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What the Market's Missing on TransCanada

The company offers a compelling midstream opportunity and a strong dividend yield.

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We think investors are not seeing TransCanada’s big picture and are too narrowly focused on outside factors and temporarily higher leverage. If we use assumptions that reflect the market’s expectations-- lower Keystone utilization levels, lower revenue on natural gas pipelines associated with the FERC announcement, and higher dividend yield spreads compared with historical levels--we get a fair value estimate that approximates today’s share price. However, we think the market is overlooking what will be higher-than-expected utilization for the Keystone XL, dividend growth, the minor impact of the FERC’s proposed regulation on TransCanada, falling leverage, and the company’s natural gas portfolio.

A 5.1% dividend yield adds to TransCanada’s attractive valuation. We don’t think investors need to worry about a dividend cut. In fact, we forecast 9% annual dividend growth fueled by an impressive portfolio of growth projects. We expect the yield to increase to 6.8% if the stock appreciates at its cost of equity over the next five years, and we expect it to grow to 7.3% based on today’s investment price.

TransCanada has increased its dividend every year since it began paying one in 2000, and it can continue to do so without compromising its balance sheet. We expect distributable cash coverage, the ratio used by the company, to grow to 1.7 times from today’s 1.5 times despite continued investment in growth projects. Even after adjusting the distributable cash flow to include deferred taxes, we forecast a coverage ratio of approximately 1.3 times by 2022, rising from today’s 1.2.

We think TransCanada looks undervalued on a multiples basis as well. Since 2012, TransCanada’s stock has traded at an average enterprise value/forward EBITDA multiple of 12.1 times. At its current level, the stock is trading under 10 times, about a 20% discount to its long-term average. Our fair value estimate based on discounted cash flow approximates an implied EV/forward EBITDA multiple of 11 times, which is still a 10% discount to its long-term average. Given the company’s continued strong pipeline of growth projects, we believe that historical multiples are a relevant check to our primary valuation methodology.

Relative to the S&P/TSX index, TransCanada’s EV/EBITDA multiples have traded at a 19% premium since 2012. TransCanada’s multiple is currently trading at a 2% premium to the index, representing a significant departure from historical levels. Our fair value estimate approximates an implied multiple premium of 17% times relative to the index, which is in line with historical averages.

We believe numerous outside factors have led to the downturn in TransCanada’s stock. Each factor on its own has had a negative impact, but the perfect storm of the aggregated factors has led to the stock’s vast underperformance. However, we don’t believe these factors present significant long-term risks to TransCanada’s fundamentals. Below, we look at the factors that have weighed on the stock and what the market is missing for each.

Canadian Oil Price Woes Can't Keep the Keystone XL Down Canada desperately needs new pipeline infrastructure to move its crude into its primary market, the United States. Canada's supply continues to grow, but pipeline capacity has remained stagnant. We forecast an average of almost 400 thousand barrels a day of excess supply over pipeline capacity this year, and it will only get worse. Rail capacity is available to move excess supply, but operators have been hesitant to commit capacity as they stand to benefit from moving grain and know that crude producers will spurn them when pipeline space become available.

Consequently, the heavy oil discount has ballooned to a $26 per barrel average during the first quarter, well above its $13/bbl trailing three-year average. We see the widening of the differential as a headwind for oil sands production growth (lower realized prices dent cash flows and potentially threaten growth projects), and it raises concerns about the utilization of uncontracted capacity on the Keystone system when expansion projects are placed into service.

Despite the rise in the heavy oil discount, more Canadian production growth is coming. Canada’s oil sands hold the most potential for production growth. While production (bitumen and synthetic crude) from the oil sands is currently expensive, technological advancements--namely, solvent-assisted steam-assisted gravity drainage, or SA SAGD, methods--will help oil sands production compete with other major marginal sources of global supply. Solvent-assisted pilot projects have been underway for years and have meaningfully reduced operating costs (driven by reductions in energy usage) and capital costs, coupled with increases in oil quality and field recovery rates. Using this technology, we believe break-evens for the best in situ projects can fall to $45/bbl West Texas Intermediate by the end of the decade versus current levels of $50-$65/bbl WTI for traditional SAGD operations. We expect SA SAGD break-evens to be generally commensurate with U.S. shale break-evens ($55/bbl WTI).

