Description

Tidewater Midstream & Infrastructure

Long Tidewater Midstream & Infrastructure (TWM) – price target C$2.35/share, ~3x upside

TWM is a Canadian refining and midstream business with a somewhat complicated and checkered past but a promising future. The company’s primary asset is the Prince George Refinery site in British Columbia, which produces 12,000 bbl/d of refined petroleum products, primarily diesel and gasoline, and 3,000 bbl/d of hydrogen-derived renewable diesel (“HDRD”). The company also owns a portfolio of natural gas midstream assets across the Deep Basin in Alberta.  Our core assertion is that TWM in 2024 is a transformed business compared to recent history after two pivotal events: 1) the sale of the Pipestone gas processing plants, which generated C$665mm in proceeds to repay debt, and 2) the HDRD facility reaching nameplate capacity in late February 2024 which will add an additional C$110mm+ in annual EBITDA. These events provide significant positive free cash flow in 2024 for the first time in the company’s history. Going forward, free cash flow will be used for both share repurchases and new investments in quick-payback, “low-hanging fruit” projects in assets that have been cash-starved for 5+ years.

We believe the stock is compelling as a fundamental investment and argue for a share price target of C$2.35 per share based on the company’s free cash flow profile in 2025 (roughly 8x free cash flow). We also believe the stock is compelling as a tactical investment after the new management team re-based expectations with a kitchen-sink Q4 report in March 2024. Given the complexity in modeling the moving pieces of the business, the Street had historically relied on (prior management’s) EBITDA guidance for forecasting. However, the new management team withdrew all former guidance and declined to provide any new estimates. The lower-than-expected Q4 results combined with a lack of new guidance resulted in several research firms downgrading both their ratings and forecasts.

Despite the negative Street reaction, the business appears to be on track to deliver significantly improved free cash flow in 2024 with the ramp of HDRD and the elimination of the heavy interest burden. The primary risk to the company’s free cash flow had been continued delays in the startup of the HDRD unit, but that facility has now been operational at nameplate capacity for several weeks at this point. Put simply, the primary risk to free cash flow generation has now been fixed, but no one appears to have noticed. However, TWM is a small-cap Canadian stock with a shareholder base predominantly composed of retail investors who likely have been selling on Street downgrades and the cancellation of the dividend in favor of share repurchases. Over the past two months, the stock has traded down to a 52-week low and market expectations are on the floor. However, the business is about to deliver significant free cash generation in the immediate future and then repurchase stock as the balance sheet has been fixed.

Brief History:

Tidewater IPO-ed in 2015 and operated a very diverse set of midstream, infrastructure, and refinery assets across Alberta and British Columbia under the leadership of former CEO and serial entrepreneur Joel Macleod. TWM was featured in two previous write-ups on VIC in October 2017 and June 2023, both of which contain detailed information on the historical business. At the risk of over-condensing a long and dramatic story into a few sentences, TWM encountered leverage and funding challenges as it tried to build and acquire too many assets at once. The assets themselves proved to be quite healthy and sustainable but the balance sheet was anything but—leading to a classic case of “good company, bad balance sheet”. After the HDRD plant encountered significant cost-overruns and delays during its construction, Macleod stepped down and was replaced by investment banker Robert Colcleugh. Colcleugh successfully executed a “save-the-company” transaction in August 2023 by selling two natural gas processing assets for C$665mm, in the process reducing TWM’s debt position dramatically. As the company transitioned from a restructuring situation to one focused on operational execution, the Board installed Jeremy Baines as CEO. Baines is a proven operator who also has significant experience working with the largest shareholder, Birch Hill Equity Partners. Prior to joining TWM, Baines was CEO of Campus Energy Partners, another Birch Hill portfolio company, and successfully monetized a collection of midstream and infrastructure assets spun out of AltaGas.

