Protect Your Downside

With all the crosscurrents in the markets, Europe in recession, Japan with no economic growth, and the U.S. registering slow GDP growth that keeps energy demand sluggish, and continued high volatility in oil and gas prices, I remain cautious in the energy sector. However, although cautious I am not absent from the market as I do believe that with a diligent and “defensive” investment philosophy one can achieve positive results over the long-term.

(Related: Three Reasons to Invest in Energy Long-Term)

Indeed, as I have outlined in several of my energy trend notes over the last few weeks, I remain bullish long-term in energy equities, as investors will continue to be attracted to energy equities due to long-term structural supply/demand imbalances that will continue to see demand – consumption increasingly outpace production growth.

Invest Defensively for the Long-Term

The key is to pick and choose wisely by not focusing on the overall broader energy market, but to seek out energy stocks that are “infrastructure” related as pipeline MLPs, or niche providers to the energy market as offshore rig providers, deep water drillers and specialty pump and valve flow systems.

In the current market of volatile share price swings, seek out companies with high dividend yields or MLPs with high distribution yields that will protect your downside by providing support to share prices in down turning markets. I’m talking about specialty companies with above average dividend yields, solid balance sheets, low debt, a sound credible and simple business plan, and — most importantly — high growth prospects. And that brings us to our energy investment idea this week: Magellan Midstream Partners LP (NYSE: MMP).

Magellan Midstream Partners LP (MMP)

If you like a company that:

• has outperformed the broader energy market (XLE) over the last two years;
• has continually moved higher over the long-term;
• recorded consistent positive free cash flow since 2007;
• provides favorable tax treatment on your dividends;
• a high dividend yield;
• high growth prospects;
• a strong balance sheet;
• and believe infrastructure is underinvested in the U.S. energy sector,

then you should like Magellan Midstream Partners LP (MMP), a master limited partnership or MLP, which due to its capital tax structure has to return 90% of its income to investors.

In a nutshell, MMP transports, stores and distributes petroleum products. It operates the nation’s largest refined petroleum products pipeline, operating in three business segments: petroleum pipeline system, petroleum terminals, and ammonia pipeline system. Its petroleum pipeline system runs roughly 9,600 miles of pipeline and 50 terminals. Its petroleum terminals include storage terminal facilities of which six marine terminals are located along coastal waterways and crude oil storage terminal in Cushing, Oklahoma and 27 inland terminals.

MMP’s recent high visibility project has been the reversal of the Longhorn crude oil pipeline in mid-April from Crane, West Texas in the oil producing Permian Basin directly to Houston refineries. The reversal allows crude oil to be diverted from its previous destination to the oversupplied Cushing, OK storage terminals. The Longhorn pipeline average delivery rate has been approximately 90,000 barrels per day (bpd) from mid-April through the second quarter, and ramping to its full 225,000-bpd capacity in the 3Q of 2013. Due to high shipping capacity demand, the company has indicated it may increase capacity by 50,000 bpd. At an estimated cost of $80 million, the expansion would take a year to 18 months to finish.

The company has noted that continued rapid growth in oil production in the lower U.S. 48, particularly in the Bakken and the Eagle Ford, will require additional pipeline infrastructure to move crude to refineries for processing.

MMP has roughly a $12 billion market capitalization and boasts a 3.80% dividend yield. What drives this stock is its strong positive free cash flow generation — a major financial metric I always pay close attention to when I look at stocks. MMP’s free operating cash flow is before any financing or capital investment spending decisions and that gives one a truer picture of the company’s internal operational strength; its ability to re-invest in its operations through its internal cash flow. Indeed, Magellan has reported positive free cash flow for 22 out of 25 quarters since 2007 through 2012.

(Related: Energy Industry Struggling to Generate Free Cash Flow)

The driver behind cash flow growth is essentially EBITDA (Earnings Before Interest, Taxes, Depreciation, and Amortization) generation, and that has been positive since 3Q 2009. Its financial strengths include a strong balance sheet with above average EBITDA-to-interest expense coverage ratio compared to its peers, no general partner incentive distribution rights, and very low to insignificant short interest exposure.

