ENERGY INFRASTRUCTURE | 1Q 2018 The Continued U.S. Energy .../media... · documentaries such as the...

The Continued U.S. Energy Renaissance and Infrastructure Build-Out: Capturing the Reenergizing of America with MLP Investing

ENERGY INFR ASTRUCTURE | 1Q 2018

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Over the last decade, the unforeseen production growth experienced within the continental U.S. has radically changed the energy landscape, domestically and abroad, and pushed the U.S. towards energy independence. From 2000 to 2008, U.S. crude oil production went from 5.8 million barrels per day ("bopd") to 5.0 million bopd a steady decline of approximately 14%. It was during this time that people began to talk about “peak oil,” a concept that gained enough traction to inspire award-winning documentaries such as the 2006 documentary A Crude Awakening: The Oil Crash; We’re Running Out and We Don’t Have a Plan. Then from 2008 to the end of 2014, as a result of technological breakthroughs that unlocked production from vast unconventional “tight oil” reservoirs, U.S. crude oil production went from 5.0 million bopd to 9.3 million bopd—a staggering increase of 86% in just six years. New infrastructure was, and is still, needed to gather; process; treat; store; and transport the vast new supply of natural resources. Connecting this new supply to the final customer requires midstream infrastructure, the majority of which is being built by Midstream Master Limited Partnerships (“MLPs”). Midstream companies are

generally engaged in the treatment, gathering, processing, and transportation, among other activities of natural gas, NGLs, crude oil, refined products or coal.

Since Summer of 2014, the discussion over the last 24 months has centered on the plunge in the price of crude oil and the aftershocks for the U.S. oil and gas industry. Namely, how will producers adapt to lower crude prices? A similar story has played out before with natural gas and natural gas liquids (“NGLs”). Going back to September 2005, domestic natural gas prices had fallen by more than 70% while production increased by ~65%, as seen in Figure 1. How is that possible? Natural gas producers did this by increasing production in the most cost-effective regions through ever-increasing efficiency at the expense of field service providers. While the price of natural gas dropped significantly from 2007-2009, the price for NGLs remained high due to their historical link with crude. Like natural gas, continued drilling eventually created tremendous supply growth (>70% growth from 2005 to 2012) that finally oversaturated the market in early 2012, causing prices to crash more than 50%.

F I G U R E 1 : N AT U R A L G A S P R O D U C T I O N A N D P R I C E S S I N C E J A N U A R Y 2 0 0 0

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…EVENTUALLY CREATING

IMBALANCE THAT PUSHED

PRICES >$80/BBL

…CAUSING PRICES

TO PLUMMET ~40%

SHALE REVOLUTION RESULTED

IN >70% GROWTH...

OIL PRODUCTION DECREASED BY 4%

FROM 2000-2010…

…. EVENTUALLY CREATING

AN IMBALANCE THAT PUSHED

PRICES >$10/MCF

…CAUSING PRICES TO PLUMMET >70%


IN ~65% GROWTH…

GAS PRODUCTION DECREASED BY 15%

FROM 2000-2005….

Source: Energy Information Agency (EIA) as of October 31, 2017. Bcf/d: billion cubic feet of gas per day. $/MCF: Thousand cubic feet of gas.

THE CONTINUED US ENERGY RENAISSANCE AND INFRASTRUCTURE BUILD-OUT: CAPTURING THE REENERGIZING OF AMERICA WITH MLP INVESTING 2

We have observed the same phenomenon with crude oil producers. As U.S. crude producers were incentivized to drill with oil prices greater than $100/bbl, production increased by >60% to almost nine million bopd causing crude prices to plummet ~50% in the second half of 2014 after OPEC decided not to cut production in an already oversup plied market (primarily due to the US increasing production by ~4 Mbpd in just five years’ time).