A brief summary of key recent events is below:

• August 2023: Tidewater announced it was selling its Pipestone I gas processing plant, Pipestone II expansion project, and its Dimsdale gas storage assets for a combination of cash and stock. The assets sold for a cash flow multiple of 11.3x, and the sale was transformative to the company’s capital structure. The sale closed in December 2023.
• November 2023: Tidewater announced the start-up of the long-delayed HDRD facility, albeit at reduced capacity.
• January 2024: TWM announced it was suspending its dividend and initiating a share repurchase program in the form of a normal course issuer bid (“NCIB”).
• January 2024: TWM announced a management transition as former CEO Colcleugh was replaced by CEO Jeremy Baines, with the company highlighting a pivot towards operational excellence and asset optimization.
• February 2024: the HDRD facility began producing renewable diesel at its nameplate capacity of 3,000 barrels per day.
• March 2024: new management team took a “kitchen sink” approach to fourth-quarter results, impairing several midstream assets based on higher interest rates and removing headline forward guidance. Reported Q4 EBITDA also missed estimates, due to the delays in the HDRD plant reaching full operational capacity and the over-hedging of HDRD feedstock given the delay in operations. An unusually warm winter also delayed sales of cold-spec winter diesel, causing further inventory build and operational issues in the December quarter. However, all the issues from Q4 were resolved as of the full-year update call in mid-March

TWM’s Asset Base:

TWM is actually a relatively straightforward business whose simplicity is obscured by byzantine segment accounting and corporate structure. TWM owns a series of midstream assets predominantly in the Deep Basin gas play in Alberta. TWM also owns 15,000 bbl/d of refinery assets in Prince George, BC, a relatively rural location with the market characteristics of a local monopoly (12,000 bbl/d petroleum refining and 3,000 bbl/d renewable diesel). The complexity lies in the fact that two different legal entities own the refining assets, with TWM owning 69% of the renewables business where HDRD resides. The renewables business is also a public company called Tidewater Renewables and trades on the ticker LCFS CN. Tidewater Renewables also owns a collection of renewables assets (hydrogen production, renewable fuels storage and logistics) located at various TWM asset sites.

Refining business: The primary costs for the petroleum refinery are feedstock (BC light oil from Taylor, not heavy oil from Alberta) and the costs of complying with the low carbon fuel standard (BC LCFS and CFR) regimes. The primary outputs of the petroleum refinery are diesel (~45%), gasoline (~40%) and heavy fuel oil (~15%). For the HDRD plant, the primary cost is renewable feedstock (canola, used cooking oil, tallow), and the outputs are renewable diesel and renewable fuel credits (BC LCFS and CFR). The HDRD plant’s credit generation is sized to cover the petroleum refinery’s obligations in the out-years of the government program. We view the entire refining complex as being a naturally hedged entity from an economic perspective rather than as a standalone petroleum refinery and a standalone renewable diesel facility.

We would strongly argue that the BC refining market is quite different compared to the larger and more commonly studied Gulf Coast, Mid-Con, and Midwest refining markets in the US. The BC provincial government undertook an exceptionally detailed and informative investigation into the market structure of local refining, which is linked here (https://www.bcuc.com/OurWork/ViewProceeding?applicationid=681). The main point to note is that, given past refining closures and the inability to permit or build new refining capacity, the province must import ~70% of its refined product needs (130,000-140,000 bbl/d). Historically, this demand is satisfied via a combination of marine imports into Vancouver, pipeline imports from Alberta via the Trans Mountain Pipeline (“TMPL”), and rail imports from Alberta.

Each of these import methods presents its own set of challenges. Rail is the most expensive method of importing and is limited to a select few markets not easily served by other methods. While TMPL does provide some of the refined product sold locally in BC, the overwhelming majority of TMPL volume is crude oil earmarked for exports and pipeline capacity is fully utilized. Marine imports are also severely capacity constrained. Most imports and exports in the province occur in the Vancouver Harbor via the Burrard Inlet. Nearly all large tanker docking space in the area is used for exports. Thus, most BC refined product imports must land via smaller barges or tankers built to dock in shallow water, which adds to cost. Due to the potential impact on marine wildlife in the Burrard Inlet, the BC government has placed severe restrictions on future construction or development of import terminals.