Given our view on the improving cost structure associated with solvent-assisted technology, we think Canadian crude supply will be higher than many suppose. Our 2022 Canadian supply forecast is 5.5 million barrels a day, roughly 3% above the outlook from the International Energy Agency. While we expect solvent-assisted technology to have a major impact on the country’s supply growth, the biggest impact will come in the back half of the next decade when the technology is more widely implemented. We expect Canada’s crude oil supply to increase to 6.2 mmbbl/d within the next decade from 2017 levels of 4.6 mmbbl/d.

Canada has limited options as to where it can transport its crude oil supply because of its geography and location of its oil production. Refineries in western Canada don’t require use of the company’s limited pipeline infrastructure but have total refining capacity of only 730 mbbl/d compared with the country’s total 2017 supply of over 4.6 mmbbl/d. Outside the oil sands, crude demand in western Canada isn’t expected to grow significantly, which makes any new refineries unlikely. With ample refining capacity compared with its neighbor to the north, the United States is the chief market for Canada’s crude oil supply. Pipelines are the most common and preferred source of crude transportation--and in this low-oil-price environment, they’re the only real option to export the country’s supply.

In the current landscape, pipeline takeaway capacity out of western Canada approximates 4 mmbbl/d. However, because of tie-ins from the U.S. Bakken, capacity attributed to refined product transportation, operational downtime and maintenance, and other crude transportation mix, egress capacity for western Canada’s production approximates 3.4 mmbbl/d on these pipelines. Accordingly, current pipeline infrastructure is insufficient to support our expected supply growth.

Help Is on the Way for Producers Canada's producers and the government are aware of the country's future takeaway capacity bottleneck, and midstream companies have proposed numerous pipeline projects to alleviate the problem. However, these projects have fallen under strong opposition from the U.S. and Canadian governments, environmentalists, and aboriginal groups in Canada. Before the election of President Donald Trump, the outlook for new pipeline projects in the U.S. looked gloomy. Now the tides have turned, and TransCanada is in prime position to benefit with the Keystone XL. The 830 mbbl/d Keystone XL would originate in Hardisty, Alberta, and extend on a direct route to Steele City, Nebraska. Once in Nebraska, shipments will be moved to the U.S. Gulf Coast. The pipeline would add another alternative to extend oil sands production into the heavy oil preferred U.S. Gulf Coast and is expected to cost $8 billion.

The Keystone XL has been one of the most controversial pipeline proposals. The pipeline was shelved in 2016 after not receiving a federal permit from President Barack Obama but was revived with the election of Trump. Shortly after being sworn into office, Trump extended presidential approval for the project, and Nebraska issued the final approval of the Keystone XL in November 2017. TransCanada plans to begin construction in 2019. We expect the pipeline to come into service during the second half of 2021. Many still question whether the project has the contracts in place to support the economics, but concerns appear overblown.

Gulf Coast refineries also stand to benefit from pipeline expansion. These refineries have approximately 2 mmbbl/d of heavy oil refining capacity and have historically imported heavy crude from Mexico and Venezuela. However, because of underinvestment, political uncertainty, and escalating debt, Mexico and Venezuela have not been able to sustain production levels, and imports from those countries are down over 55% from their peak in 2005. The instability has left refiners scrambling to maximize light oil throughputs, which are less beneficial than heavy oil. Because of the complex nature of refining infrastructure, it’s not typical to toggle between crude types, so refiners in the Gulf Coast still have a strong demand for heavy oil despite the uptick in less expensive light oil production from U.S. shale.

As the door is closing on Mexico and Venezuela, it’s opening for Canada. Oil sands projects produce stable production levels, generally for 30 years, which makes them attractive receipts for Gulf Coast refiners. However, because of limited downstream pipeline capacity, Canada has not been able to take full advantage of the opportunity. The country exported less than 400 mbbl/d of crude oil into the Gulf Coast during 2017, leaving plenty of potential untapped. The Keystone XL would add significantly more takeaway capacity and allow the Gulf Coast to almost triple receipts.