In March of 2016, the U.S. Energy Information Association (“EIA”) released their annual “Trends in U.S. Oil and Natural Gas Upstream Costs”, which shows that for 2015 the average well drilling and completion costs were 25%-30% below 2012 levels. Per the report, “The oil price collapse of 2014 forced changes upon the market, including capital cost reductions, downsized budgets and focus on better prospects within these plays.” Upstream producers have buckled down and focused on the most economic projects and reduced operating costs;

and today rig counts in the U.S. are on the rise. For the calendar year 2017, the U.S. oil rig count increased by ~40%, even as prices remained volatile.

We believe underlying oil and gas supply fundamentals continue to improve and each quarter we get closer to a supply-demand equilibrium. U.S. oil and gas production is a crucial component of the global oil and gas market and, we believe, it will continue to be over the foreseeable future. This requires continued investment along the value chain, especially in midstream – the key link between supply basins and end users. Yes, it is true that some areas of the U.S. are completely built out and do not require any additional material capital expenditures. However we continue to see a myriad of opportunities where midstream infrastructure can meet growing demand and continue to improve netbacks1 to producers, ultimately lowering the cost of energy, both domestically and abroad.

F I G U R E 2 : C R U D E O I L P R O D U C T I O N A N D P R I C E S S I N C E J A N U A R Y 2 0 0 0

PR E -SH A L E P OS T-SH A L E

Average Daily Production (MMBbl/d) $/Bbl Average Daily Production (MMBbl/d) $/Bbl

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…EVENTUALLY CREATING

IMBALANCE THAT PUSHED

PRICES >$80/BBL

…CAUSING PRICES

TO PLUMMET ~40%


IN >70% GROWTH...

OIL PRODUCTION DECREASED BY 4%

FROM 2000-2010…

…. EVENTUALLY CREATING

AN IMBALANCE THAT PUSHED

PRICES >$10/MCF

…CAUSING PRICES TO PLUMMET >70%


IN ~65% GROWTH…

GAS PRODUCTION DECREASED BY 15%

FROM 2000-2005….

Source: EIA as of October 31, 2017. MMBbld/d: million barrels per day. $ / Bbl: $ per barrel


T H E O P P O R T U N I T Y S T I L L A H E A D

With the growth of energy production over the past decade, the U.S. has witnessed robust increases in energy infrastructure capital expenditure (“capex”). See Figure 3. These infrastructure projects come in all shapes and sizes – from multi-billion dollar Liquefied Natural Gas (“LNG”) export facilities to small gathering and processing systems in the Permian Basin. All are important and play a crucial role in increasing efficiencies along the energy value chain and making the U.S. a competitive player in the global crude market.

The need for capital is diverse: by region (Midwest, Northeast, Southeast, West Coast, Rockies, Gulf Coast); by commodity (crude, natural gas, natural gas liquids); and by asset (e.g., gathering, long-haul pipes, processing, fractionation, LNG, shipping). We believe that MLPs, in particular, are the entities best positioned to capitalize on this tremendous infrastructure build out because of their cheap cost of capital and tax-advantaged corporate structure.

After all the news surrounding the collapse in global oil prices, an April 2016 report released by the Interstate Natural Gas Association of America (“INGAA”) Foundation estimates that over $500 billion in crude, gas and NGL infrastructure will be needed through 2035. The focus of that infrastructure build out has shifted from the source of the hydrocarbon to the use of that hydrocarbon.

Domestically, we continue to see significant bottlenecks that result in price spikes during high-demand periods, such as the one seen recently in the southeast. In early September 2016, a massive leak was discovered in the Colonial Pipeline – the main conduit for transporting gasoline from Gulf Coast refineries to consumers along the Atlantic. As a result, gasoline prices skyrocketed (16 cents above the national average) across the southeast due to the lack of other supply options. Midstream projects can help alleviate such price dislocations by providing low cost optionality and reliability to end users.

