Welcome to My Website

 

Jack Blog Picture 7-5-2014

If you would like to contact me, my email is jackhudd1@gmail.com, or feel free to call at 615-525-7592.

I started this website in 2009 as part of my plan to take a disciplined approach to studying financial analysis and preparing for a career. I am using it now as a way to let potential employers see samples of my work. I’m not looking for an easy job. In fact, I would like a challenging job.

In brief, I have trained for 6 years as a financial analyst, have completed the Chartered Financial Analyst (CFA) Program, and have passed 3 of the 4 CPA Exams and am scheduled to take the fourth CPA exam. I have a Master of Accounting degree, B.S. in Finance (3.92 GPA on 4.0 scale), and advanced skills in financial analysis, accounting, financial modeling, Excel and PowerPoint. I am 25, single, and do not have dependents.

In April 2008, while a Freshman, I began studying for the Chartered Financial Analyst (CFA) Exams. To complete the CFA Program requires passing 3 very difficult exams, two of which are only offered once a year.  The earliest anyone can take the first exam is when they are a senior in college. I passed the Level 1 CFA exam in June 2011 while a senior, passed the Level 2 exam in June 2012, and in June 2013 I passed the Level 3 exam. According to the CFA Institute, the worldwide pass rate was 39% for the Level 1 exam in June 2011, 42% for the Level 2 exam in June 2012, and 49% for the Level 3 exam in June 2013. The CFA Program has been referred to as a “gold standard” by The Economist and Financial Times. It has been described as “grueling” and “the equivalent of a master’s degree in finance with accompanying minors in accounting, economics and statistical analysis”. It is said that completing the CFA Program requires “ability, dedication, ethical grounding and hard, transferable analytical skills”. The CFA Program Curriculum consists of 8,000 pages in 18 volumes and covers topics such as Corporate Finance, Financial Reporting and Analysis, Quantitative Methods, Equity and Fixed Income, Economics, Alternative Investments, Portfolio Management, and Ethical and Professional Standards. The CFA Program has prepared me to be a financial analyst.

I graduated summa cum laude from UWF in December 2011 as a Finance major and received a Master of Accounting degree in May 2014. I could have finished the Master of Accounting sooner, but I spent a lot of time studying for the CFA exams. I spent over 2,000 hours studying for the CFA exams and an additional 1,000 hours doing financial modeling in Excel.

I have passed 3 of the 4 CPA exams and am scheduled to take the fourth exam. I wasn’t allowed to take the CPA exams until I finished the Master of Accounting (MAcc). I received the MAcc in May, 2014 and my application to sit for the CPA exams was approved within a month. The CPA exams I have passed are Business Environment and Concepts (BEC), Auditing and Attestation (AUD), and Regulation (REG). I am scheduled to take Financial Accounting and Reporting (FAR) at the end of November. The CPA exams are difficult and the pass rate is about 50%. I hope it won’t take longer than a month to prepare for each exam, but the exams aren’t offered every month and that complicates matters. Some of the exams like AUD and REG require a lot of memorization. I’m glad to pass some of the CPA exams before I start a full-time job, but I am ready to start work when I am needed.

At the Berkshire Hathaway (BRK.A) annual shareholders meeting for the year 2013

At the Berkshire Hathaway (BRK.A) annual shareholders meeting for 2013

I pursued a Master of Accounting degree for two reasons. First, I felt the additional accounting courses would help me be a better financial analyst and that has proven to be true. Second, UWF has a strong accounting program. In 2013, UWF ranked number 5 in the U.S. out of 266 small accounting programs for first-time pass rates on the CPA exam and it ranked number 2 in Florida among all college accounting programs (source: the NASBA, which is the national accounting regulatory organization).

I  have advanced proficiency in: corporate finance, accounting, complex financial modeling, valuation, and forecasting; Excel, PowerPoint and Word; financial statements and financial reporting; DCF, NPV, ROI, IRR, accretion/dilution analysis, and pro forma analysis; analyzing depreciation, working capital requirements, investment opportunities and investment performance; statistical analysis of economic and financial data; and most kinds of financial analysis. I have read hundreds of financial statements, notes, disclosures and MD&A, 10-K’s and 10-Q’s. If you want to see a detailed explanation of how I analyze and value companies, click the sixth link on the right side of this page titled “How I Analyze and Value Companies”.

My accounting knowledge is useful because many Financial Analyst jobs require a high level of accounting knowledge.

I am also proficient with Access and familiar with SAP, SQL, Hyperion Planning, and Essbase.  I can quickly learn software for financial analysis, planning, monitoring, reporting, budgeting, forecasting, Enterprise Project Management, ERP, databases, business intelligence, business performance management, etc., and am willing to study specific software before starting a job.

In case you wonder about the domain name of this website, it is from the famous article by Warren Buffett titled “The Superinvestors of Graham-and-Doddsville,” which was published in the 1984 fall issue of the Columbia Business School magazine.* Warren Buffett was a student of Benjamin Graham, and he attributes much of his success to Graham’s ideas. I admire Warren Buffett and his partner Charlie Munger. In May 2013, I attended the Berkshire Hathaway Annual Shareholders Meeting in Omaha.

Thank you for visiting my website.

James “Jack” Huddleston
Updated  November 5, 2014

*http://www7.gsb.columbia.edu/alumni/news/hermes/print-archive/superinvestors

The Battle Between China’s 3 Telecom Companies And Its Impact On Profits

 

July 23, 2013

Note: This article has also been published to seekingalpha.com.

Disclosure: No positions in any securities mentioned at the time this article was written.

China’s telecommunications industry is comprised of three competitors: China Mobile (CHL), China Unicom (CHU), and China Telecom (CHA). This article discusses the battle for market share that is being waged between these three companies. Obviously, the outcome of this battle could affect their values.

Brief History of China’s Telecom Industry Since 1999

China Mobile, China Unicom, and China Telecom are spin-offs of an old government-owned entity called China Telecom, which had a monopoly on all telecom services in China. The Chinese government broke up that company and distributed its assets to form several new companies, for the purpose of creating competition.

China Mobile, formed in 1999, was given the mobile business. After some other distributions, China Telecom was left with a fixed-line business. Later in 2002, China Netcom was formed. Distributed to it were China Telecom’s assets in the 10 northern provinces of China. China Netcom merged with China Unicom in 2008 to form the China Unicom we know today (the former China Unicom was established in 1994 and had built a mobile business). China Telecom retained its assets in the 21 southern provinces of China.

This description of past events is a vast oversimplification. It does, however, serve to show how these companies came to be and just how actively involved the PRC government actually is.

Overview of China Mobile, China Unicom, and China Telecom

China Mobile is strictly mobile, although there are reports that the company is building its own fiber-optic network and plans to offer fixed-line broadband. This network is solely operated by China Mobile and allow it to compete with China Unicom and China Telecom for the internet market. In addition to mobile, China Unicom and China Telecom offer fixed-line service, which China Mobile does not. China Mobile does, however, “cooperate” with China Tietong in providing fixed-line services. Both China Mobile and China Tietong have the same government-owned holding company as their parent corporation.

China Mobile’s network extends into much of rural China, whereas Unicom and Telecom have focused relatively more on urban areas. While this means that China Mobile has a de facto monopoly in some parts of rural China, customers in those areas tend to be poorer. As mentioned already, Unicom’s and Telecom’s fixed-line business were originally concentrated in northern China and southern China, respectively. Since 2008, China Telecom’s mobile business has expanded to all 31 provinces in China (counting Chongqing, Beijing, Shanghai, and Tianjin as provinces). China Unicom also expanded its services to all 31 provinces in 2009.

What the Companies Are Battling for and the Impact on Market Share, Revenues, Earnings, and Profit Margins

The impacts of the battle for market share are evident in the tables below, which shows mobile subscribers, market shares for mobile subscribers, revenues, pretax earnings, and pretax profit margins.

*Source: For 2008-2012, 20-F statements and company presentations. For 2013, Reuters. *Note: (1) Revenue and earnings before income tax include revenues from fixed line subscribers. (2) Currency conversions in this article are at the rate of 1 RMB = 0.162933 USD. The terms Renminbi (RMB) and Yuan are used interchangeably to refer to the currency of China.

Observations from the tables above:

1. From the first of 2011 to May 31, 2013, there was a huge increase in 3G subscribers in China – from 53 million to 310 million. China Mobile added 102 million 3G subscribers, China Unicom added 82 million, and China Telecom added 72 million. However, China Mobile’s share of 3G customers dropped from 51% to 42% while both China Unicom (31%) and China Telecom (27%) have gained market share.

2. From 2008 to 2012, China Mobile’s total revenue increased by 36%, but during the same time frame China Telecom’s revenue increased by 52% and China Unicom’s revenue increased by 56%.

3. Since 2008 there has been a huge difference in pretax profit margins between the three companies. In 2012, China Mobile’s pretax profit margin was 30.57%, China Unicom’s was only 3.82% and China Telecom’s was 6.99%.