Most importantly, the province is short storage space for refined product. For example, Parkland’s Burnaby Refinery site can handle refined product imports but lacks the storage capacity to import while the refinery is operating. Thus, Parkland only imports refined products when necessary during refinery outages or during scheduled turnaround/maintenance work. The BC government has also placed environmental restrictions on building additional storage capacity due to the potential impact on wildlife. Given the extreme difficulty in permitting and building new pipelines, marine terminals, and refined product primary terminals, refined product imports into the province for local consumption are constrained. The import and local distribution capacity that does exist is fully utilized by four major firms who control all the relevant infrastructure. Given full capacity utilization on refined product terminals and storage in BC, the existing firms do not have an economic incentive to engage in price wars among each other. As a result of the inability to build a lot of new infrastructure to facilitate imports for new entrants, refined product pricing for BC has remained very stable over time. While this dynamic exists for the entire province, it is even more true for the Prince George region where TWM operates as the sole supplier with an 8-hour drive time from the closest alternative source of refined product in Edmonton.

Tidewater’s petroleum refinery at Prince George also stands to benefit from the new Trans Mountain Expansion Pipeline (“TMX”), which is set to begin service during Q2 2024. The new pipeline changes the pricing dynamics in the region in a way that will likely benefit Tidewater. The pipeline itself can transport 590,000 bbl/d of heavy crude oil from Edmonton to Vancouver to be exported globally. Future prices for the WCS differential, which is the discount that Canadian heavy oil sells for relative to WTI, have narrowed by more than US$15/bbl since November 2023. This means the price of Canadian heavy oil is set to increase. Refineries in Edmonton are designed to intake heavy oil, which means they will soon be paying more for their crude feedstock. To hold margins flat, these refiners must raise rack prices, which means gasoline and diesel in Edmonton will become more expensive. Because Tidewater’s rack prices are effectively determined by Edmonton pricing plus transport cost, Tidewater’s rack price should rise in tandem. However, Tidewater’s petroleum refinery uses light oil instead of heavy oil as its feedstock. Light oil prices are unlikely to be impacted by the TMX pipeline, meaning Tidewater’s margin should increase naturally due to its differentiated feedstock. Even without any tailwinds from TMX increasing rack prices, we estimate that the petroleum refinery at Prince George can sustainably generate ~C$78mm of EBITDA annually.

Another nuance for refining in British Columbia is the BC LCFS program. The provincial government mandates that anyone who sells fuel in BC comply with increasingly strict carbon intensity scores. Producing a fuel with a carbon intensity score below the required threshold (e.g. renewable diesel) generates BC LCFS credits while producing a petroleum-based fuel (higher carbon intensity score) requires purchases of credits for compliance. A similar standard called the CFR also exists at the national level. Increasing credit prices have been a major headwind for petroleum refining profitability in the last few years, but with the HDRD facility now running at full production rates, that headwind will be more than offset by profit generation from credit sales in the renewable subsidiary – albeit TWM owns 69% of the offset.

HDRD is currently running canola oil to generate renewable diesel but will migrate toward superior feedstock over time. Advantaged feedstocks like tallow and used cooking oil (“UCO”) have lower carbon intensity scores compared to vegetable oils like soybean and canola and, therefore, generate more credits. Tidewater’s HDRD facility has a pretreatment unit, which will allow it to switch feedstocks based on market dynamics. Tidewater owns a small used cooking oil business that it plans to scale over the next few years. The company has also established a 50/50 joint venture with Rimrock Cattle Company called Rimrock Renewables. Per management, Rimrock’s cattle operations could supply nearly half of the required feedstock for the HDRD facility in the form of tallow. While this project is likely several years away from providing a material amount of feedstock to Tidewater, it provides yet another long-term feedstock option for Tidewater. We believe the sustainable run-rate EBITDA for the HDRD plant is ~C$100-120mm, as TWM runs at nameplate capacity and opportunistically finds way to improve profitability with cheaper and lower-CI feedstocks.