Looking at natural gas and NGLs – where ~70% of the aforementioned $500 billion will be invested – years of depressed prices have funneled directly to increased demand. Additional pipeline capacity is needed to service the demand of the petrochemical and utility sectors for their necessary feedstocks. In addition, the pricing outlook and global spreads continue to incentivize natural gas exports through the newly constructed LNG facilities. Ethane and Liquefied Petroleum Gas (propane and butane) exports from the petrochemical industry (which has never existed before) will also need associated pipelines, terminals and storage facilities. For the U.S. to realize its full potential as a low-cost energy source – significant infrastructure investment remains a high priority.

F I G U R E 3 : H I S T O R I C A L A N D F O R E C A S T O R G A N I C M I D S T R E A M C A P I TA L E X P E N D I T U R E S ( “ C A P E X ” ) C-Corp Organic Capex MLP Organic Capex Total Capex

Note: Figures reflect Wells Fargo coverage universe only. Source: Wells Fargo estimates as of December 31, 2016.

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2020E2019E2018E2017E201620152014201320122011201020092008200720062005

FIVE-YEAR HISTORICAL AVERAGE (2011-2015)


F U E L I N G T H E C O N T I N U E D I N F R A S T R U C T U R E B U I L D O U T …

The below drivers are underpinning the continued build-out of U.S. energy infrastructure assets.

1. Global Exports and Expanding Markets: Today, the U.S. is the world’s largest producer of natural gas. While historically natural gas was a domestic market, the U.S. is now expected to be a net exporter of natural gas and NGLs by 2018. Due to the rapid increase in the domestic supply of natural gas, the U.S. experienced a major wave of LNG export terminal planning and construction to capitalize on global demand. With Sabine Pass, the first LNG facility on the Gulf Coast that opened in 2016, U.S. LNG exports are expected to grow to 2.5 trillion cubic feet (“tcf”) in 2020. These facilities will continue to require efficient feedstock logistics to be able to remain profitable in the current competitive global marketplace. Closer to home, the U.S. continues to ramp up natural gas pipeline exports to Mexico. Mexican natural gas production has been gradually decreasing for the last seven years while consumption continues to increase, particularly in the industrial and utility sector. Mexico’s national energy ministry, SENER, projects that U.S. natural gas pipeline exports will reach 3.8 billion cubic feet per day (“bcf/d”) by 2018 – more than double the amount seen in 2013.

2. The Resurgent Petrochemical Industry: Before the shale boom, the U.S. did not have significant NGL production and, most large petrochemical companies were moving offshore, closer to NGL sources. India, Brazil, Trinidad and the Middle East all became increasingly in favor to both multinational and U.S. petrochemical companies. New extraction techniques, however, have allowed U.S. producers to drill significant wet gas reserves that are rich in NGLs. This new NGL supply has directed much of the petrochemical investment to the U.S., where companies can rely on more stable fiscal framework and a more extensive infrastructure network. In response to abundant ethane supply, several corporations have approved or are currently constructing massive new Ethane cracking petrochemical complexes along the Gulf Coast and across the U.S. (see Figure 4) – projects dubbed “world scale crackers.” These crackers often carry multibillion dollar price tags and with two to three year or longer construction times, convert cheap ethane into ethylene and are currently expected to increase ethane demand by over 500 thousand barrels a day (“mpbd”) by the end of 2019. These new facilities will require pipelines to supply the feedstock and to ultimately deliver the processed goods to the end-user.

F I G U R E 4 : U . S . P L A N N E D ( N E W A N D E X P A N D E D ) E T H A N E C R A C K E R S COMPANY: NEW CRACKERS ETHANE CAPACITY, TONNES/YEAR LOCATION START-UP