MMP has consistently exhibited positive upward momentum above its 50-day and 200-day moving averages over the last two years. Its longer term line of support is 47.49 at its 200-day moving average. Over the last two years on a rolling basis, MMP has outperformed the broader energy sector (XLE).

Conclusion: I like Magellan’s outlook as an infrastructure player building pipeline capacity from main oil producing regions like the Permian and Eagle Ford. It has a good dividend distribution yield that provides a floor of support to the stock, and has very little short interest. I recommend buying modest amounts particularly on any stock pullbacks toward its long-term line of support at 47.49. Place a firm stop-order limit at 47.00. BUY.

Price Target: 60.00 within the next six months.

Company Information:

Magellan Midstream Partners LP

One Williams Center

Tulsa, OK 74172

918-574-7000

http://www.magellanlp.com

Current global oil consumption is running just under 90 MM b/d, with wellhead production at about a little over 85 Mm b/d, or a deficit or about 4.7 Mm b/d. As we pointed out last week, overall global oil consumption since 2000 to 2012 has been running at a per annum rate of 1.2%; should global consumption continue to grow at this rate, we will hit roughly 100 MM b/d by 2022, or in ten years. If global oil consumption should slow to a per annum rate of 1.0%, we will hit 100 MM b/d only two years later by 2024.

Many people within the industry community believe that oil consumption at 100 MM b/d will occur and within roughly the 2022 to 2024 time frame, however, what many of the same observers note is that global oil production will be severely challenged to meet that level of consumption.

Reinforcing this view, is the reality that global oil production since 2000 has only grown at a 1.0% per annum rate, and is not believed capable of exceeding that level going forward. Indeed, should global oil production at the wellhead continue to grow at 1.0% per year, we would not hit 100 MM b/d of production until roughly 2029-2030, and sustaining that level will be the real challenge for the industry.

One can look at detailed oil production by country to arrive at this conclusion, or one can look at the Eight International Majors’ (ExxonMobil, Chevron, ConocoPhillips, BP, Royal Dutch/Shell, Total, ENI and Statoil) global oil production profile. What is unique about their combined production profile is that nearly each one of the Majors operates in roughly all of the major oil and gas basins around the world.

(Related: How Much Oil Does the World Produce?)

From 2004 to 2012 the Eight Majors have struggled to replace oil production on a proven reserve basis; over this time period, on average, for every 100 barrels of oil production they have replaced only 78 barrels with proven reserves.

The inability of the Majors to replenish production is not for want of effort. Indeed, each year they have increased capital spending to boost production.

With major oil basins around the world, like Alaska, North Sea, Mexico, Venezuela, and China, suffering a global decline rate on average of roughly 4%, the industry will be challenged to replace existing production and grow to meet future consumption levels heading toward 100 MM barrels per day.

From 2000 the increasing industrialization of the developing world has been the primary catalyst driving the demand for global crude oil. Among non-OECD nations, China and India have led the charge, with Chinese oil demand growing at a torrid 6.7% per annum rate and India’s oil demand growing at 4.0% per annum. Overall non-OECD demand for oil has increased at a comparable rate of 3.6% per annum, with the Asia/Pacific region growing oil demand at roughly 2.7%. Developed nations, however, have seen diminishing oil demand with a negative -.04% per annum growth rate.

As I shall point out, the decline in OECD oil demand is not enough to offset the rising demand for oil from the developing world, so the net result going forward will be an increasing supply/demand imbalance. My analysis points to an increasing deficit — gap in global wellhead oil supply — to meet demand.

Supply/Demand Imbalance

While demand is being driven by the developing nations, supply from both the OPEC and Non-OPEC producing regions are struggling to meet demand. Since 2000, OPEC wellhead oil production has increased at a per annum rate of 1.3%, and non-OPEC production has actually declined slightly at a per annum rate of -0.3% — combined, a yearly increase of 1.0%.