Together, we expect the major pipeline growth projects (Keystone XL, Enbridge’s Mainline expansion, Line 3 Replacement, and Trans Mountain Expansion) to add 1.8 mmbbl/d of new pipeline capacity and be fully placed into service and operational by 2022. Before the pipelines are placed into service, we still expect growth from oil sands production. Oil sands operations are quite different from U.S. shale production. Most of the capital associated with oil sands projects is spent up front on infrastructure and heating the reservoir. Once production is up and running, it’s common to maintain steady production levels for more than 30 years with minimal capital commitments.

We don’t expect the lack of current pipeline capacity to discourage growth. Producers are aware that the current U.S. political environment holds the best opportunity for pipeline expansions and that oil sands expansion projects are long-term investment decisions. Accordingly, we don’t expect oil sands producers to allow near-term headwinds to derail the growth needed to support the new pipelines that will lock in long-term price economics. However, we expect continued pressure on the heavy oil discount in the near term. We believe producers will commit to medium-term rail contracts that will provide some relief until pipeline expansions are placed into service. Once the pipeline projects are placed into service, we expect the heavy oil discount to narrow to $17/bbl.

With nearly 1.8 mmbbl/d of new pipeline capacity from expansions, there is some uncertainty regarding the utilization of the Keystone system. But we expect the Keystone system to be fully utilized in the long term, with only a few quarters of minor underutilization. We expect western Canadian supply to increase by 1.7 mbbl/d over the next decade, with all pipelines fully utilized.

It’s true that the U.S. Gulf Coast holds the best opportunities for incremental production, but the U.S. Midwest provides producers with the highest netbacks. Producers can improve netbacks by as much as $8/bbl by shipping production to the U.S. Midwest as opposed to the Gulf Coast. The current Keystone system ships crude to both markets; when the Keystone XL is placed into service, it will serve solely the Gulf Coast, while the legacy system will serve the U.S. Midwest. With access to higher netbacks in the Midwest, there are concerns that the Keystone XL won’t be fully utilized. However, we don’t see a significant risk to TransCanada.

Under FERC regulations, pipelines can only contract 90% of their capacity, leaving the other 10% for spot capacity. Accordingly, the Keystone XL’s contracts are limited to approximately 750 mbbl/d of the 830 mbbl/d total capacity. TransCanada was successful in securing 500 mbbl/d of commitments and will also move 200 mbbl/d from the legacy system. With 700 mbbl/d of contracted capacity, the Keystone XL is almost fully contracted. That leaves more open spot capacity on the legacy system that serves the more attractively priced Midwest market. This strategic move allows TransCanada to position itself to have a leg up on Enbridge’s Line 3 replacement project. Line 3 will move incremental production to the Gulf Coast but does not contain any contracted capacity due to the nature of the Mainline’s status as a common carrier pipeline. The uncontracted portions of the Keystone system will be competing with Enbridge’s Mainline. Shippers will be motivated to move noncontracted supply into the U.S. Midwest on the Keystone first over Line 3’s Gulf Coast access.

While the legacy Keystone system can move noncontracted supply into the U.S. Midwest, questions remain about the utilization of spot capacity on the Keystone XL. Historically, pipelines have not operated at the total capacity because they move other products and portions of the pipelines may be unavailable for routine maintenance. In recent history, the legacy Keystone pipeline has operated at 95%, so we assume that the combined Keystone system will approximate the same utilization. Despite competition from Enbridge and the Trans Mountain expansion, we expect only a few quarters of minor underutilization from target levels on the combined Keystone system. We don’t expect the underutilization to be significant, with utilization ranging between 94% and 99% of targeted capacity over this period. Eventually the pipeline should operate at full targeted capacity and maximize returns on the project.

FERC Proposal Has Minimal Impact on TransCanada On March 15, the Federal Energy Regulatory Commission proposed a regulation that would disallow pipeline operators from recovering income taxes from shippers on natural gas and crude pipelines that operate under a cost-of-service contract structure. The announcement resulted in a big sell-off among pipeline operators.

But we don’t think the market understands the impact of the FERC’s proposed regulation on TransCanada. As of 2017, approximately half of TransCanada’s U.S. natural gas pipeline EBITDA, or CAD 900 million, came from assets with cost-of-service contracts. This represents only 13% of TransCanada’s 2017 total EBITDA. We expect this portion to fall approximately 5% to CAD 860 million in 2018, or 11% of 2018 expected EBITDA.