4. China Mobile’s pretax profit margin has decreased every year since 2008.

Recently, the focus for these three companies has been to compete for higher-end customers who can afford smartphones and 3G/4G service. As implied earlier, such customers tend to be found in urban areas. From the start of 2009 to May 31, 2013, China Mobile saw its market share drop from 74% to 63%. That loss went almost entirely to China Telecom, whose market share increased from 4.5% to 14.8%. As seen in the table, much of this can be attributed to China Telecom and China Unicom gaining share of the 3G market.

In order to stop its market share from declining further, China Mobile is increasing its spending on 4G and on handset subsidies. The company announced last March that in 2013 it plans to spend 41.7 billion Yuan ($6.79 billion) on developing a 4G network and 27 billion Yuan ($4.4 billion) on handset subsidies, a 13% increase from 2012. Analysts expect China Mobile’s annual profit for 2013 to decline from 2012 partly because of the 4G spending. If that occurs, it will be the first time the company’s profit has decreased since 1999. As an additional effort to retain higher-end customers, China Mobile has lowered international roaming fees.

China Telecom has also been spending heavily in order to increase its market share. After China Telecom signed its iPhone deal with Apple in 2012, it spent a large amount for advertising and customer subsidies. This resulted in China Telecom’s profit being lower in 2012. Wang Xiaochu, Telecom’s Chief Executives, says the costs are investments for greater long-term profits.

Conclusions

1. As stated earlier, the Chinese government’s intent has been, and probably still is, to make its telecom industry more competitive. The government has imposed mergers and divestitures on all three companies in the past and could do so again in the future for the sake of stimulating more competition. Needless to say, rarely does increased competition result in values increasing for all the competitors.

2. China Mobile is not burdened with fixed-line operations. An obvious societal trend is the switch away from landlines to mobile phones, yet Unicom and Telecom still have to maintain their landline systems. The fixed costs in those systems is big and, all else equal, revenue falling in that business will squeeze profits. As an example, China Telecom mentioned that its lower year-over-year profit in the fourth quarter of 2012 was partly attributable to declining fixed-line phone revenue. In order to maintain revenues, China Telecom has to invest in mobile network assets, yet at the same time its fixed line assets are losing value.

3. China Mobile will probably continue to lose market share in the future as more people switch from 2G to 3G. This can be seen in the relative market shares between the three companies for 2G and 3G. This is based on the assumption that any new future 3G users will be distributed roughly according to present market shares.

4. China Mobile is currently uncontested in many rural areas, but Unicom and Telecom have stated a desire to also compete for rural customers.

5. If I had to choose to invest in any of these 3 companies, I would probably choose China Mobile for the reasons that it is the cheapest by conventional measures of value (EV/EBITDA and dividend yield) and it has the highest pretax profit margin. There are other factors to consider, however, such as growth and any future changes in profit margins. An in-depth analysis of such factors is beyond the scope of this article, and I have not done a full-fledged valuation for all three companies. China Mobile’s pretax margin has consistently declined in the past five years, though this could change in the future if China Mobile can steal back some of the high-end 3G market by selling iPhones.

6. The main point of this article is this: before anyone invests in these companies, they should be aware of the battle for market share that is going on. This battle is causing all three companies to increase spending. It is too soon to know how this battle will end and the ultimate impact it will have on profits. There are many factors that come into play: the shift from fixed-line phones to mobile phones, increasing internet usage, government pressures, and the quality of decision making by management – all of which deserve their own individual analysis. In any case, it is highly unlikely that intensified competition will result in an increase in the profits of China’s three telecom companies.

Note: The sources for facts mentioned in the sections titled “Brief History of China’s Telecom Industry Since 1999″ and “Overview of China Mobile, China Unicom, and China Telecom” are the 20-F filings for China Mobile, China Unicom, and China Telecom.

Devon Energy (DVN) Analysis

 

Disclosure: At the time this article was written, I was long DVN.

Analysis of Devon Energy

June 27, 2012

Updated August 1, 2012, for Q2 2012 information (Posted 8-22-12)

Table of Contents

A. Format of this Report
B. Summary of Investment Conclusions
C. Basic Description of Devon’s Operations
D. The Peer Group
E. Production and Reserves
F. Merger and Acquisition Activities
G. Prospects for Growth
G.1. Expansion of Existing Locations
G.2. New Ventures
G.2.a. Description of the 6 New Ventures
G.2.b. Sinopec Joint Venture
G.2.c. Sumitomo Joint Venture
G.3. Canadian SAGD Projects
H. Financial Analysis
H.1. Accounting Adjustments
H.1.a. Impairment charges
H.1.b. Discontinued income
H.2. Financial Strength
H.3. Competitive Strength
H.3.a. Cost and Asset Efficiency
H.3.b. Profitability & Returns
H.3.c. Growth rate
I. Valuation
I.1. Free Cash Flow
I.2. Growth Rate
I.3. Discount Rate
I.4. Target Price Calculation
I.5. Special or Unusual Factors in the Valuation
I.6. Supplemental Valuation
I.7. Optionality Value
J. Worst Case Intrinsic Value
K. Worst Case Stock Price
L. Recommendation
M. Notes
Disclosure

 

A. Format of this Report

For the convenience of the reader, the sections of this report are numbered and the notes referenced in each section can be found at the end of that section or subsection, and these notes are set off from the regular text by a horizontal line. Notes to tables will be found at the bottom of the table. In addition, I have tried to use a text size that is easy to read on computers and mobile devices.

 

B. Summary of Investment Conclusions

Based on a study of the company, competitors, and future industry and economic expectations, as of June 27, 2012 Devon has a calculated midpoint target price of $98.47. Given a 33% range of value, the upper and lower ranges are $115.25 and $86.05. Using the midpoint target price as the decision rule for investment, Devon is recommended as a sound investment for purchase.

 

C. Basic Description of Devon’s Operations

Devon Energy Corporation (symbol: DVN) is an independent oil and gas company. It has an upstream exploration and production (E&P) business and a marketing and midstream (M&M) transportation business. In addition to pipelines, the M&M segment has compression and processing plants.

The M&M business’s purpose is primarily strategic, and it is not the main focus of the company’s strategy or capital expenditures. The primary function of Devon’s M&M business is to support its E&P business. The company was one of the first producers to begin drilling in certain plays. As a result, Devon has had to build the necessary transportation and processing infrastructure. As other E&P companies move in to drill, Devon allows them to use its infrastructure in return for a fee. In total the M&M business only comprises about 8% of Devon’s operating income, and accordingly it is given less attention in this article in comparison to Devon’s E&P business.

 

D. The Peer Group

Throughout this article, several mentions are made of a peer group. The 14 companies in the Peer Group are listed below. These companies were chosen because they have similar economic characteristics to Devon in that: (a) most of their operations are in continental North America, (b) each of the companies has at least $1 billion in market capitalization, and (c) most of their business is in E&P. This Peer Group includes the following companies:

The Peer Group (1) has been split into subgroups based on the amount of reserves that are in natural gas. This is because the economics for oil and gas are different. I think one point that can be argued is that the mixed producers have a special advantage over the predominantly oil or predominantly gas producing companies. The advantage is that mixed producers can take advantage of price changes by shifting their production more toward the energy commodity that is most favorable. On the other hand, a company that has mostly oil or gas can do nothing more than wait until prices turn to their favor. This advantage, I think, translates into greater stability in earnings and returns.

Note that whenever the Peer Group is mentioned throughout this article – as it is frequently in the “Financial Analysis” section – it is referring to the aforementioned group of 14 companies. In addition, when a calculation for the Peer Group is shown, either the overall peer group average or the median of ratios, Devon is always excluded. Devon is shown in the list of Peers above just for convenience.


(1). See my article “Debt Servicing Ability of 15 Oil & Gas Companies” for more about this Peer Group

 

E. Production and Reserves

Reported total production (stated in million barrels of oil equivalent or MMBOE) since 2003 is as follows:

Devon’s Total Production from 2003 to 2011 (MMBOE)

A quick look at total reported production can give the impression that Devon has not grown at all over the past several years. The table above shows, however, that after excluding offshore and international operations – thereby isolating production to onshore North America – total production has increased 4.40% per year annually compounded. (Note: Devon currently only has operations in the continental U.S. It divested of its offshore and international operations over the past 5 years. See below: “Merger and Acquisition Activities”).

Reported proved reserves (MMBOE) since 2003 are as follows:

Reported Proved Reserves 2003-2011 (MMBOE)

Continental North American reserves have roughly doubled since 2003. Canadian reserves have been relatively stagnant with the main advances being the Jackfish and Kirby-Pike steam-assisted-gravity-drainage (SAGD) projects (see the section “Growth Prospects” below for discussion on Canadian operations). U.S. onshore reserves have more than doubled since 2003, increasing 11% per year annually compounded since then.