Despite global economic growth weakening in 2012, from the depths of the Great Worldwide Recession in 2009, global oil demand has increased roughly 1.7% per annum, while supply has increased about 1.5% over the comparable period maintaining our consumption/production gap.

WTI and Brent Oil Prices in the Next Few Years

For 2013, WTI should average closer to the last two years’ average of roughly $94/bbl. By 2014, I see the global consumption/production gap beginning to widen, as global economies begin to improve led by developing nations.

WTI should average higher in 2014 from $95 to $100 per barrel aided by better economic growth toward the end of 2013 into 2014, and lessening supply bottlenecks in Cushing, Oklahoma as crude oil logistics increase oil from the Mid-Continent to the Gulf Coast refiners. The WTI-Brent differential should continue to narrow with WTI increasing and Brent prices moving lower.

Indeed, going back to 1989 I see a strong correlation of +82% between WTI prices and the global consumption/production gap. While correlation does not prove causality, nevertheless, since 1989 we can see a positive lag relationship between WTI and the global consumption/production gap. Particularly, once the difference between oil consumption and production turned positive in 1999, we begin to see an acceleration in WTI prices, as global supply begins to outpace global demand.

However, what is surprising is that despite the significant tailwind of high crude prices since 2010 to current, net free cash flows (operating cash flow less cash capital spending) have actually declined for the industry overall. Operating costs are increasing crimping margins, and investment spending is rising faster than top-line revenue growth. To put things into perspective, although total industry operating cash flow (OCF) dropped only 1% in 2012 from 2011, from 2007 to 2012 spending grew at a per annum rate of nearly 10% while OCF increased at a 5% per annum rate.

The worst offender has been the U.S. E&P sub-sector heavily weighted to natural gas production at low prices; the sector has seen its deficit cash flow grow. In 2012, despite spending decreasing 2% from 2011, OCF dropped a whopping 17%. From 2007 to 2012, capital spending grew at nearly a 7% per annum rate, while OCF increased only 3% per annum.

Seeking to build infrastructure to meet growing production from unconventional oil & gas shale plays primarily in the Northeast U.S., North Dakota, and Texas for transport to markets, the midstream sector has focused on capacity growth with only one year –2011– from 2007 to 2012 posting positive FCF. Although OCF nearly kept pace with spending growth rates on a per annum basis from 2007 to 2012, 0% to 9%, respectively, the total dollar outlays exceeded cash inflows.

Likewise the utility sub-sector has focused on building natural gas fired generation to replace retiring coal fired plants. Utilities’ spending have grown roughly 11% per annum from 2007 to 2012, while OCF grew at a per annum rate of under 9%.

Seeing the pullback in spending by the U.S. E&Ps and a moderate increase by the western multinationals in spending, the Oil Service sub-sector pulled back in spending in 2012 from 2011 by 3%, and improved cost control helped improve OCF to increase by 4% 2012 from 2011. Indeed, good bottom line management enabled the sector to record only one deficit year from 2007 to 2012; from 2007 to 2012 spending did increase at a 9% per annum rate, while OCF increased only 2.4% per annum.

Not surprisingly, despite capital spending growing at a per annum rate of 10% from 2007 to 2012, and OCF growing 3% over the comparable period, the Western Majors (IOC) with their consistent emphasis on financial performance only had one deficit year in 2009, at the height of the global economic collapse. In 2012, their FCF fell 5% from the year before, but remained positive.

Although the U.S. refiners recorded FCF deficits in 2008 and 2009, the widening of the WTI-Brent differential provided a significant tailwind to their margins, as their feedstock costs are recorded at WTI prices and their refined products are based on Brent prices. The best of both worlds, as their OCF jumped 33% in 2012 from 2011, and rocketed 188% in 2011 from 2010. From 2007 to 2012, spending increased 18% per annum, while OCF grew at an impressive 28% per annum.