Midstream assets: Outside of the refining complex, TWM also owns a collection of legacy midstream assets in the Deep Basin. The largest two assets are the Brazeau River Complex (“BRC”) and the Ram River gas processing and sulfur handling facility. BRC consists of a gas processing plant, gas gathering assets, gas storage assets, and a 10,000 bbl/d NGL fractionation and blending facility with truck-in, truck-out capabilities. The Ram River facility consists of a sour gas processing plant, sulfur forming and remelting facility, and sulfur unit trading loading station. Tidewater also owns several self-described non-core assets (smaller gas processing plants, ethane extraction facilities, rail terminals, oil batteries, etc.) across the Deep Basin. Historically, TWM’s midstream assets have collectively generated C$45-50mm in EBITDA annually. While short-term production curtailments due to low Canadian gas price and a turnaround at BRC may create a ~C$10mm headwind in 2024, the new management team has already identified C$6mm of run-rate operating cost synergies within the midstream asset base. We would note that much of the drilling activity around TWM’s midstream footprint is driven by NGL/liquids economics as opposed to dry gas. By 2025, TWM’s midstream asset base should be able to sustainably generate C$51-56mm of EBITDA annually.

SAF (sustainable aviation fuel): Tidewater is conducting a feasibility study, fully funded by the BC government in the form of BC LCFS credits, to potentially build a 6,500 barrel per day sustainable aviation fuel facility in the province. The potential project is a 50/50 joint venture between TWM and the Tidewater Renewables subsidiary. On the latest earnings call, Tidewater said it was considering either funding the project in-house or bringing in a partner to help offset the build. We expect the feasibility study to be cash flow neutral to TWM and the company plans to reach a final investment decision in mid-2025. Currently, SAF unit economics are superior to renewable diesel economics, as SAF volumes sell for a huge premium to jet fuel in most markets. The key component of the SAF plan is that it will only be constructed if management secures commercial offtake agreements with counterparties to de-risk the economics. We view this idea as a free call option in that the plant only gets built if doing so makes a lot of sense from an economic perspective. While an investor receives this option for free, we think it’s actually worth quite a bit: the plant discussed could generate C$250mm+ of EBITDA annually with a significant portion of construction costs funded by BC tax credits.

Valuation:

We estimate that the sustainable after-tax free cash flow potential is ~C$46mm annually for deconsolidated TWM (midstream assets and petroleum refining) and ~C$118mm at the renewables subsidiary annually. Given TWM’s ownership in LCFS, that equates to ~C$123mm of levered free cash flow attributable to TWM shareholders and ~C$1.0 billion of TWM equity value (~C$2.35/share) assuming an 8x FCF multiple (12.5% FCF yield). We use an 8x multiple on levered free cash flow because TWM’s assets operate in a local monopoly and hence exhibit much, much lower variability in cash flow than seen in other refining markets. The use of the term “sustainable” in the cash flow metric just means that we are accruing for 4-year refinery turnarounds in the maintenance capex. Given the significant turnarounds undertaken by TWM in 2023, actual cash flow 2025 should be significantly higher given very low maintenance capex required until the next refinery turnarounds in 2027. To sanity check our 8x free cash flow multiple, we examined two other renewable fuel peers, Neste (NESTE FH) and Calumet (CLMT US). Neste trades at ~17x 2024E and ~12x 2025E free cash flow to equity based on Bloomberg estimates. Calumet, which carries a heavy debt burden, is forecasted to generate negative free cash flow in 2024 and trades at ~17x free cash flow to equity on 2025 estimates. Our stylized valuation also assumes a C$425 LCFS price; this is a cost incurred by TWM and a profit stream recognized by the renewables subsidiary. A lower LCFS credit price as seen in other markets like California would just shift the economics in favor of TWM, with a lower cash flow at the renewables subsidiary offset by higher cash flow at the parent. However, we also think that a common-sense approach would be to collapse this corporate structure at some point in the future, likely with TWM tendering for the minority interest in the renewables subsidiary.

1. LCFS diluted shares outstanding includes the impact from warrants based on treasury stock method; TWM ownership in LCFS on a fully diluted basis is ~65.5%. 

2. TWM diluted shares outstanding assumes TWM repurchases ~27.5mm shares during 2024 under its previously announced NCIB.