Oil, NGLs and Total Liquids as a % of Total Reserves 2007-2011 (2)

(2). Note: Oil + NGLs = Liquids

Below is a table from the company’s 2011 annual report, which breaks down reserves, production, and net acres by each major geographic area.

Reserves and Production by Geographic Area, 2011

 

Natural gas prices have declined in the past few years because of an oversupply of the commodity. This oversupply is often credited to the “shale boom” in North America, as prices in foreign countries have generally not experienced a decline of this degree. The largest exposure Devon has to low natural gas prices (and possibly decreasing NGL prices) is in the Barnett. Devon’s Barnett reserves in 2011 were 22.1% liquids. In 2011, 32.4% of Devon’s production came from the Barnett, 7.5% from the Permian, and 5.1% from Cana-Woodford.

A rate of return matrix in a 2012 company presentation shows that at $2.50 gas and $80 oil rates of return in the Barnett Shale are about 12%. After corporate taxes this would be 7.80%, which is not far from the ROIC seen for Devon as a whole and for the general industry in 2011 and 2010. (See below: “Profitability & Returns”).

The recent low gas prices will probably be temporary. Rates of return at recent prices are unattractive enough relative to oil projects that many producers have cut gas production and increased liquids production. Moreover, low gas prices have resulted in higher demand. The basic laws of supply and demand will most likely eventually cause gas prices to revert to some equilibrium price higher than the current price.

This equilibrium price reversion, however, probably will not occur within the next few months or even the next few years. Until this price reversion occurs Devon will continue to give a greater weight of production to oil and NGLs. In Q4 of 2011, 45% of sales came from oil and 36% came from NGLs. This kind of production obviously isn’t sustainable forever, given the reserve mix, but it can probably continue until natural gas prices increase.

The Barnett will benefit hugely if gas prices rise to a higher level. At a gas price of $3.50 and an oil price of $80, the Barnett operations are expected to have a rate of return of 30%. Cana-Woodford, which is 36.4% liquids, is expected to have a rate of return of 28% return at those same prices.

The Permian, which is mostly liquids (roughly 80%), has been not been much affected by the depression of gas prices. Out of dozens of competitors, Devon has the second largest acreage position (at 1,500 net acres) in the Permian next to Occidental Petroleum (2,400 net acres).

 

F. Merger and Acquisition Activities

Devon currently has operations solely in the continental U.S. (the lower 48 states) and Canada. In the past it had offshore operations in the Gulf of Mexico and subsidiaries across the globe, but from 2007 to 2011 the company divested of both. These divestitures are part of a strategic decision to focus on continental North America that was announced officially in 2009 by company management. Former CEO J Larry Nichols (now Chairman of the Board) explained this decision in his 2009 letter to shareholders:

“We had more high-quality development opportunities than we could simultaneously pursue. Therefore, in order to optimize the value of our overall opportunity set, we are relinquishing some opportunities and focusing our resources on others. This led to our decision to monetize our Gulf of Mexico and international assets and to focus our capital and human resources on our world-class assets onshore in the U.S. and Canada.”

Devon’s merger, divestiture, and acquisition activity since 1998 is presented below: (3)

(3). Note: The book value figures are calculated as the total selling price minus the sum of related capital gains.

It has been the company’s policy since the Ocean Energy merger to prefer internal investment over growth through mergers or acquisitions. Some investors worried that Devon might use the proceeds of the offshore and international divestitures to make poor acquisitions. The company, however, has made it clear that it does not intend to use those funds for acquisitions, and it will instead use the cash to repurchase shares and reinvest in itself. This course of action is based on the belief that its current opportunity set offers better rates of returns than a potentially overpriced acquisition.

It is interesting to note that, based on 2007 reserve data, offshore and international operations in total represented 8.9% of the company’s total reserves at the time. Yet these reserves were sold for in total $13 billion, or 57% of the company’s common stock market capitalization as of June 27, 2012. It would seem that either the market is acting pessimistically or the buyer of these assets was overly optimistic. It is more likely is that the resource potential is greater than the stated proven reserves, and that the value of those two divestitures as a percentage of the total company is significantly greater.

 

G. Prospects for Growth

There are three main known areas of prospective growth for Devon:

  1. Expansion of Existing Locations
  2. “New ventures”, including joint ventures with the China Petroleum & Chemical Corporation (Sinopec) and Sumitomo
  3. Canadian steam-assisted-gravity-drainage (SAGD) projects

These three topics will be discussed in some detail below.

G.1. Expansion of Existing Locations

While the scope of this report does not permit a detailed analysis of each individual play the company is involved with, a discussion of the general picture is warranted. Devon was one of the first companies to enter into some of North America’s recently discovered plays. That allowed it to acquire large acreage positions at a relatively low cost. As of June 2012, all of Devon’s locations are in North America.

Areas where the company was most actively expanding in terms of drilling as of 2011 and early 2012 are the Cana Woodford Shale in Oklahoma, the Barnett Shale in Texas, the Permian Basin also in Texas, and Lloydminster in Canada. Most of these plays are unconventional with the exception of Lloydminster, which produces heavy oil by conventional means. Not listed on the “Reserves and Production by Geographic Area” table above is another large acreage position in the Permian Basin that Devon only recently revealed known as the Cline Formation, which is a “liquids rich” play according to the company.

One way to evaluate Devon’s long-term growth prospects is by looking at its “risked resources”. In its 2012 Analysts Day presentation, Devon stated that risked resources as of April 2012 were 16,200 MMBOE and unrisked resources were 31,800 MMBOE, implying overall roughly a 50% chance of successful extraction. Based on 2011 production that means risked resources will take 67.5 years to extract. (Note: Risk resources figures include the “new ventures” described below.)

Management estimates should obviously be viewed with skepticism, as they could be overly optimistic, but even if one assumes that risked resources will be half of management’s estimate there is still an inventory of 33.75 years remaining. This does not include the exploration that the company will do over that period to find additional new resources.

Unfortunately, Devon does not define “resources” in its 2011 annual report or any other documents I reviewed. In addition, I cannot determine whether the definition of resources is the same as that used by the Society of Petroleum Engineers. It seems likely, however, that the company is using the standard definition of unrisked resources, which includes proved, probable, and possible reserves – reserves extractable given the best case scenario. Risked resources is likely defined as unrisked resources multiplied by the probability of ultimate extraction.

Chevron provides the following definition of “resources” in its 2011 annual report:

“Estimated quantities of oil and gas resources […] includes quantities classified as proved, probable and possible reserves, plus those that remain contingent on commerciality. Unrisked resources, unrisked resource base and similar terms represent the arithmetic sum of the amounts recorded under each of these classifications. Recoverable resources, potentially recoverable volumes and other similar terms represent estimated remaining quantities that are expected to be ultimately recoverable and produced in the future, adjusted to reflect the relative uncertainty represented by the various classifications.”

Max Petroleum PLC defined unrisked resources in a report titled “Resource Estimates of Exploration Potential on Blocks A & E from Ryder Scott Company, LP” dated July 12, 2012: (4)

“Unrisked prospective resource volumes are commonly categorized as Unrisked P90, P50, P10 or Mean Resources and are estimated before multiplying by the geological chance of success which assumes that the drilling of an exploration well is successful.”

And risked resources:

“Risked prospective resource volumes are commonly categorized as Risked Mean Resources and are calculated by multiplying the unrisked mean resources by the geological chance of success to account for the risk of drilling an unsuccessful exploration well.”


(4). http://www.maxpetroleum.com/uploads/10-07-12-rns-competentpersonsresourceestimates.pdf

G.2. New Ventures

This section describes the 6 New Ventures and joint ventures with Sinopec and Sumitomo.

G.2.a. Description of the 6 New Ventures

In addition to expanding on the plays where Devon already has substantial operations, there are multiple “New Ventures”, as the company calls them. Notable among these is a joint venture with Sinopec, a Chinese company that seeks to gain expertise in producing in unconventional oil and gas. The Sinopec joint venture includes five New Venture positions. A sixth New Venture is the Cline Shale. The Cline venture is close in proximity to Devon’s outstanding Permian Basin operations and will benefit from the infrastructure and economies of scale already present there.

Summary of Devon’s New Ventures as of Q1 2012 (5)

(5). Note: (a) This data was originally shown in the 2012 Analysts Day presentation. (b) The “total” column figures are weighted by unrisked resources to Devon. (c) BOE/D = barrels of oil equivalents per day.

These plays are mostly unconventional, but some conventional wells will also be drilled. In the above table, the first month production rate is taken from a “type curve,” which shows expected production from a well over the life of the well. The type curve is almost always hyperbolic – that is, production decreases very rapidly near the first few years and then decreases very slowly for several years thereafter. For the type of projects comprising the New Ventures, the production by years 2-3 is usually roughly 20% of the initial production. Assuming production by 2013-2014 will be 20% of what it is by the first month, then BOE/D production per well is:

Assuming the production in years 2-3 will be 20% of the first month production rate, then the wells that are planned to be drilled by the end of 2012 will add to production between 5.97 and 6.59 million barrels of oil equivalents (BOE). If these ventures turn out to be a success, it is likely more wells that can be drilled in each area with similar economics to the rest of the company’s operations.