The WTI-Brent differential has collapsed to under $13 per barrel, and for the 1Q 2013 average, WTI and Brent prices are below 2012 comparable levels by 8% and 5%, respectively. The lower prices and spread coupled with costs that in general will remain stubbornly high, will most likely contribute to lower earnings for the energy sector in the 1Q 2013 compared to the 1Q 2012. With weak energy demand driven by an overall anemic economy in the U.S. and globally, expect free cash flows to remain challenged into 2013 for the energy sector.

At first glance, higher capital spending in the energy industry may seem a paradox during a period of weak global economic growth. However, it requires enormous capital to maintain — let alone grow — its business model. To that end, several tailwinds have helped fuel the industry’s relentless re-investment, simulative monetary policy – low interest rates, high crude prices, rising costs, increasing demand from developing nations, increasingly remote and difficult regions to explore for oil driven by globally constrained light sweet crude oil.

Particularly, high crude prices are a major catalyst driving spending higher. Since 2011, on average, crude prices — whether WTI or Brent — have been at a consistently historically high level; WTI at roughly $94/bbl, and Brent at about $112/bbl.

Looking at the overall energy sector that includes the oil & gas (U.S. E&P, Western Majors and Canadians), refining, pipeline, utility, and oil services sectors, the industry spent over $450 billion, or 58% higher in 2012 compared to 2007 spending, and 6% above 2011, at a per annum growth rate of nearly 10% from 2007 to 2012.

Refining

The refining sub-sector has grown the most on average from 2007 to 2012, at a per annum rate of 18.4%, and a 25% jump from 2011 to 2012. In no small part, fueled by the need to comply with increasing environmental regulations and the widening WTI-Brent differential that exploded in 2011 pushing margins wider, as operating cash flow soared 30% in 2012 from 2011.

Pipelines

Despite a falloff in operating cash flow in 2012 from 2011 by 14%, the midstream sub-sector – pipelines continued to re-invest in infrastructure. Spending in 2012 jumped 32% from 2011, growing at a per annum rate of nearly 10% from 2007 to 2012. The catalyst in North American pipelines was driven by the unrelenting production from unconventional tight oil – shale plays that have spurred the need for greater means of transporting oil and gas from producing areas to consuming markets.

E&Ps

The U.S. E&P sub-sector registered constrained overall spending in 2012, growing only 2% from 2011, and at a per annum rate of 6.8% from 2007 to 2012, the lowest among the energy sub-sectors. With their heavy exposure to natural gas (NG) production and despite turning to greater liquids (oil and NGL) production, the E&Ps posted minimal spending as operating cash flow dropped 17% in 2012 from 2011 — the highest decline among the sub-sectors.

Oil Services

The oil service sub-sector actually registered a decline in spending in 2012 from 2011 of 3%, as they began to pull back spending YoY in the back half of 2012, reacting to a slowdown in North American production activity driven by low NG prices in 2012. However, from 2007 to 2012 spending averaged 9% per year, roughly on par with the industry overall.

Utilities

The utility sub-sector posted a significant 21% jump in spending in 2012 from 2011, averaging nearly 11% per annum from 2007 to 2012. The main catalyst has been increased environmental regulations that have encouraged the retirement of older coal-fired generating plants replaced by relatively cleaner natural-gas fired combined cycle generation.

The Majors

Known for their steady hand in capital investing, the Majors consistently invest through the cycles, pulling back only slightly in global economic downturns. In 2012, the Majors known as the Integrated Overseas Companies (IOC) increased spending only 4% from 2011 to roughly $210 billion, at an average of 10% per annum from 2007 to 2012.

Looking Ahead

Initial announcements of investment spending for 2013 appear to be conservative in line with 2012 levels, with a number of U.S. E&Ps announcing slight pull backs in spending from 2012. I expect overall industry 2013 spending to range from 4% to 7%. Higher spending in North America among E&Ps and service providers will depend on NG prices, and whether economic activity can push ahead of 2% GDP growth. Crude prices above $90/bbl for 2013 will sustain industry spending closer to 2012 levels, while higher oil prices will push spending higher. I expect the pipeline and utility sub-sectors to continue to significantly re-invest in their infrastructure as they seek to service growing markets and get ahead of a more robust economic recovery perhaps in late 2013 or 2014. A lower WTI-Brent spread and higher ethanol mandates may limit further refining re-investment below 2012 growth rates.