Chevron Phillips Chemical 1.5 million Cedar Bayou, Texas Mid-Late 2017

ExxonMobil Chemical 1.5 million Baytown, Texas Late 2016

Dow Chemical 1.5 million Freeport, Texas 2017

Sasol 1.5 million Lake Charles, Louisiana 2017

Formosa Plastics 1.0 million Point Comfort, Texas Q1 2017

Formosa Plastics 1.2 million Louisiana Not given

Occidental Chemical/Mexichem 544,000 Ingleside, Texas 2017

Axiall/Partner Not given Louisiana 2018

Shell Chemical Not given Monaca, Pennsylvania Not given

Odebrecht Not given Wood County, West Virginia Not given

COMPANY: EXPANSIONS ETHANE CAPACITY, TONNES/YEAR LOCATION START-UPINEOS 115,000 Chocolate Bayou, Texas 2014Williams Partners 273,000 Geismar, Louisiana April 2014Westlake Chemical 82,000 Calvert City, Kentucky Q2 2014LyondellBasell 363,000 La Porte, Texas Mid 2014Chevron Phillips Chemical 91,000 Sweeny, Texas 2014Westlake Chemical 113,000 Lake Charles, Louisiana 2014LyondellBasell 113,000 Channelview, Texas 2015LyondellBasell 363,000 Corpus Chrisit, Texas Late 2015Huntsman 19,300 Port Arthur, Texas N/ABASF Fina Petrochemicals N/A Port Arthur, Texas 2014

Source: Companies, ICIS analysis as of December 31, 2017.


3. Shifting Utility Sector Dynamics: America’s dominant electricity sources have historically been coal, nuclear and natural gas, in that order. The risks of both nuclear and coal are well known around the globe. With recent nuclear incidents and the heavy environmental taxes on coal, the traditional heavyweight sources of electricity are consistently being replaced by cleaner, safer natural gas. Accounting for over 52% of electricity generation as recently as 2000, today coal accounts for ~30% of total electricity output. This number is widely expected to continue its downward trend. In 2000, Natural Gas accounted for just 16% of total U.S. electricity production, as of 2016 it represented almost 35%. Motivated by its abundance and decreasing costs, companies are willing to build new infrastructure to bring natural gas to power plants. With the vast supplies coming to market, natural gas seems poised to take an ever-more prominent role in the production of U.S. electricity. Transportation is key with electricity switching though; natural gas needs to be brought to the centers of demand, densely populated areas, which will require natural gas pipelines directly tied to demand centers. (i.e. not dependent on commodity prices).

4. Refinery Landscape Transformation: The geographical locations of new supply basins are reshaping America’s historical refinery landscape. Long stagnant due to prohibitions and lack of permits, the refinery picture was set 45 years ago and that system was built to service yesterday’s energy realities. This meant refineries designed to process the heavy crude originating from the Middle East, Mexico and South America were built along the Gulf Coast. The refineries built in the Northeast were designed to process light sweet crude originating from the “Brent (North) Sea” and finally the West Coast refineries were built to process both light and heavy crudes. There has been a significant change in the locations of supply over the past decade; heavy crude which is needed for the Gulf Coast refineries is now coming from Canada and the light sweet that the coastal refineries require is originating in North Dakota and Texas. Refineries, however, are cost prohibitive to convert and permits to construct new or relocate are non-existent (a new refinery has not been constructed in the United States in over 35 years!) This means the energy transportation network must be significantly expanded and re-routed to bring the proper sources of crude to the refineries that can process them – from Texas and North Dakota to the East and West coasts and from Canada down to the Gulf Coast. The infrastructure needed by refineries is not dependent on commodity prices – a fact the market tends to overlook. Demand-oriented assets, such as these, can actually do better in a low commodity price environment since low prices tend to stimulate demand.

COAL30.3%

OTHER8.8%

NUCLEAR 19.6%

HYDROELECTRIC6.6%

COAL51.9%

OTHER5.1%

NUCLEAR 15.9%

HYDROELECTRIC7.3%

NATURAL GAS19.9%

NATURAL GAS 34.8%

COAL30.3%

OTHER8.8%

NUCLEAR 19.6%

HYDROELECTRIC6.6%

COAL51.9%

OTHER5.1%

NUCLEAR 15.9%

HYDROELECTRIC7.3%

NATURAL GAS19.9%

NATURAL GAS 34.8%

E L E C T R I C T Y G E N E R AT I O N B Y S O U R C E – 2 0 0 0

E L E C T R I C I T Y G E N E R AT I O N B Y S O U R C E – 2 0 16

Source: EIA as of December 31, 2016.