If even 10% of the unrisked resources from the 6 New Ventures are eventually classified as proven reserves, this would add 79.52 million BOE assuming a 9.5% depletion rate (typical of Devon and the peer group historically) – as compared with Devon’s total 2011 production of 240 million BOE.

G.2.b. Sinopec Joint Venture

The terms of the joint venture with Sinopec are favorable for Devon. Devon receives $2.5 billion from Sinopec in exchange for a 33% interest in five New Venture exploration plays in the U.S. $900 million will be received during Q1 of 2012, and the rest will be paid incrementally over the life of the project to cover future drilling costs. The company expects the other $1.6 billion to be realized by the end of 2014. This $2.5 billion will, according to current estimates, cover 80% of total development costs until 2014. This significantly reduces the risk of the New Ventures, and it is almost self-funding, meaning it will not require relatively significant amounts of capital to be diverted to it.

If Sinopec did not overpay for the 33% interest, then that implies the total value of the joint venture is $7.5 billion. Devon’s $5 billion portion of the joint venture is 22% of Devon’s market capitalization as of June 27, 2012. Based on the June 27, 2012 share price of $56.20 and if one assumes that the market price is also correct, this implies the value of Devon’s current operations is $31.52, which is a 25% discount to stated book value per share (6).

The historic earnings and returns of the company, I think, do not at all justify any discount to stated book value. This same value of $31.52 when divided by the 5-year average of earnings per share (adjusted for impairments and discontinued operations) shows a P/E of 5.37. It seems likely that either the market is not giving much credit to the joint venture or has little faith in current operations.


(6). This is calculated as: the June 27, 2012 share price of $56.20 minus Devon’s share of the joint venture per share of $12.36 minus non-operating assets per share of $12.31 (for the calculation of non-operating assets per share. (See “Special or unusual factors in the valuation” below).

G.2.c. Sumitomo Joint Venture

Devon announced on August 1, 2012, that it will sell a 30% interest in its Cline and Midland-Wolfcamp properties to the Japanese company Sumitomo Corporation. The details of this deal are similar the Sinopec deal. According to Devon’s press release, the 30% interest will be sold for $1.4 billion. $340 million is expected to be paid by the end of the third quarter of 2012, when the deal is expected to close, and $1.025 billion is “committed” to funding drilling and completion costs over the next few years as the initial phases of the project are completed. This $1.025 billion is expected to be fully received by sometime in the middle of 2014. Devon will be the operator and “responsible for marketing.”

This deal is also favorable for Devon. According to the company the deal will cover 79% of drilling and completion costs. This has the two beneficial effects of (1) reducing the amount of capital expenditures Devon must commit and (2) reduces the risk of the project. The first few years of the venture will be the riskiest, and this risk will be substantially reduced when wells are actually drilled and producing. Until that time, Devon doesn’t have to commit much capital. It can be argued that a significant reduction in initial fixed investment increases Devon’s overall returns from the project. This factor combined with the lower risk makes the joint venture quite favorable.

As a side note, this joint venture along with the Sinopec joint venture gives credit to the notion that there is an advantage to a larger size just as there is a disadvantage. The disadvantage is potentially lower growth. The advantage, though, is that Devon is more likely to be a candidate for favorable joint ventures of this type.

G.3. Canadian SAGD Projects

In Canada, Devon has been investing several for nearly a decade in a steam-assisted-gravity-drainage (SAGD) project known as the “Jackfish.” The SAGD technology is used to liquefy crude oil so heavy that – according to Devon’s head of Canadian operations Chris Seasons – one can almost walk on it. Devon claims to be the first independent U.S. based company to operate an oil sands project in Canada.

After the success of the first Jackfish project, Devon invested in two more SAGD projects, and now has a total of three. Each Jackfish project produces approximately 35,000 barrels of oil a day, or 12.78 million barrels a year, and each has a lifetime of about 25 years. Jackfish 1 alone amounted to about 5.32% of Devon’s total 2011 production, and it has been in production since around 2008. Jackfish 2 was completed in 2011, but it won’t be at full capacity until 2012. Jackfish 3 achieved regulatory approval from the Canadian government at the end of 2011, and it probably will not be completed until 2013.

The cost structure of these projects is not made clear, but they are likely more expensive than conventional oil and gas projects. A rate of return matrix shown in a 2012 presentation for Jackfish 1 and Jackfish 2 shows an expected rate of return on Jackfish 1 of 29% assuming $80 WTI and $2 natural gas. Under the same price assumptions, the rate of return on Jackfish 2 is expected to be 22%. Returns for Jackfish 1 reach 39% at $120 oil and 29% for Jackfish 2. Another interesting feature of the SAGD projects is that the costs decrease as the price of natural gas decreases, since it is used as an input into the process. As a result, the rate of return on these SAGD projects decreases about 1% for every $2 increase in natural gas prices per mcf.

It seems that several more of these Jackfish-type projects can be developed within the next decade. For example, the Kirby-Pike Project is a 50-50 joint venture with BP and is similar to the Jackfish. Because Devon has gained an expertise in these kinds of projects, they are the operator. Chris Seasons estimates that at least six Jackfish-type projects will be operational before 2020 (2 projects at Jackfish, 3 projects at Pike, and a separate “Jackfish East” project), which will add about 52 million barrels of oil production per year in comparison to Devon’s total 2011 production of 240 million BOE (7).

Devon would have 2.20% volume growth over the next 10 years if its expansion were limited only to its Canadian SAGD projects. These projects have little risk in terms of exploration, because (1) the location of the oil is already known and (2) Devon has experience with the technology. Most if not all of this production will be heavy oil bitumen, and the economics of SAGD should provide a slight hedge to natural gas price declines.

The first Jackfish project took several years, but the SAGD technology at that time was relatively new. The knowledge Devon gained from Jackfish 1 has allowed it to now be capable of finishing a project within 1 to 1.5 years after Canadian regulatory approval, and Devon has been successful at quickly obtaining the required approvals. The economics should get better over time as the company’s expertise grows further. In addition, since all the currently planned Jackfish-type projects will be located in close proximity to each other, there will be economies of scale from transportation infrastructure, processing, personnel, and so forth.


(7). This is after subtracting out BP’s 50% interest in the three Pike projects.

 

H. Financial Analysis

The purpose of this section is to determine through objective analysis whether Devon is at least as good as the Peer Group, in terms of its financial strength, cost and asset efficiency, profitability, returns, and growth prospects (8). If this is the case, then Devon should sell for at least as much as the average company in the Peer Group has in the past several years. For the purposes of valuation, I am assuming that Devon will grow at a slower pace than the average for the Peer Group. The slower growth is offset to some degree, however, by the company’s financial strength and stability.


(8). The list of 14 companies in the Peer Group is near the beginning of this report.

H.1. Accounting Adjustments

Before analyzing the ratios themselves, it is necessary to discuss various items that have been adjusted and the reasoning behind these adjustments.

H.1.a. Impairment charges

In 2008 and 2009 Devon had two very large impairment charges against income termed “reduction of carrying value of oil and gas properties.” Companies in the oil and gas industry have special accounting standards, and the gist of this impairment charge is – although this is a gross oversimplification – that it is required when oil and gas prices decline by a significant amount. Many companies in the oil and gas industry recorded this kind of impairment in 2008 or 2009 as a result of the major price decline that occurred as a result of the recession.

The price of oil, measured by the “West Texas Intermediate” (WTI) spot price, started its plunge in July of 2008 at a price of $145.31[1], bottomed in December at $30.28, recovered to about $80 by the end of 2009, and steadily rose to approximately $100 by the end of 2011. By June 2012, oil prices had returned to the $80 range. It is definitely true that such price volatility affects cash flow. While the company’s derivatives protected its average sales price per barrel of oil equivalent in 2008 ($44.08), the average price received in 2009 was definitely affected ($24.71). Natural gas prices, measured by the “Henry Hub” (HH) spot price, dropped from a high of $13.31 in July 2008 to $2.06 in Sept. 2009, rose to $3.00 by the end of 2011 and were $2.74 by the end of June 2012.

Impairment implies a permanent long-term decline of earning power. Given these facts, the size of the impairment seems overstated. Once the prices are back up, the assets become economical again. A good portion of the impairment charge is justified – as the property and equipment were purchased at much higher natural gas prices than are expected in the future – but it is difficult to know precisely how much.

Inclusion of impairments for Devon and for the Peer Group companies reduces comparability. For the sake of simplicity, the adjusted ratios in the analysis below remove the total impairment from the income statement for Devon and the Peer Group.

H.1.b. Discontinued income

Since 2007, Devon has divested of its offshore and international operations. Besides a small amount of operational income, the sale created large capital gains in 2011 and 2010 and a lesser gain in 2008. In the table below, Devon’s net income is adjusted to exclude income from discontinued operations.