The increasing supplies of NG driven by the productivity of unconventional shale exploration and drilling has pushed NG prices lower over the last few years. With lower NG prices has come greater NG use as a fuel source in power generation.

While many in the media have sounded the death knell for coal as a power fuel source, and in the very long-term I think coal usage will gradually diminish, it will take years — perhaps even decades — for coal to be relegated to an insignificant role in power generation, but I am convinced it will occur.

The cost of producing clean coal is expensive – scrubbing is costly, and the overall cleaner environmental and lower economic cost of NG combined cycle power generation is too competitive. Coal fired plants are being shut down or retirement hastened.

However, the demise of coal use in power generation will be in fits and starts, and we are seeing this pattern unfold currently. As I pointed out in last week’s column Short-Term Trend in U.S. Natural Gas Prices Point Higher,although NG has been recently heading higher driven by a seasonal tailwind of cold weather; nevertheless NG prices are at a nine year low and winter is drawing to a close that should spell a break in NG’s recent climb.

Greater NG production has led to lower NG prices that in turn have led to lower NG electric power prices that are good for the retail consumer; but lowers the “spark spread” for power generators – the gross margin from selling electricity compared to the cost of NG feedstock used in generating the electricity.

Over the years, NG has taken market share from coal. In 2002, power generation was provided 50% by coal and 18% by NG; by 2012 coal’s power generation market share has declined to roughly 37%, with NG increasing to 34%, a stunning reversal of fortune. Most interesting is that the respective rate of decline in coal and the increase in NG’s market share began to accelerate in 2009, the beginning of significant production from unconventional shale sources.

This pattern of substitution driven by price is clearly evident when comparing 2011 to 2012. NG increased its market share by greater proportions in 2012, when NG prices were at their lowest point from March to May of 2012.

However, the reason that the decline in coal consumption for power generation will be gradual and irregular is that when NG prices increase as they did by the summer of 2012, coal prices became more attractive relative to NG and power generators switched to coal from NG.

Long-term, NG is the preferred fuel source for power generation, with both the environment and the consumers at the retail end of the pipeline benefiting. But the road will be bumpy.

The U.S. Energy Department (EIA) reported that U.S. gas inventories were 2.2 trillion cubic feet (Tcf) for the week ending February 22nd, a decline of nearly 6% year-to-date (YTD) compared to last year for the same period; however, storage remains 16% above the five-year average. Comparing the YTD averages since 2008, NG still remains above prior years except for 2012. So we have good news and bad news, good that 2013 NG levels are running below 2012, bad that NG levels still remain at very high levels.

Let’s look at the good news; it appears that NG production has slowed in early 2013. I looked at my NG database that covers U.S. NG production; year-over-year production 4Q 2012 to 4Q 2011 is flat at roughly 0.0% with the multinationals down 4% YoY on the quarter, and the U.S. Independent E&Ps up only 2% YoY on the quarter.

I say only, because from the 1Q through the 3Q of 2012, the YoY production growth comparisons on the quarter were 10%, 10% and 11%, respectively. This indicates that NG production growth has slowed down, particularly among the E&P group that has driven unconventional shale NG production over the last five years.

So far, on the supply side it appears that we are seeing a slight tightening. On the demand side, this week, we have seen demand strengthen compared to last week and to the comparable period last year. However, much of the recent firming in demand is attributable to weather, as 2013 has been colder than 2012, and we still have ten months to go in 2013.

Much can happen: continued hurricane interruptions to production, a warmer than usual summer and so on. But should NG demand remain at roughly 2012 levels and NG production growth continue to slow, then it is increasingly probable that NG prices may firm on average above the $3.25 to $3.53 Mcf level that the Energy Information Agency (EIA) is forecasting for 2013.

