill on the property and pricing recovers long term.

Date Amount Raised ORRI % Acres Cashflow to Buyer, Year 1
10/2018 $300mm 1% 300,000 ~$25mm
7/2019 $600mm 2% 350,000 ~$48mm
10/2019 $150mm .5% 350,000 ~$12mm

There is also opportunity for public mineral companies to participate in these ORRI financings. By partnering with a company in a basin, public mineral companies can secure long-term revenue without changing their business model. Operators in turn would receive the funding they need to reduce debt or increase drilling activity and the relationship becomes mutually beneficial. As more mineral companies become public, there will be a crunch in the market for deal flow to maintain growth and revenues; companies will have to come up with interesting ways to grow their business. Why not partner with an operator and own the drilling schedule?

Figure 5: Debt issuance in 2019 using Enverus Capitalize shows an all-time low until Q3 (Oxy and Exxon accounted for more than 50% of total issuance in Q3).

Figure 6: Equity issuance in 2019 from Enverus Capitalize report.

Asset-Backed Security

The newest form of alt lending we think might get some traction are asset-backed securities (ABS). By securitizing an asset, it opens it up to more investors looking for yield from a financial product that has an investment grade. Asset-backed securities also differ from other financial products as they are a financial product backed by a hard asset, such as royalty streams.

The benefit of an ABS is that risk is lowered as you pool together various streams of revenue that otherwise could not be sold on their own, for instance, hundreds of small royalty payments. The problem that will always exist for oil & gas is determining the value of the assets we own. Real estate is more straightforward, payments stay the same and delinquency rates are low for certain tranches while the underlying asset appreciates in value. Oil & gas assets decline over time unless new drilling takes place, but at the end of the day almost all assets go to zero.

Raisa was able to securitize non-op interests across 700 wells, which reduces risk of non-payment. It is much harder to show up at a well site and take ownership of your percent, however, than foreclose on a property. The ABS sold by Raisa has been compared to aircraft and railway issuances except, that those industries yield closer to 4.5% compared to Raisa’s ABS, which is 6% or more—meaning buyers are still unsure of the underlying risk of oil & gas assets.

There have been questions on how PE will exit their investments if the market is not willing to accept the multiples they request. One thought was that larger funds could create a separate debt fund to pay out investors. The problem is that this saddles PE-backed operators with a debt-loaded asset that reduces their ability to scale and grow. Many of these companies can get ratings on their debt, but it is still close to or at junk status. The ABS provides another avenue that would be open to additional investors on the street.

For mineral companies, both public and private, this might be one of the better routes to take if public investors won’t allow for additional debt or equity issuances. Since Raisa is the first one to complete one of these security issuances, it will be interesting to see if additional requests are made. If there is one thing the street likes, it’s new forms of investments to sell.

Will we see insurance products pop up if ABSs take off? Will there be other products similar to credit-default-swaps, as we see in the mortgage industry? Reinsurance? If (and it’s a big if) this takes off it will raise the question of to what limit will be placed on derivate products that are created, and that could create a house of cards.

Bearish Inventory Report Keeps the Pressure on Prices

Bearish Inventory Report Keeps the Pressure on Prices

US crude oil stocks increased by 7.9 MMBbl. Gasoline and distillate inventories decreased 2.8 MMBbl and 0.6 MMBbl, respectively. Yesterday afternoon, API reported a crude oil build of 4.26 MMBbl alongside gasoline and distillate draws of 4.0 MMBbl and 1.6 MMBbl, respectively. Analysts were expecting a crude oil build of 1.5 MMBbl. Total petroleum inventories posted a decrease of 3.9 MMBbl.

US crude oil production remained unchanged last week. Crude oil imports were down 0.62 MMBbl/d last week, to an average of 6.1 MMBbl/d. Refinery inputs remained low. Averaging 15.8 MMBbl/d (0.24 MMBbl/d less than last week’s average), which was a major factor behind the large crude build.

West Texas Intermediate for December delivery settled higher on Tuesday at $57.23/Bbl, up 69 cents per barrel from the prior day. Flat price had been up for the past three sessions and was approaching five-week highs. Sentiment was lifted by reports that US and Chinese officials may be close to reaching an agreement to partially roll back some tariffs as part of the Phase One trade deal currently under negotiation. Prices had also been bolstered with the release of third quarter earnings reports from US E&Ps, which so far have been pointing toward lower capex plans in the year ahead. Oversupply concerns continue to linger, though, capping gains. Indeed, OPEC’s World Oil Outlook report released yesterday made headlines due to its grim forecast of non-OPEC production (led by the United States) outstripping global demand over the next five years. OPEC plans to meet next month to discuss further cuts to production.

Petroleum Stocks Chart