H.2. Financial Strength

Before a valuation can be made, the basic question of the Devon’s financial condition must be addressed. In addition, an analysis of the company’s competitiveness in comparison to competitors is warranted.

The table below compares Devon to the Peer Group on various ratios indicating financial strength:

Devon’s Financial Strength Compared to Peer Group (9)

(9). Note: (a) No adjustment for discontinued operations is made for Devon as discontinued operations is reported below pretax net income. (b) For the years 2011 to 2007, the figure shown for the Peer Group is the median of ratios, and the average for those years is the arithmetical average of the ratios shown for the previous years.

These ratios, when taken in aggregate, show that there is little chance of the company being unable to pay its debts, and they show that Devon is generally in a stronger position in comparison to the Peer Group. Interest can be more than adequately covered by EBIT, and any debt principal can be repaid with normal operating cash flow. The ratios seen in 2009 are also strong given the circumstances. Management has voiced several times in the past few years its intentions to keep debt within safe limits.

As with any business, having free cash ready to take advantage of opportunities is a big advantage. Devon’s high cash levels in 2011 and 2010 are the result of its divestitures and, besides creating temporary extra financial cushion, will allow the company to make substantial investments without having to raise new funds from financial markets. As is discussed below, the current market price hardly seems to be giving any credit to this large cash position.

H.3. Competitive Strength

H.3.a. Cost and Asset Efficiency

The table below compares Devon to the Peer Group on various ratios indicating its cost and asset efficiency:

Cost & Asset Efficiency Comparison – Reserve Replacement (10)

(10). Note: (a) For the years 2007 to 2011, the figures shown for the peer group are the overall average of the 14 companies in the Peer Group, excluding Devon. It is not the average of ratios but the ratio calculated if the figures for each company are summed. The reasoning for using an overall average rather than a median is to see how efficient the industry is on a whole on a barrel of oil equivalent basis. The average for those years is the arithmetical average of the ratios shown for the previous years (b) A ratio is calculated excluding revisions because for the most part these revisions are the result of changes in prices for oil and gas. Efficiency ratios are meant to analyze management’s ability to deal with things that are under their control, which does not include price changes.

The S&P Industry Survey for the “Oil & Gas: Production & Marketing” industry from March 29, 2012 shows that the “organic reserve replacement” ratio for U.S. producers is 2.07 on average for the three years 2010 to 2008 (11). Devon lags the Peer Group in replacing its reserves, but seems to be on par with U.S. producers in general.

Devon is one of the larger companies in the Peer Group, and typically oil and gas companies show a decrease in their reserve replacement ratio over time. This makes sense from a logical perspective (the larger a company becomes, the more it is expected to regress to the mean). For example, the average reserve replacement ratio for the 5 “super majors” (BP, Chevron, ExxonMobil, Royal Dutch Shell, and Total) was roughly 1.50 in the year 2000 and 0.75 on average from 2004 to 2007 (12).

Oddly, in spite of its lower replacement, Devon has lower costs. Typically a company with lower costs is capable of expanding at a faster rate – that is why the low-cost Marcellus producers and producers in similar plays are achieving such high reserve replacement ratios. This may be simply a matter of choosiness on Devon’s part and a desire to forgo costlier projects and thereby sacrificing growth for overall returns. Indeed, growth that results in lower overall returns can sometimes result in a decline of the overall value of a company. The company has emphasized many times its desires to maximize returns and debt-adjusted growth per share, so this is a reasonable explanation.


(11). The S&P calculates this ratio as: = (revisions + extensions and discoveries + improved recovery) / production. Few companies actually report a line item even resembling “improved recovery” (all in all, only 3 do: SM Energy, Berry Petroleum, and Denbury Resources); it seems for the most part to be aggregated in “extensions, discoveries, and other additions.” The S&P’s figure most likely includes offshore production as well.

(12). International Energy Agency data. http://www.ie-ei.eu/Club_de_Nice/2009/GUINOT_2009.pdf

H.3.b. Profitability & Returns

The table below compares Devon to the Peer Group on various ratios indicating its profitability and returns:

Devon’s Profitability Compared to Peer Group (13)

(13). Note: (a) For the years 2011 to 2007, the figure shown for the Peer Group is overall average of the industry. The average for those years is the arithmetical average of the ratios shown for the previous years. (b) The HH and WTI data are calculated based on monthly figures from the U.S. Energy Information Administration. These figures generally correspond to the realized price for each company before the effects of derivative hedging.

In the above table, two figures are presented for Devon. The first (“Devon Energy”) are the ratios based on data as reported. The second (“Devon Energy Adjusted”) makes adjustments for three one-time significant gains from the sale of discontinued operations. These gains occurred in 2011, 2010, and 2008.

The gains had the second consequence of placing a large amount of cash on Devon’s balance sheet. In 2011, 17% of Devon’s total assets were in cash. Obviously, much of this cash is not needed for operations and could reasonably be excluded in a calculation of ROIC. Making this adjustment by excluding “non-operating cash” (defined as any cash in excess of 2% of total assets) increases the ROIC for 2011 to 10%. The same adjustment for 2010 increases ROIC to 10.3%. Making these additional adjustments causes the average ROIC to become 13.5%.

I think this shows that Devon slightly trails the Peer Group. Making adjustments for any similar gains to the Peer Group could cause its average to decline (Cabot and SM Energy, for example each had substantial non-recurring gains in 2011 and 2010). In any case, the difference does not seem large enough to state conclusively that Devon is definitely worse than the average company, but in comparison to the Peer Group it probably isn’t one of the better companies in terms of its profit margins and returns on invested capital.

H.3.c. Growth rate

Total proved reserves provides a basis for valuing oil and gas producing companies and is a reliable measure of growth. It is from proved reserves that companies draw all of their production and hence their revenue. Proved reserves also minimize the effects that oil and gas price changes have on growth, which weakens the value of information gotten from growth rates. Oil and gas price increases over the past decade were extraordinary, and it would be foolhardy to project similar increases far into the future.

As shown on the table below, from 2001 to 2011, the growth rate of proved reserves for the Peer Group was 11.20% while Devon’s growth rate was 9.5% (after subtracting offshore and international reserves). Devon’s 2011 reserves are understated because of its previous divestitures and the huge amount of cash – around $7 billion (including that amount of the proceeds temporarily placed in short-term securities as of the end of 2011) – has yet to be reinvested. Devon’s cash is about the same amount that it spends in capital expenditures each year. Under this theory, there is a potential 8% of growth (the growth of reserves over the past 5 years) that is not factored into the current reserve figure. If that cash had been reinvested, the theoretical growth rate over the period 2001 to 2011 would have been 10.36%. For a company that is relatively large in size and has done little in terms of acquisitions over the years, this isn’t bad.

Proved Reserves – Peer Group and Devon (MMBOE) (14)

(14). Source: 10K statements for each company – 2003, 2006, 2009 and 2011.

 

I. Valuation

The way to value any asset is to project its cash flows out into the future and then to discount them at an appropriate rate. This section discusses all components of the valuation, including: free cash flow, growth rate, discount rate, target price calculation, special factors in the valuation, supplemental valuation, and optionality value.

I.1. Free Cash Flow

The cash flows have been calculated using the “scientific” or modeling method of calculating first revenue, which is sales price multiplied by physical volume, and then subtracting operation expenses and taxes (15). The operating profit margin approximately equals that seen on average over the past decade, which is a good indication of the margin assuming a “normal” oil and natural gas price level. Operating cash flow is then found by adding back non-cash items, including necessary working capital investments, and then a subtraction for “maintenance” capital expenditures is taken to find “free cash flow” (16). Finding free cash flow in the case of an oil and gas company is comparatively simple. I used two methods of calculating maintenance capital expenditures that ended up with approximately the same results. These are briefly described below.

Value for an oil and gas company (i.e., its dividend paying potential) should stay the same if its reserves stay the same and everything else remains equal. Thus one would subtract from operating cash flow the amount of capital expenditures necessary to replenish depletion of reserves from production. Historically, Devon’s average annual total additions to reserves have been double their production. The predominant expense in adding new reserves is capital expenditures (additions to property, plant, and equipment). It can therefore be concluded that “maintenance” capital expenditures are approximately half of reported capital expenditures (i.e., one half of capital expenditures are needed to replace reserve depletion and therefore keep value constant).

A second method of calculating maintenance capital expenditures is to adjust depreciation for inflation over time. My personal records show that the multiplier necessary to adjust depreciation, depletion, and amortization to its cost in today’s terms is 1.25. Again, this is based solely on my personal records, and I found this number by looking at several companies that have a high amount of long-lived depreciable assets. The major error in this method is that today it costs more to gain a barrel of reserves from unconventional resources than it did ten years ago, but the results using this method for Devon were very close as those obtained from the first method based on reserve replacement. Over a 9 year period, the result using this method was within one percent of the result using the first method

Over a long period of time, free cash flow does not differ substantially from net income. Its main benefit in historic analysis is to get around oddities of accounting that distort results, such as with the impairments in 2009 and 2008.