In 2012 NG prices averaged $2.75 Mcf, the YTD average for spot Henry Hub (HH) is now $3.32 Mcf or 28% above the YTD average ($2.60 Mcf) for the comparable period in 2012. Given the recent trend for HH spot prices graphed below, — NG has been dancing between its 50 (short-term) and 200-day (long-term) moving averages — it now appears poised to push above the 50-day trend line aided by the recent bout of colder weather.

I think it is reasonable to expect an average range of $3.50 to $3.75 Mcf for 2013, maybe even slightly higher; a colder March than last year would provide a short-term tailwind for NG prices pushing above $3.50 to $3.60 Mcf over the next month.

Possible headwinds over the horizon further into 2013 will be U.S. economic growth stalling out closer to 1% for the first half of 2013, and continuing to drag along at 1% to 2% for the back half of 2013.

However, for E&P producers, NG prices below $4.00 Mcf continue to provide unprofitable margins once all-in costs of finding and development costs are factored into the equation. So investors in NG producers will have to continue to wait for significant demand and sharper production growth pullbacks to emerge to provide a catalyst for share prices to move significantly higher. Even low cost producers as Cabot Oil & Gas (COG) and Range Resources (RRC) will see their shares continue to be highly volatile, as NG prices since 2004 remain at their nine year lows.

This week I am focusing on energy trends in global natural gas (NG) supply and demand; or as the Russians prefer to call NG, “the blue fuel,” due to its blue burning properties.

Unlike our more popular hydrocarbon — crude oil — there is no talk of “peak gas”—at least for now. Global NG production has increased at an annual compound rate of 5.3% since 2000, while crude oil’s comparable growth rate has been 1.0%—so we are not running out of NG, and the world is amply supplied or in balance overall. However, there are supply/demand imbalances across regional NG markets.

The major reason for the regional imbalances is that while crude oil is highly fungible or easily transportable, NG is not, which makes NG globally a highly segmented market. While NG can trade under $3.00 per thousand cubic feet (Mcf) in North America, it commands prices north of $15 Mcf in Asia.

Until the last few years, NG global supply and demand had always been tightly balanced. But recently, overall global production has begun to slightly outpace demand; primarily because of significant NG production from unconventional shale basins in North America, particularly in the U.S. But the additional supply of NG has been limited to, or held captive within, the U.S. due to a lack of liquefaction plants, regulatory hurdles and export terminals. (Related: Why Are Permits Needed for LNG Export Terminals?) The end result is oversupply and low NG prices in North America, and undersupply and high prices outside North America. However, since 2009 even in the U.S. the gap between natural gas consumption and production has narrowed.

In the global Liquefied Natural Gas (LNG) markets, the Majors (ExxonMobil, Chevron, BP, Royal Dutch/Shell, Conoco, Total and ENI) are the primary “big” players due to their deep pockets, strong balance sheets and technical skills. In recent years, however, their global NG production has been on the decline, though not as drastically as their global crude oil production. Indeed, the Majors’ global NG production over the last few years on a year-over-year basis peaked in the 3Q and 4Q 2010 and turned negative in 4Q 2011.

From a different perspective, the Majors’ NG production from 1Q 2010 to 4Q 2012 has been essentially flat to negative or declining at an annual compound rate of -0.1%. Interestingly, the abundance of NG shale production in North America has not made up for their overall global decline.

The ‘Blue Fuel’

Today, global NG supply remains squarely in control of nationalized oil companies (NOCs). Roughly 60% of global NG proven reserves are in Russia and the Mid-East, which together account for 35% of global NG production; the western Majors account for about 15% of global NG production. The U.S. is nearly in balance, with 4% of global “proven” reserves, 20% of global production and 22% of global consumption.

The U.S. NG “proven” reserves will most likely be revised upward once we develop these unconventional resources further. But, for now the majority of U.S. NG unconventional supplies remain in the undeveloped probable and possible resource category.

Russia is oversupplied, with 21.4% of global proven reserves, 19% of global production and 13% of global consumption.