Side note on debt: since the AltaGas shares received in the Pipestone transaction were not sold until January, the December 31 balance sheet has more TWM debt outstanding than will be the case on March 31, due to the sale of the shares, the repayment of the TWM credit facility, and the cash generated from inventory sales (cold-spec diesel). We would expect gross debt at TWM outstanding of ~C$75mm, with net debt likely a good bit lower. The Renewables subsidiary does still retain the HDRD unit construction financing (~$346mm of total debt currently non-recourse to TWM) but we would expect a very significant pace of debt paydown in 2024 and 2025 now that the HDRD unit is generating significant cash flow. Depending on the pace of share repurchases, the entire company could approach close to zero net debt outstanding by 2026, although the business is more than capable of operating with some leverage.

Addendum 1:  US refining bear case: TWM’s refining assets are very misunderstood. Many investors believe the Prince George Refinery is over-earning (like many US refineries are) and will soon become far less profitable. This assertion, while probably correct for many US refineries, is not applicable to Tidewater’s Prince George Refinery. In fact, the Prince George Refinery has been under-earning due to poor working capital management by the former management team. Cash flow generation in 2024 and beyond should exceed that of 2023.

Let’s start with the bear case on global refining assets. Refining is a highly competitive global market. Crack spreads, the difference between the price of a barrel of refined products less the cost of crude oil feedstock, is highly sensitive to global supply-demand imbalances. Since 2022, the global refining complex has been in a period of “overearning” with high crack spreads due to surprisingly strong global growth and multiple geopolitical conflicts reducing refined product supply. However, from 2024 to 2028, the world is expected to add ~4mm bbl/d of refining capacity, led by large-scale plant openings in Nigeria and Mexico. While this will represent just a 4% increase to global refining capacity, many expect demand growth to lag supply growth. What does it mean for refineries exposed to seaborne trade flows like the US Gulf Coast? Crack spreads should normalize down to pre-COVID levels and refineries will generate less free cash flow.

It would seem to make sense to apply the same logic to Tidewater’s Prince George Refinery. However, Prince George is protected from the volatility and competitiveness of the global refined products market for several reasons. First, Prince George is in a remote area of Canada at least an 8-hour drive away from any other potential alternative source of refined product. For refined products to flow from Edmonton to Prince George, they must travel 450 miles West (usually by truck) while navigating the Rocky Mountain Range.  Refined products imported by barge must land in either Vancouver or Prince Ruport (which have limited to zero excess import capacity) and then travel a similar distance by truck to Prince George. Furthermore, the Prince George Refinery is too small for any other major refiner to care about it. At 15,000 barrels per day of nameplate capacity, it represents less than 10% of British Columbia’s refined product demand and ~1% of Canada’s. Competing with Tidewater in the Northern BC market would not be a needle-mover from a cash flow standpoint for any of the larger Canadian refiners and it wouldn’t justify the logistical nightmare required to ship product to Prince George. In summary, Tidewater effectively has a monopoly on the Northern BC refined products market simply due to transportation distances / geography. Tidewater’s crack spreads have been consistently much higher and less volatile vs. an average refinery due to its insulation from the global refined products market.

Incidentally, the same factors that have resulted in stable petroleum refining margins in BC also apply to Tidewater’s HDRD operations. While there is also a near-term global oversupply of renewable diesel that has tanked California’s LCFS credit pricing, spare import capacity doesn’t exist for British Columbia to absorb the excess supply into the province. Also, the BC LCFS program requires that renewable fuels use Canadian sourced feedstock, which limits the universe of likely suppliers. Smaller US renewable diesel plants in Montana and Wyoming can afford to have Canadian canola shipped across the border to the US, process it into renewable diesel, and then ship it back to Canada; but logistically this is not a realistic option for US Gulf Coast refiners, let alone Asian or European based renewable diesel suppliers. Furthermore, BC fuel suppliers like Shell who import renewable diesel to satisfy their LCFS requirements have to back out some of their existing petroleum-based fuel sales in the province and sell them elsewhere (at lower net prices given transportation). Hence, the four main fuel retailers in BC only import US-based renewable diesel from 3rd parties in quantities sufficient to cover their LCFS obligations rather than displace their own product sales with excess imports.