(15). Future oil and gas prices are assumed to be slightly less than today’s breakeven prices for producers, to take into account cost efficiencies that will most likely occur in the future. The logic underlying this method is that competition should ultimately cause prices to move to their equilibrium price set by the laws of supply and demand. A scenario analysis was done to test for a near-term “shock” to oil and gas prices, where both drop significantly, and the results of this method do not differ hugely from that assuming a constant breakeven price. The calculated value between these two scenarios differed by about $5 per share.

(16). Maintenance capital expenditures are those needed to maintain value. Subtracting total capital expenditures instead of maintenance capital expenditures will cause free cash flow to be negative in many years. A good portion of the capital expenditures of oil and gas companies is spent for growth purposes.

I.2. Growth Rate

The growth rate used to value Devon does not include any assumptions about price increases over time – only volume growth is considered. Volume is assumed to merely grow at a certain percentage each year based on the company’s historic results, the Peer Group’s experience, and the fact that growth rates typically decline as companies become larger and oil and gas resources become scarcer. The estimated production from the SAGD projects and the new ventures alone are enough to grow volume roughly 4% per year over the next 10 years. Those two factors in addition to planned expansion at outstanding operations (the Barnett, the Permian, etc) are also considered in the estimated growth of volume.

A long-term growth rate of 8% is assumed. This reasoning is most succinctly explained in the following table. This table assumes that, with the exception of changes to reserves outstanding, everything else remains equal. In addition, it assumes a depletion rate (production divided by average reserves of the beginning and end of the year) of 8%. Note that, given a constant reserve replacement ratio (RRR), the growth rate percentage will be different depending on the depletion rate.

The reserve replacement ratio for Devon is expected to be at least 2 over the next several years, and it will likely decline over time as the company grows larger. This decline in the reserve replacement ratio is also reflected in the growth rate over the next 10 years. The long-term growth rate, over the next 90 years or so thereafter, is very low at 2% to reflect (a) diminishing returns on scale over time and (b) the uncertainty of that future.

I.3. Discount Rate

The cost of equity is the opportunity cost of investing in Devon as opposed to a competing oil and gas company or some company of equivalent risk. This opportunity cost is determined from the 14 Peer companies mentioned many times above.

Since potential oil and gas price changes are not considered in future growth, neither are they considered in the cost of equity – conceptually similar to using a “real” (as opposed to nominal) discount rate.

The cost of equity is calculated using two separate measures. The first is to combine historic growth with the historic dividend yield received on average for the Peer Group over the past several years. As calculated above, the Peer Group growth rate is 11.20%. The Peer Group’s dividend yield in May of 2012 was about 1.04%. Combining these two forms of return yields a total return of 12.24%. This is what one would have realized on average from the 14 companies in the Peer Group over the past several years after excluding those gains that occurred as a result of increases in the price of oil and natural gas.

I.4. Target Price Calculation

Based on a discounted cash flow valuation, a Target Price is calculated as $98.47 per share. Adding roughly a 33% range creates an upper range of $115.20 and a lower range of $86.05.

Below is a summary of this discounted cash flow valuation for the price:

Discounted Cash Flow Valuation (17)

(17). Note: This valuation is not attempting to forecast precisely the net income for 2012 or 2013. Its purpose is to provide an estimate of the value that is indicated given all the relevant facts of the company. If you would like to see the valuation model I used I can email it to you.

Long-term oil and gas prices are obviously open to debate. My reasoning in choosing those prices was to choose a price that seems conservative and justified based on long-term supply and demand. In the case of natural gas, this is based on the significantly higher prices seen outside of the U.S. and historically. For crude oil, this is based on a collection of many expert opinions on what the economic breakeven price (18) for crude oil is – that is, the price that will offer returns high enough to incentivize companies to drill for oil. Both prices include a rough discount for cost efficiencies that will probably be realized in the future as a result of experience gained and new technology.

The amount of time it will take Devon to reach this Target Price is indeterminable and depends a lot on how oil and gas prices move – for oil and gas companies move systematically with oil and gas prices. The average time frame for a stock to revert to its target price is 2.5 years (19).


(18). For clarity’s sake, the word “economic” typically means a subtraction for the opportunity cost is made.

(19) This average number is based on Benjamin Graham’s records. See HarperCollins Publishers 2005 version of “The Intelligent Investor” (1949 edition) on page 39.

I.5. Special or Unusual Factors in the Valuation

As mentioned numerous times in this report, there is a large amount of cash and short-term securities sitting on Devon’s balance sheet that can be reinvested over the next few years. Rather than attempting to determine the time frame and the ultimate returns from these reinvestments, I simply added the book value of these net non-operating assets to the present value of cash flows.

As of March 31, 2012, Devon had $5.828 billion of cash and cash equivalents and $1.282 billion in short-term investments (mostly commercial paper and the like receiving very low interest). Most of this is a consequence of the divestitures and $900 million of it came from Sinopec as a result of that joint venture, which is discussed above. Most of this cash is not needed for basic operations, and several of the companies in the Peer Group carry cash balances far below 2.5% of their total assets for several years consecutively. For the sake of conservatism and possible sampling error, it has been assumed that Devon will carry 5% of its total assets in cash.

The assumed cash needed for operations using the 5% assumption is $2.13 billion. This is far more than Devon has ever carried historically except for 2010 and 2011. It is enough cash to cover all current payables as of Q1 2012. After subtracting this $2.13 billion, $4.98 billion is left over as “excess cash.” This equates to $12.31 per share and has been added to the intrinsic value of operating activities.

The value of this $4.98 billion could alternatively be estimated by assuming it is reinvested and then calculating the present value of the resultant cash flows. The present value of such cash flows would probably result in a value higher than $4.98 billion.

I.6. Supplemental Valuation

A supplemental valuation based on a multiplier approach was also calculated as a check on the discounted cash flow approach. Based on historic earning power of $2.586 billion from current operations (the average of net income over 5 years after adjusting for impairments and discontinued operations) and a multiplier of 13.50 on these earnings, the value of current operations is found to be $86.39 and $98.70 after adding the value of non-operating assets.

The price to earnings multiplier was found by calculating for the average peer group multiple over a period of roughly 10 years, which was found to be around 15. The multiple was adjusted downward to 13.50 as analysis shows that Devon has slightly lower growth prospects than the Peer Group average. The multiple is also adjusted simply as a matter of healthy conservatism by assuming a general regression to the mean economic performance on an industry-wide scale over the long-term.

I.7. Optionality Value

Optionality value, simply stated, is that value that will become possible when some contingent event occurs. Technically, optionality value should already be included in an intrinsic value calculation, with the optionality component being equal to the total value multiplied by the probability of occurrence. In many cases, though, it is impossible to estimate the probability to reasonable range. Including it essentially adds a speculative component and basing an investment decision on that component when the investment would otherwise be unsound seems imprudent. For that reason, optionality value is not included in the calculation of the target price, but I think it still warrants discussion.

There are two prominent forms of optionality available to Devon that may become active and increase the intrinsic value calculated above. The first of these are additional opportunities that will become available as oil and gas prices rise. A clear-cut example of this is the North American oil and gas boom in the past few years, which has been made possible only because higher prices justified the increased costs of horizontal drilling and hydraulic fracturing.

The second relates to the Devon’s marketing and midstream (M&M) business. The annual report for 2007 states that the company was considering selling a minority stake in its M&M business in the form of a master limited partnership (MLP). The company felt the market was undervaluing it and an the M&M having its own securities would force the markets to value it independently with the high capitalization multiple generally given to MLP’s. This was in 2007 before the financial collapse, when MLP’s sold at an especially high multiple. Devon again discussed selling the M&M business at the 2012 Analysts’ Day. To quote current CEO John Richels (20):

“. . . the investment thesis at that time was these assets trade for, these MLP assets trade for 12 times EBITDA and you’re trading it at 6 or wherever we were at that time and take advantage of that. But what we found is the assets that are in our midstream and where we generate our EBITDA and our operating profit through our midstream operation is subject to commodity price fluctuations because they tend to be percentage of proceeds liquids contracts. And so as we got more into that, it became obvious and our advice from our investment bankers was that those assets, because they have commodity price exposure, trade more like 8 times rather than the 12, and we have very low basis in those assets. So we’d have to pay a big check to Uncle Sam, and frankly, it ended up — we’re given up the strategic assets and all of us the shareholders wouldn’t have seen it. So we decided not to go ahead with that. It’s something we revisit from time to time to see if those circumstances change, but at this point in time, it just doesn’t make sense.”