North America is in balance with a significant supply of “captive, as in high storage levels” of NG, which equates to low prices—good for end-consumers, but bad for producers and E&P investors. As for the rest of the world, Europe is essentially a hostage of Russian gas while Japan, China, and India remain primarily reliant on LNG from the Mid-East and Australia—and that means high prices for Europe and Asia, and “captive” markets for Russia and the Mid-East.

However, the majority of the Majors’ profits remain tied to crude oil production, which is declining, as I have pointed out over the last few weeks. While NG and LNG production is a growing percentage of the Majors’ production profile, over the long-term they will be challenged to counter the depth of NG resources of Russian, Mid-Eastern or other NOCs’ ability to penetrate and supply regional dispersed markets.

Lou Gagliardi

But, is peak global oil production just around the corner?

Energy industry analysts believe that global oil production will peak sometime between 2015 and 2025. That sounds like a fairly broad range. However, the reality is that it’s a fairly short timeframe in geologic time that does not even register a notch, and it’s rapidly coming upon us.

(Read More: Five Misconceptions About Peak Oil)

I’m not a forecaster, but I have studied oil supply and demand for the last 20 years, and I do believe that global crude oil production has reached a plateau, and may very well peak sooner than we think.

Why? For one thing, on average, the global natural decline rate of producing wells is roughly 7% plus or minus 1% or 2%. That means production has to grow at least 8% a year to register a net positive increase.

From 2000 to 2011, global oil production at the wellhead has increased at an annual compound rate of 1%. From 1989 to 2000, that annual growth rate was 1.4%, the same rate as 1970 to 2011. The slowing rate of production growth is evident in the chart below that plots the year-over-year percentage change in production.

As the growth in global oil production has slowed, the gap between global oil consumption and production has widened that puts upward pressure on crude prices.

For the “big oil” multinationals like ExxonMobil, Chevron, BP, Conoco, Shell, Total, Statoil, and ENI, the picture looks even worse, whether it’s on a quarterly year-over-year comparison, or on a quarterly sequential comparison.

(Read More: How Much Oil is Left in the World?)

Globally, all the western multinationals (IOC) and national oil companies (NOC) are struggling to keep pace with the demand for crude oil. Currently, the dilemma is not as acute as it could be because global demand for energy is weak, but if global demand accelerates in the near term, the strain on production to meet crude oil demand will tighten and that will push crude prices significantly higher.

The trend is clear, global crude oil production is struggling to meet demand in the long-run. That supports elevated crude prices over the long-term, and in turn the advantage is to seek out “oily” producers that are “growing” oil production.

A few things to remember: invest in low cost producers with deep resources to feed future growth production, strong balance sheets to invest through the cycles, and positive net cash flow to fund future growth prospects and return cash to shareholders. Protecting the downside is just as important as maximizing the upside, and above all else, investing is a long-term “process.”

Lou Gagliardi

But first a little bit about my career and experience.

I began my career doing project economics at Texaco for all facets of the energy value chain from upstream, downstream to midstream. I eventually segued to covering oil and gas companies at IHS Herold’s valuation shop. At Herold, I provided fundamental equity investment research. My core specialties run the entire energy value chain from oil, gas, and power markets to company coverage of Western multinationals, U.S. E&Ps, Canadian oil sands, national oil companies, refining, alternative energy, MLPs, pipelines, and oil service providers.

Over the years I have been interviewed by CNBC, the New York Times, Forbes, and the Financial Times, regarding Canadian oil sands, emerging markets, Enron and El Paso. I was featured in Robert Bryce’s book on the downfall of Enron, having notified clients of Enron’s financial inadequacies prior to the market’s awareness.