The company has CAD 10 billion in capital growth projects, none of which are expected to operate under a cost-of-service model. Once these assets are placed into service, we expect cost-of-service EBITDA affected by FERC policies to drop to 8% from 13% over the next five years, as the rest of TransCanada continues to grow.

Rising Interest Rates a Headwind, but Dividend Deserves More Credit Historically, rising interest rates have served as headwinds for high yielders like midstream energy stocks. Investors sell out of high-yielding stocks for yields that are deemed to be safer, which they can find in U.S. Treasuries. Over the past 30 years, TransCanada's stock has demonstrated an inverse relationship with the U.S. 10-year Treasury yield. The data supports this negative relationship with a correlation coefficient of negative 0.85 and a r-squared coefficient of 0.72.

The past six months have not been any different. U.S. 10-year Treasury rates have risen 40%, while TransCanada’s stock has faltered. The inverse correlation is similar to the long-term trend but contains even stronger statistics. The data supports this negative relationship with a correlation coefficient of negative 0.90 and a r-squared coefficient of 0.80.

However, the market doesn’t seem to realize the value of TransCanada’s dividend. Over the past decade, TransCanada’s yield averaged a 1.8% spread to the 10-year yield, but the spread currently sits at 2.5%, or a 40% premium to the historical average. Over that time, TransCanada’s forward yield averaged 4.3%. TransCanada’s current yield represents a 25% premium to its historical average.

We expect TransCanada to meet its dividend growth target of 8%-10% over the next three years, and we forecast a 2020 dividend of CAD 3.28 per share. The company’s recent commitment to dividend growth coupled with the falling stock price has pushed the yield well above its historical average. Given the plethora of attractive growth projects, we expect distributable cash flow to triple and the associated coverage ratio to exceed the three-year trailing average when these projects are fully operational.

Once the growth projects are placed into service, we think the dividend will normalize, but we expect a premium to the historical yield to reflect the new levels of growth. When we apply the historical spread of 1.8% to the current 10-year yield of 2.8%, we calculate a 4.6% dividend yield, which stands at a 15% discount to the current yield and almost 10% above the historical yield. The 4.6% yield supports a slight premium to our fair value estimate.

High Leverage Is Only Temporary TransCanada's leverage is another red flag for investors. It has spiked over the past couple of years, resulting from the additional obligations to fund the capital expenditures associated with the current investment cycle and the Columbia Pipeline Group acquisition. We expect TransCanada's 2018 trailing 12-month net debt/EBITDA to approximate 6.2 times, the highest among its peers.

But current levels don’t look alarming because the industry is investing in growth projects. 2017 capital expenditures were more than double 2014 levels, and we expect them to increase over the next three years as TransCanada undertakes attractive growth projects. These projects contain contract terms that range from 10 to 107 years with returns on invested capital that range from 7% to 10%, exceeding our forecast cost of capital of 6.1%. Rising interest rates shouldn’t have a meaningful impact on TransCanada, as approximately 90% of the company’s debt is fixed rate. Once the investment cycle passes and the projects are placed into service, we expect a meaningful drop in leverage. We forecast leverage to drop to 2.8 times net debt/trailing EBITDA by the end of the next decade.

Don't Forget Natural Gas Natural gas pipes have long been TransCanada's bread and butter. The Nova Gas Transmission Line and Mainline systems operate 75% of Canadian takeaway capacity, while U.S. infrastructure is positioned around the Marcellus, Utica, Bakken, and Gulf Coast. Many questions surround the future of Canadian natural gas, with Canadian production at 10-year highs and growing competition from the U.S. However, TransCanada's infrastructure contains solid, long-term contracts and is positioned to take advantage of both Canadian and U.S. supply growth along with growing consumption in the U.S. and Mexico and from the oil sands.

Despite the attention on the Keystone XL, 65% of TransCanada’s CAD 32 billion growth portfolio consists of natural gas pipelines. Combined, we expect natural gas projects to contribute CAD 2.8 billion in annual incremental EBITDA once fully placed into service.

We expect half of the natural gas pipeline growth to come in the U.S., primarily in the east region. TransCanada is positioned to take advantage of prime production growth there. The U.S. Energy Information Administration expects a significant uptick in natural gas production in the lower 48 U.S. states, approximating 36% growth over the next decade. The EIA expects 65% of that growth to come from the east region.