Essentially, the company believes that its M&M business has a “strategic” value created when combined with its normal E&P business, and that this synergy value plus the low market valuation end up exceeding the market valuation if split off as an MLP with its own securities and sold at a higher multiple. In regard to Mr. Richels’ comment about “commodity price exposure,” note that MLPs are often preferred as investments when oil prices are volatile, as those companies have a tendency of being more isolated from the short-term impact of price changes; hence the statement that Devon’s M&M assets have “commodity price exposure” was used as support that it would sell at a lower multiple.

It seems possible that if the multiples of MLP companies reach a high enough level, it may be possible for Devon to unlock greater value by selling a portion of its M&M business. This optionality value is somewhat small and the probability is most likely small as well. The value of Devon’s M&M business if it became an independent MLP is calculated to be $1.518 billion at the midpoint, $1,822 billion at the upper range, and $1.215 billion at the lower range. These values imply a P/E for the business of 13.93, 16.72, and 11.14, respectively.


(20). Credit to seekingalpha.com for the transcript of the whole event.

 

J. Worst Case Scenario

I have calculated separately on the assumption of a “worst case.” The intrinsic value under this scenario is calculated as $80.21. The valuation calculations are shown below.

The worst case assumes the following:

  • After most hedges on the price of oil and gas expire by the end of 2013, there is assumed in 2014 to be sudden and severe decline of oil, natural gas liquids, and natural gas prices – similar in degree to that seen in 2008-2009. For example, Western Texas Intermediate (WTI) oil prices bottomed in 2008-2009 at about $40, and that is close, I think, to the most extreme case. Effectively this means I am assuming that in the worst case there will be a price drop in 2014 to 50% of its long-term average price. Prices thereafter rise linearly to their long-term average in 2016. The long-term average price for oil is assumed as $80 per barrel, for natural gas $3.25 per million cubic feet, and for NGL $20 per barrel.
  • Natural gas liquids (NGL) prices decline relative to WTI oil prices in a similar way that natural gas did in the past few years. Historically, the price of natural gas has been about one-sixth the price of oil, which is roughly the “energy-equivalent” ratio (on a British thermal unit basis, 6 thousand cubic feet of natural gas equals 1 barrel of oil). Natural gas prices in 2012, though, have instead traded at about one-fiftieth of oil prices because of (1) a supply glut of natural gas in the U.S. and (2) the loss of excess production capacity of oil within the past decade. NGL prices have become depressed in 2012 due to oversupply – the same thing that has happened to natural gas. My worst case assumption is effectively that NGL prices will drop to 25% of the price of WTI oil instead of the historic average of 50%. The average price of NGL per barrel sold in Q2 of 2012 for Devon was $31.42 per barrel, and the average price of oil per barrel sold was $67.67 (this is before the effect of derivatives).
  • There is a slight decrease in production volume growth of 1% from the normal case.
  • EBT margins are reduced in the long-term to 32% instead of 38-40% as seen historically (after adjusting for one-time charges). This gives allowance for possible cost increases as unconventional projects increase in complexity (as the easier and cheaper “low-hanging fruit” are picked) and increased regulatory costs that may come as a result of public anxiety regarding fracking. Very rarely in normal has Devon experienced an EBT margin this low historically, and its margin is usually several hundred basis points higher – sometimes as much as 1,000 basis points higher.
  • EBT margins decrease during the oil and natural gas price shock to 20%, as there are short-term fixed costs.

These assumptions are shown in the valuation below.

 

K. Worst Case Stock Price

In my opinion, the price of Devon Energy’s stock is highly unlikely to go below $40. I would say that the worst case stock price is between $40 and $50 in the near future. The circumstances that could cause the stock price would go that low would be: (1) if a recession occurred (in which oil, natural gas, and stock prices all most likely plunge for a short while), (2) if natural gas prices fall independent of the general economy, or (3) if oil prices fall independent of the general economy. I will address all three in that order.

1. Occurrence of a recession

$40 is roughly the price Devon bottomed at during the 2009 stock market crash (at $39.92). Since 2009, the company has expanded its intrinsic value. In addition, with the exception of the 2009 bottom, Devon’s stock price has not fallen that low within the past 5 years. The stock price declined considerably within the past few months (as of September of 2012), but it seems to have hit a “resistance level” of around $55.

2. Natural gas price decline independent of general economy

Part of Devon’s stock price movement is caused by natural gas prices, which are one of several inputs constituting Devon’s total revenues. From January 2009 to August 2012, natural gas prices declined by 51.37% from $5.83 per thousand cubic feet (mcf) to $2.84 per mcf (these are the monthly average prices). During the same time frame, Devon’s stock price fell from about $75 to about $58 – a decline of 22.67%. The decline in natural gas prices were caused primarily by overproduction, and subsequently a “glut” formed in supply.

A natural gas price in the mid-$2s puts a lot of pressure on the profit margins of E&P companies. As a result of this decline in natural gas prices, many companies, including Devon, have switched their exploration and production activities largely if not completely away from natural gas and are now focusing on oil instead. I find it hard to imagine that the imbalance in supply to demand could be exacerbated any further (except possibly just briefly) or that the price would fall below a breakeven level, as these companies have shown themselves to be very nimble in shifting production in response to changes in prices. In addition, prices at the mid-$2s gives a big incentive for companies to invest in the expensive process of natural gas exportation, since natural gas prices in Europe and Asia are far higher than they are in the U.S., and major investments in this regard have been made at the time of writing (September 2012).

A further decline in natural gas prices is not entirely impossible, though. If gas prices fall an additional 50% from the mid-$2s, say $2.50, and if Devon’s stock price falls by 23% from a price of $60, then its stock price would still not go below $40.

3. Oil price decline independent of general economy

As for oil prices, there are two ways prices could decline (besides due to a decline in economic activity): (1) worldwide oil prices fall because of excess production capacity, (2) regional oil prices in the U.S. fall relative to worldwide prices (there exists a discount to worldwide prices or the discount widens).

In the past, (1) was the typical situation, as OPEC sought to stabilize world oil prices through increasing and decreasing production as necessary. It could do this because it had excess production capacity over demand. Within the past 10 years, though, OPEC has largely lost this excess capacity and absolute price control is no longer a possibility. Oil prices now are set by market forces. A decline in worldwide oil prices is certainly possible if a recession occurs, as demand would decrease. Absent of a recession, though, worldwide supply is unlikely to exceed demand for any significant period. Thus, there is no significant catalyst that I know of that would cause a significant decline in worldwide oil prices except for a recession.

The main danger is (2), and the primary culprit behind it is a lack of adequate pipeline capacity to handle the sudden increase in U.S. oil production from the oil sands in the northeast U.S. (Wyoming, North Dakota, etc) and Canada, and from other places as well (the Permian Basin in west Texas being a good example). A huge amount of capital, however, has been funneled into building new infrastructure over the past few years, and this infrastructure problem should largely be resolved within the next few years, say by the end of 2013-2016.

Before that capacity comes online, a further decline in North American oil prices – due to a widening of the discount – is possible. If that occurs, Devon’s stock price would likely decline as well, since Devon sells all of its oil production at U.S. and Canadian prices. The lack of capacity, though, is already largely reflected in current prices. West Texas Intermediate (WTI) sells at a significant discount to worldwide oil prices, and the price of crude oil from the oil sands sells at a further discount to WTI. For example, Devon’s average U.S. selling price of oil was $88.74 in Q2 of 2012, while Canadian oil (where its oil sands projects are located) sold at an average of $54.88.

I do not think increases in production of oil are going to outpace increases in infrastructure in the near-term – as the steep discount of U.S. oil prices to world prices disincentivizes rapid expansion of production, and new infrastructure is being built at a fast pace. An significant increase of the discount of U.S. prices to world prices does not seem likely (except perhaps for brief moments). Even if it occurs, it is unlikely to be more than a 20% drop (which would set Canadian oil to $44, based on Q2 prices). As with natural gas, oil at $80 (from its recent normal level of around $100) puts pressure on the profit margins of many unconventional companies. If that kind of drop occurred, and assuming Devon falls by the full 20% from a stock price of $60, then its stock price would still not fall below $40.

4. Final thoughts

It is for these reasons that I say Devon’s worst case price is between $40 and $50 in the near future. These reasons are entirely related to price, because I do not think Devon will fail on exploration and production matters or cost control in the near-term, and in fact Devon has been doing well in those regards.

 

L. Recommendation

Devon’s price as of $56.20 per share as of June 27, 2012 is far below my calculated intrinsic value. The decision rule on whether to buy is that the price should be at most two-thirds of the midpoint target price. At the current price, this ratio is 57.07%. I calculate a midpoint target price of $98.47. Based on a 33% range, the upper range is $115.20 and the lower range is $86.05. Using the midpoint target price as the decision rule for investment, Devon’s common stock is recommended as a sound investment for purchase.

 

M. Notes

Note 1: Sources of company data

Except where otherwise noted, data in this article is exclusively from company SEC filings. Market price data, however, is from Yahoo! Finance.

Note 2:

Technically speaking, a positive adjustment on the income statement for impairment or a negative adjustment for gains would necessitate an adjustment on the balance sheet. I failed to do this only because it does not change the overall conclusions as toward Devon’s relative position to the industry.