5. New Supply Basins: While producers may have temporarily cut back on the exploration side of the business, the proliferation of new supply basins has been essential to recent production growth. Advancements in technology and Exploration & Production (“E&P”) efficiencies continue to lower breakeven costs around the country and have led to new reserve discoveries, such as the SCOOP/STACK and the Alpine High. The SCOOP / STACK play (oil field) in Oklahoma has been generating buzz for the large amount of potential liquid resources. In September 2016 Apache Corporation (NYSE: APA), an E&P company, announced the discovery of “Alpine High” a potential large, low cost, organic resource play in the western part of the Permian basin. New discoveries like the ones mentioned above will require new gathering and processing systems and long haul takeaway capacity.

M L P S : S T I L L L E A D I N G T H E B U I L D O U T

We expect that the five drivers mentioned above will support the continuation of the necessary infrastructure build-out. In the last decade alone ~$200 billion of capital investment has been made in energy infrastructure and the INGAA study projects that over $500 billion will be needed through 2035. This infrastructure build-out has been, and we expect will be led by MLPs. Historically, MLPs primarily acquired existing infrastructure assets from other companies which transitioned these assets into the tax-advantaged MLP status. That has changed significantly in the past decade. Much of the future capital expenditures will take place at the MLP or MLP affiliate level, which in turn will drive new asset development, increased cash flow generated by those assets, and ultimately the potential for distribution growth to investors. To put the magnitude of such spending into context, if only 50% of the estimated required capital is spent at the MLP level, or $250 billion, that equates to roughly 80% of the market capitalization of the Alerian MLP index.2 This should translate into continued top-tier growth well beyond the next ten years.

To remind us why we believe MLPs are essential to the continuing build-out, it is important to remember that MLPs are companies that by law must have 90% of their asset base producing revenue from the transportation, storage and/or treatment of a natural resource. Due to the tax structure of the vehicles, MLPs must distribute a majority of their distributable cash flow to unitholders. With the U.S. economy stuck in a tepid recovery, the drivers underpinning the infrastructure development and accompanying MLP growth are not dependent on increased aggregate U.S. economic activity. The projected investment growth of the asset class, coupled with the relatively low correlation to total economic activity, highlights the compelling nature of the investment thesis and the sector as an attractive option.

O U R O U T L O O K : S A F E T Y F I R S T

As we have stressed repeatedly, every MLP is different and requires its own analysis. Investors will need to understand distribution risk, the way contracts are structured and the manner in which cash flows are generated. We feel low leverage, consistent distribution growth supported by long-term, fee-based contracts that could bring dependable cash flows is the most attractive way to invest. In the face of the Energy Renaissance and accompanying infrastructure build-out, skillful active management by seasoned operators may assist investors in capitalizing on these exciting developments for the coming decade and beyond.


BROOKFIELD INVESTMENT FUNDS ARE DISTRIBUTED BY QUASAR DISTRIBUTORS, LLC. INVESTMENT PRODUCTS: NOT FDIC INSURED | MAY LOSE VALUE | NOT BANK GUARANTEED brookfield.com | [email protected]

R I S K A N D O T H E R D I S C L O S U R E S :