Supply growth in the U.S. will be met with growing demand from the U.S. and Mexico. The EIA expects U.S. consumption to increase by more than 8 billion cubic feet per day by 2030. Additionally, excess U.S. supply can be moved to Mexico, where TransCanada has diversified its operations. These pipelines represent only 15% of the natural gas growth portfolio, but they are some of the most lucrative. These projects carry 10% returns on invested capital and 25-year take-or-pay contracts.

AECO prices reached five year-lows during 2017 and aren’t trading much higher currently. The lack of takeaway capacity from Alberta has been the driving force, and with prices so low, additional infrastructure is needed more than ever. TransCanada’s NGTL is the premier takeaway pipeline from the region, with 75% of the region’s takeaway capacity. Through the NGTL, gas is transported to the U.S. West Coast, the Dawn storage hub, the U.S. Midwest, and the oil sands. Natural gas production in the region is expected to sharply rise over the next decade, growing at a 3.5% rate. TransCanada has CAD 7.2 billion in planned NGTL expansions, which aim to provide relief for producers. Also, increased oil sands production will require increased natural gas use. We expect oil sands producers to need almost 1 bcf/d of incremental natural gas over the next decade, representing a 4.3% compound annual growth rate. TransCanada’s proposed growth projects are positioned to meet these needs along with the needs of the U.S. and Mexico.

Narrow Moat Protects TransCanada's Network Midstream companies transport and process hydrocarbons. Once a transport route is established, there's usually little need to build a competing route. Doing so would drive returns for both routes below the cost of capital. Thus, pipelines are generally moaty because they efficiently serve markets of limited size.

New pipelines are typically constructed to allow shippers or producers to take advantage of large price differentials (basis differentials) between two market hubs because supply and demand is out of balance in both markets. Pipeline operators will enter into long-term contracts with shippers to recover the project’s construction and development costs in exchange for a reasonable tariff that allows a shipper to capture a profitable differential, and capacity will be added until it is no longer profitable to do so.

Pipelines are approved by regulators only when there is an economic need, and pipeline development takes about three years, according to the EIA. Regulatory oversight is provided by the FERC, National Energy Board, and at the state, provincial, and local levels for cross-border Canadian pipelines. New pipelines under consideration must contend with onerous environmental and other permitting issues. Further, project economics are locked in through long-term contracts with producers before breaking ground on the project. If contracts cannot be secured, the pipeline will not be built.

A network of pipelines serving multiple end markets and supplied by multiple regions is typically more valuable than a scattered collection of assets. A pipeline network allows the midstream company to optimize the flow of hydrocarbons across the system and capture geographic differentials, use storage facilities to capture price differentials over time, and direct more hydrocarbons through its system via storage and gathering and processing assets, ensuring security of flows and higher fees. Finally, it is typically cheaper for an incumbent pipeline to add capacity via compression, pumps, or a parallel line than it would be for a competitor to build a competing line.

Top-Tier Asset Quality The major consideration for assessing evidence of a moat for a midstream company is asset quality, where we consider the company's competitive strengths and assets in the efficient scale regional markets it serves. Asset quality is evaluated based on the location of the individual assets, the type of asset (for example, pipeline versus gathering and processing), the cost-competitiveness of the basins the assets serve, capital intensity, and the overall quality of the network. Basin cost-competitiveness is important as pipelines are likely to remain relevant longer if connected to a low-cost hydrocarbon supply. Some of the highest-quality midstream companies have a dense network of assets that connect to key refineries, basins, and market hubs and are reliable transportation providers for shippers. This connectivity encourages shippers to use the pipelines but also protects the midstream entity. The asset integration prevents another third party from extracting rents by owning an asset that is part of the route to the most profitable market.

TransCanada’s assets are among the best in the North American midstream sector. The crown jewels of its portfolio are the NGTL and Mainline natural gas pipelines and the Keystone crude pipeline. The natural gas pipelines transport natural gas from the Western Canada Sedimentary Basin into the oil sands and the U.S. Canada has limited takeaway capacity and excess gas supply, which is why we’ve seen a downward trend in AECO prices. The NGTL and Mainline systems operate 75% of the takeaway capacity, and the industry would crumble without the infrastructure.