Since 2021, Tidewater’s crack spreads at Prince George have increased from ~C$70/bbl to ~C$110/bbl back down to ~C$90/bbl. At first glance, one would assume Tidewater’s crack spreads should continue normalizing back down to ~C$70/bbl; however, the increasing BC LCFS burden pushes crack spreads higher every year. The program, modeled after a similar one in California, establishes a carbon intensity target for transport fuels that steadily reduces every year. Clean fuels that have carbon intensities below the target generate BC LCFS credits under the program. Fossil fuels, like petroleum gasoline and petroleum diesel, exceed the carbon intensity (“CI”) target and thus generate a deficit. Fuel suppliers like Tidewater must offset its total deficits each year by buying BC LCFS credits and/or blending clean fuels into its fuel supply. Credits trade in the open market and all credit transfer details are tracked monthly and published by the BC government. Because the CI target decreases every year, more credits must be purchased by fuel retailers every year to offset deficits. The cost burden of the BC LCFS program, which applies to every supplier selling fuel in BC, is largely passed through to the consumer in the form of higher crack spread and higher rack prices. The C$20/bbl net increase in crack spreads since 2021 can be explained by the increasing stringency and price increase of BC LCFS credits. The LCFS-adjusted crack spread (headline crack spread less LCFS compliance cost per barrel) has been relatively consistent for years.

In Q4 2023, TWM underperformed sellside expectations on EBITDA and free cash flow, largely due to working capital issues at the Prince George refinery. As the new management team outlined on the latest earnings call, Q4 2023 profitability was challenged due to an unseasonably warm winter and lower demand for cold-spec diesel, leaving TWM with significant excess refined product inventory at the end of the year. Cold-spec or winter diesel is required in northern climates to prevent gelling in extremely cold temperatures and is produced seasonally each Fall in geographies such as Canada. Prince George is located at 53.45 latitude, just south of Alaska. In fairness to management, one can understand their surprise at not seeing snowfall until nearly Christmas, but the end result was still a surprise inventory build and lower demand in the quarter. This excess inventory will be a tailwind in 1Q 2024 as TWM is opportunistically selling inventory into a more constructive market.

Addendum 2:  British Columbia import capacity constraints: An obvious challenge to the idea of import restrictions is the capacity of the Trans Mountain Pipeline (TMPL), which could theoretically supply the entire refined product import demand for BC given a headline capacity is 300,000 bbl/d. This challenge was in fact made and addressed during the 2019 BC provincial government review of market structure. To spare the reader the time of reviewing the entire ~200-page report, we will briefly address the topic here. The overwhelming majority of volume sent through the TMPL is crude oil that gets exported globally. This is largely due to the lack of westward-flowing pipeline infrastructure in Canada. TMPL is the only pipeline that transports both crude oil and refined products from Alberta to the West Coast, where it can be exported via tanker to global markets.

TMPL is a common carrier pipeline, meaning it doesn’t have customer-specific contracts with predetermined volumes. Instead, volumes are determined by a set of rules approved by the Canada Energy Regulator (“CER”). In the case of TMPL, these volumes are determined based on demand from both oil producers and refiners seeking to ship product on the pipeline. Every month, shippers submit a request stating the total volume they would like to send through the pipeline. The aggregate requested volume from all shippers is then apportioned based on available capacity.  The lion’s share of volume demand on TMPL comes from oil producers instead of refiners. Oil producers in Alberta can sell seaborne crude on the West Coast for a much higher price compared to crude traveling east to Ontario or US Midwest markets. On the other hand, refiners don’t benefit from nearly the same price premium by shipping West vs. East. As a result, ~85% of TMPL volume ends up being crude oil, which is highly likely to continue for the foreseeable future.

Catalyst

1.  Quarterly results and FCF generation, starting in Q1’24 and accelerating each quarter thereafter.

2.  Share repurchase program

3.  Debt paydown at renewables subsidiary