This past year, as crude price volatility has heightened, I have focused clients on industry infrastructure trends where “bottleneck” opportunities that “moves energy molecules” are providing long-term investment opportunities that have lower commodity risk and high dividend yields to provide support to the downside, like MLPs such as Magellan Midstream Partners (MMP) – up 11% with a 4% dividend yield since last October, and Plains All American Pipeline (PAA) – up 22% since last July with a 4.3% dividend yield. I also recommend companies that provide a “niche” service or product to the energy sector, such as Flowserve (FLS) that generates positive net free cash flow – up 22% since last August, SeaDrill Limited (SDRL) a specialty provider of deepwater drilling rigs that sports a roughly 9% dividend yield, and an MLP E&P BreitBurn Energy Partners (BBEP) – up 17% since recommended last August and boasts a nearly 9% dividend yield.

With more than two decades of industry experience in the oil patch, I will help you drill for opportunities all along the energy value chain from the upstream to the downstream, from E&Ps to oil service providers to pipeline MLPs. I will analyze industry trends, providing a multifaceted perspective in industry insight and analysis, and not only tell you what the trends mean, but who will be the winners and who the losers.

My investing approach builds upon a global commodity view, technical analysis supported by growth and momentum indicators, macroeconomic trends and solid fundamental analysis. I combine a top-down and bottom-up approach to investing in energy equities; linking equity, commodity, and currency markets with energy policy, to get a better understanding of the cross-currents that underlie share and market performance.

Successful investing in energy relies upon three key principles: getting the commodity right, getting the company right, and lastly getting the global macro picture right. Never has that core tenet been as important in energy as today, particularly with the heightened global economic uncertainty and accentuated market and commodity swings over the near term. However, I do see lucrative investment opportunities over the long-term horizon for energy investors.

Indeed, the long-term global energy view is best captured in understanding three structural long-term trends that I do not see abating:

1. Constrained Global Resource Supply: increasing demand from developing nations will outstrip available global supply.
2. Continued Economic Growth in Emerging Markets will be spurred by faster population growth than in OECD nations.
3. Global Inflationary Pressures will be fueled by increasing monetary stimulus.

All three factors are bullish long-term catalysts for higher crude prices. Indeed, constrained global resource supply is the most critical tailwind that will drive oil prices higher. This point is driven home in the chart below: when global oil production from 2000 onward began to fall below 95% of global consumption, crude prices moved dramatically higher. Over the long-term I do not see this scenario abating, rather I see it intensifying.

Since 2000 emerging markets have driven global GDP growth.

Excessive monetary stimulus provides an additional support to higher crude prices from 2000 onward.

According to the IEA, roughly 80% of the world’s population resides in the developing world, i.e., Asia, Africa, Latin America and the Middle-East, which grew from 1990 to 2008 at an annual rate of 2.1% and is projected to grow at 1.4% per annum to 2025. Compare this to OECD nations in North America and Europe, where population grew at a more moderate 0.7% from 1990 to 2008 and is expected to remain at that rate through 2025.

Markets in 2013 will continue to be preoccupied with “economic uncertainty,” i.e., sovereign debt woes in Europe, a ballooning U.S. deficit and overall a precarious global financial system that has stymied global economic growth and spawned excessive monetary stimulus to jump-start flagging economies, but in reality has fueled longer-term inflationary expectations. The net result has been greater global market and currency volatility that in turn has heightened oil price volatility. Against this backdrop of high market beta, with energy stocks nearly 90% positively correlated to oil prices, which in turn are highly negatively correlated to the U.S. dollar, managing the downside is critical to trading energy stocks.

In the near-term I will trade around volatile crude prices by focusing on a select few defensive energy stocks that have a high dividend yield and upside potential to maximize returns; companies that are currently exhibiting relative strength and growth momentum.

However, the investing foundation of my fundamental methodology will rest on six “quality” attributes: links along the oil & gas value chain of “Resources to Production to Cash Flow to Value.”

1. Low cost producers to strengthen the P&L;
2. Companies with deep resources to grow future production;
3. High growth prospects to accelerate cash flow;
4. Strong balance sheets with low debt expense to invest through the cycles;
5. High net cash flow (NCF) to feed future growth prospects;
6. Companies that trade at a discount to net asset valuation to optimize the upside.

Stay tuned as I keep you abreast of the latest industry trends to drill for the best long-term investment opportunities.

Lou Gagliardi