The Keystone is the second-largest crude pipe and is essential to the Canadian crude industry. It delivers crude to the two principal U.S. markets: Gulf Coast and Midwest. With crude supply growing in western Canada, the Keystone is needed more now than ever. In addition to these premium assets, TransCanada operates U.S. natural gas pipelines in the fast-growing Marcellus and Utica regions of the U.S. and Mexican pipelines that bring much-needed gas to Mexico.

Solid Contract Quality Contract quality is primarily assessed by term, with long-term contracts (10-plus years) being preferred with take-or-pay provisions. Contract quality does not directly support the efficient scale moat source, but it more directly speaks to the sustainability of future excess returns. Entities that are primarily oriented around pipelines are the strongest positioned as they obtain the longest terms. Long-term contracts for pipelines tend to be made up mostly of capacity reservation fees and a more modest transportation fee. Shippers are obligated to use the pipeline but not required to do so; however, they must pay the reservation charges in any scenario, ensuring rents for the pipelines. The smaller transportation fees are only paid based on actual volumes shipped. Less well-positioned companies typically contain a large component of gathering and processing, storage, fractionation, or other business areas, where it is harder to argue that advantages will persist for two decades or more, and contract terms tend to be only a few years, reflecting the reduced barriers to entry compared with pipelines.

TransCanada’s assets also possess solid contract quality. Existing NGTL and Mainline pipelines are fully contracted with take-or-pay contracts that have 10-year average terms. The Keystone has a remaining term of 13 years on its initial 20-year contract on its take-or-pay contract and is fully contracted to maximum allowable amount, 90% of capacity. Each of the projects in Mexico is underpinned by 25-year take-or-pay agreements with Mexican state-owned agencies, ensuring that project and capital costs and an attractive return are recovered. While the contracts are solid and lock in attractive economics for more than 10 years, they are not best in class. We would like to see the average remaining terms on the existing assets exceed 20 years, which is why we conclude that TransCanada has a narrow instead of wide moat.

Growth Projects Reinforce the Moat Extensive regulatory oversight of TransCanada's assets acts as barrier for new entrants, with many federal, state, and local agencies involved in permitting, siting, and rate-setting activities. Regulators in Canada, the U.S., and Mexico permit TransCanada to recover costs to operate pipeline networks by collecting tolls for services. Tolls include the recovery of the pipeline's investment, a rate of return on the investment, and pipeline operating costs. The regulatory oversight provides stability in returns that typically exceed TransCanada's cost of capital.

TransCanada’s growth portfolio contains premier assets with top-tier contract quality. The portfolio contains over CAD 7 billion in much-needed NGTL expansion projects, the Keystone XL, and high-quality Mexico and U.S. natural gas pipelines. What’s more impressive is the long-term take-or-pay contracts that range from 15 years to over a century.

In addition, the returns on these projects are a function of both the location and long-term contract structure of the assets. The company generates annual ROICs on new projects that range from 7% to 10%, compared with its cost of capital, which approximates 6.1%.

The combination of top-tier asset and contract quality, regulatory protection on existing pipelines, attractive near-term and long-term pipeline projects, and a vast, diverse pipeline network allows TransCanada to realize efficient scale on its pipeline economics and generate sustainable excess ROICs.

TransCanada has undergone significant growth and capital spending in the past half decade, which has hampered returns. But with growth and capital spending expected to slow after the current portfolio is placed into service, investors should see the company generate significant economic profit in the next decade. We forecast ROICs to exceed TransCanada’s WACC by over 50%. Even in our bear case, we still expect TransCanada to generate economic profit.

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About the Author

Joe Gemino

Senior Equity Analyst
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Joe Gemino, CPA, is a senior equity analyst for Morningstar Research Services LLC, a wholly owned subsidiary of Morningstar, Inc.. He covers Canadian oil and gas companies.

Before joining Morningstar in 2015, Gemino held equity analyst roles for Goldman Sachs and Gate City Capital Management. Before business school, he was a technical accountant for Citigroup and Northern Trust.

Gemino holds a bachelor’s degree and a master’s degree in accountancy from the University of Notre Dame along with a master’s degree in business administration from the University of Chicago Booth School of Business. He holds the Certified Public Accountant designation.

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