Must be preceded or accompanied by a prospectus.Mutual fund investing involves risk. Principal loss is possible. Investing in MLPs involves additional risks as compared to the risks of investing in common stock, including risks related to cash flow, dilution and voting rights. The Fund’s investments are concentrated in the energy infrastructure industry with an emphasis on securities issued by MLPs, which may increase volatility. Energy infrastructure companies are subject to risks specific to the industry such as fluctuations in commodity prices, reduced volumes of natural gas or other energy commodities, environmental hazards, changes in the macroeconomic or the regulatory environment or extreme weather. MLPs may trade less frequently than larger companies due to their smaller capitalizations which may result in erratic price movement or difficulty in buying or selling. The Fund invests in small and mid-cap companies, which involve additional risks such as limited liquidity and greater volatility. Additional management fees and other expenses are associated with investing in MLPs. Additionally, investing in MLPs involves material income tax risks and certain other risks. Actual results, performance or events may be affected by, without limitation, (1) general economic conditions, (2) performance of financial markets, (3) interest rate levels, (4) changes in laws and regulations and (5) changes in the policies of governments and/or regulatory authorities. Unlike most other open-end mutual funds, the Fund will be taxable as a regular corporation, or “C” corporation. Consequently, the Fund will accrue and pay federal, state and local income taxes on its taxable income, if any, at the Fund level, which will ultimately reduce the returns that the shareholder would have otherwise received. Additionally, on a daily basis the Fund’s net asset value per share (“NAV”) will include a deferred tax expense (which reduces the Fund’s NAV) or asset (which increases the Fund’s NAV, unless offset by a valuation allowance). To the extent the Fund has a deferred tax asset, consideration is given as to whether or not a valuation allowance is required. The Fund’s deferred tax expense or asset is based on estimates that could vary dramatically from the Fund’s actual tax liability/benefit and, therefore, could have a material impact on the Fund’s NAV. This material is provided for general and educational purposes only, and is not intended to provide legal, tax or investment advice or to avoid legal penalties that may be imposed under U.S. federal tax laws. Investors should contact their own legal or tax advisors to learn more about the rules that may affect individual situations.The Fund is not required to make distributions and in the future could decide not to make such distributions or not to make distributions at a rate that over time is similar to the distribution rate it receives from the MLPs in which it invests. It is expected that a portion of the distributions will be considered tax deferred return of capital (ROC). ROC is tax deferred and reduces the shareholder’s cost basis (until the cost basis reaches zero); and when the Fund shares are sold, if the result is a gain, it would then be taxable to the shareholder at the capital gains rate. Any portion of distributions that are not considered ROC are expected to be characterized as qualified dividends for tax purposes. Qualified dividends are taxable in the year received and do not serve to reduce the shareholder’s cost basis. The portion of the Fund’s distributions that are considered ROC may vary materially from year to year. Accordingly, there is no guarantee that future distributions will maintain the same classification for tax purposes as past distributions. An investment in the Fund may not receive the same tax advantages as a direct investment in the MLP. Because deferred tax liability is reflected in the daily NAV, the MLP Fund’s after-tax performance could differ significantly from the underlying assets even if the pre-tax performance is closely tracked.

Past performance is no guarantee of future results. The Center Coast Brookfield MLP Focus Fund is managed by Brookfield Investment Management Inc.The Fund may not be suitable for all investors. The views in this material are intended to assist readers in understanding certain investment methodology and do not constitute investment or tax advice (please consult your tax professional). The Fund, the Fund’s advisor, and the Fund’s sub-advisor do not render advice on tax and tax accounting matters. This material was not intended or written to be used, and it cannot be used or relied upon by any recipient, for any purpose, including the purpose of avoiding penalties that may be imposed on the taxpayer under U.S. federal tax laws. The views in this material were those of the author as of the date of publication and may not reflect his view on the date this material is first published or any time thereafter.

The Alerian MLP Index is a market-cap weighted, float-adjusted index which tracks the performance of the 50 most prominent energy Master Limited Partnerships (MLPs).

E N D N O T E S1 Netback is a summary of all the costs associated with bringing one

unit of oil to the marketplace and all of the revenues from the sale of all the products generated from that same unit, expressed as gross profit per barrel.

2 Market capitalization of the Alerian MLP Index, a widely followed MLP index, as of 12/31/17 was $316 billion.


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