Disclosure: I am long Devon.

Copyright Jack Huddleston, 2012

You are allowed to copy all or part of this article as long as you credit:

Jack Huddleston, www.graham-and-doddsville.com

Debt Servicing Ability of 15 Oil & Gas E&P Companies

 

Debt Servicing Ability of 15 Oil & Gas Exploration and Production Companies

 

Data as of July 2012 and earlier – Posted 8-22-12, Revised 9-2-12

Table of Contents

A. Format of this Report

B. Overview

C. The Effects of Oil and Gas Price Volatility on Debt-Servicing Ability

C.1. Average Monthly Oil & Gas Prices for 2011 to 2006

D. Comparison of Financial Condition

D.1. Financial Condition Ratios for 2011

D.2. Financial Condition Ratios 2006 through 2011 (6 year averages)

D.3. Financial Condition Ratios for the Year 2009

D.4. Debt Servicing Ability by Cash and Liquid Assets

E. Break-even Oil & Gas Prices and Break-even Costs

F. Relative Valuation

F.1. Valuation Multiples

G. Concluding Thoughts

H. Notes

I. Raw Data Tables

I.1.   Revenue, 2006 to 2o11

I.2.   Earnings Before Interest, Income Taxes, Depreciation, Depletion & Amortization, 2006 to 2o11

I.3.   Depreciation plus Depletion plus Amortization, 2006 to 2o11

I.4.   Interest Expense (excluding capitalized interest), 2006 to 2o11

I.5.   Interest Capitalized to PPE, 2006 to 2o11

I.6.   Impairments from Full-Cost-Ceiling Test, 2006 to 2o11

I.7.   Earnings Before Income Taxes, 2006 to 2o11

I.8.   Net Income (continuing Income where applicable), 2006 to 2o11

I.9.   CFO (continuing CFO where applicable), 2006 to 2o11

I.10. Cash & Cash Equivalents plus Short-term Investments plus Restricted Cash, 2008 to 2o11

I.11. Receivables, 2008 to 2o11

I.12. Total Debt, 2006 to 2o11

I.13. Shareholders’ Equity, 2006 to 2o11

A. Format of this Report

For the convenience of the reader, the sections of this report are numbered and I have tried to use a text size that is easy to read on computers and mobile devices.  Notes to tables can be found at the bottom of the table and general notes are at the end of the report.

B. Overview

This article compares the debt servicing ability of 15 U.S. oil and gas exploration and production companies (the “Peer Group”). These companies primarily derive their operating income from North America, from exploration and production, and from onshore activities.

Note: If for any reason the tables in this article are obstructed, right click the table and then select “view image.”

C. The Effects of Oil and Gas Price Volatility on Debt-Servicing Ability

In the U.S., the historical chance of a recession in any year is roughly 1 in 5, so it is important for a company to be prepared for that possibility. While oil and gas generally have inelastic demand, recessions are often accompanied by a decline in oil and gas prices and sometimes the prices collapse, as occurred during the last recession. This can be seen in the recent history of West Texas Intermediate (WTI) crude oil spot prices and Henry Hub (HH) natural gas spot prices.

Average Monthly Oil & Gas Prices for 2011 to 2006 (1)

(1) The spot prices here generally correspond to the average price realized by each company before netting the effect of derivatives hedging. Some companies seem to continually receive higher prices than others, but the relative movement year-after-year is similar.

The preferred way to pay debt service is from operating cash flow but prolonged low sale prices can cause operating cash flow to decline after hedges expire. Marginal operating cash flow is not an immediate issue if a company carries an adequate amount of cash to service debt or maintain basic operations if oil and gas prices drop below the break-even point. (See ”Break-even Oil & Gas Prices and Break-even Costs” below). Some oil and gas companies, however, carry little of their total assets in cash and have little cushion to protect against adverse events (See table below: “Debt Servicing Ability by Cash and Liquid Assets.”).

A cash reserve deficiency can be countered by very stable operating cash flow. That is why utility companies, for example, can safely carry very large amounts of debt that would not be safe for the typical company. In the event of a major price decline, O&G companies that have inadequate cash reserves could be forced to service debt rather than replenishing reserves lost through depletion, which could result in an impairment of value. A more severe consequence would be a near-term funding shortfall. If debt service can’t be paid from operating cash flow or cash reserves, it may become necessary to sell long-term assets, but a decline of oil and gas prices would decrease the amount a company could liquidate those assets for. The result could be very problematic.

D. Comparison of Financial Condition

The tables below compare the ability of the 15 oil and gas companies (the “Peer Group”) to service debt interest and principal from cash flow, cash reserves, and liquid assets. The formulas used to calculate these ratios can be found below the first table, “Financial Condition Ratios for 2011”. The data seems to indicate that there are significant differences in the ability of the companies to service debt in the event of a protracted period of low oil and/or gas prices.

 

Financial Condition Ratios for 2011 (2) (3) (4)

(2) Chesapeake has the unusual practice of capitalizing nearly all (around 92%) of its interest charges from debt, making it appear much financially stronger than it really is. On average the other companies capitalize 25% of their interest charges.

(3) Newfield recently issued $1 billion of debt at a yield of 5.625%. This increases its 2011 debt to equity ratio to 102.2% (97% based on Q1 2012 data) and lowers its 2011 EBIT TIE ratio to 4.63 and its 2011 EBITDA TIE ratio to 7.95.

(4) The “overall Peer Group average” calculates the same ratio for its column except it uses the sum figures of the group (rather than taking the arithmetical average of the ratio calculated for each company, which can be distorted by outliers). The “median of ratios” is just the median of the calculated ratios. The downside of the average is that it gives greater weight to larger companies; the median is calculated and presented as an alternative.

 

 

Financial Condition Ratios 2006 through 2011 (6 year averages)

The worst year for these companies was 2009, when they felt the impact of the rapid decline in oil and gas prices. In addition, the cost structure of several companies was higher as they pursued unconventional projects. The ratios for 2009 are below:

 

 

Financial Condition Ratios for the Year 2009

 

 

Debt Servicing Ability by Cash and Liquid Assets

 

E. Break-even Oil & Gas Prices and Break-even Costs

The gas predominant companies seem to have adequate debt servicing abilities when gas prices are in the $3.50 to $4.00 range, but at $3.00 or less they are tight. The oil predominant companies seem to experience pressure when oil prices fall to the $75 range. This gives evidence to the notion, I think, that if prices fall below these marks at the current cost structure, then the independent E&P companies will be incentivized to cut new exploration and development expenditures, thereby reducing supply.

The cost structure from 2008 to 2011 reflects industry adjustments to new operational requirements associated with unconventional production. Costs will probably decline in the future, and thus so will the breakeven price. The breakeven cost will also vary from basin to basin: the Marcellus Shale is known for having low costs – in part because of better economies of scale and a close proximity to its end-use markets – whereas oil sands production has relatively higher costs.

 

F. Relative Valuation

Valuation Multiples (5)

(5) Price data from Yahoo! Finance, using closing price data on July 13, 2012.

It seems that the market’s valuations of the Peer Group are based primarily on expectations of growth. Not much weight seems to be given to the risks undertaken to achieve that growth. In some cases growth is being achieved by utilizing a high percentage of debt financing. Normally, companies with a speculative capital structure are given a discount in the multiple as compared to equivalent companies that do not have a speculative capital structure. Among the 15 companies compared in this article, however, there seems not to be a noticeable association that can be attributed to the capitalization factor.

G. Concluding Thoughts

This article is not a complete analysis of the companies discussed. I cannot offer any definite conclusions as to which companies are speculatively capitalized, as simple statistical ratios cannot alone answer such questions. I think it is generally true, however, that companies with low liquid assets and a high level of debt are riskier. It is possible that some companies will be able to grow their way out of debt, but that level of analysis is beyond this article’s scope.

I am not an expert on each company mentioned in this article. If you have detailed knowledge of any of these companies, I would be grateful if you shared it in the comments section below for the benefit of everyone, or feel free to e-mail me. I have completed a 20 page analysis of Devon Energy Corporation that is available on my website.

 

Disclosure: Long position in Devon Energy (DVN)

H. Notes

Note 1:

The ratios are adjusted for impairments of proven oil and gas properties that are the result of “full cost ceiling” accounting, which practically means – although this is a gross oversimplification – that oil and gas companies must write off a portion of their assets when oil and gas prices fall by a large percentage.

Except for the affect on the cash flows of 2008-2010, companies were largely unaffected by the price volatility that caused the impairment. Although a significant portion of the impairment was warranted, especially for natural gas properties, the impairments have been added back to improve comparability among the companies.

In addition, the timing of the impairments among companies is different (most made the necessary impairments in 2008 and/or 2009, but some waited until 2010 or 2011, and some made several smaller write-offs over the whole period), so it is necessary to add the impairments back so the companies can be compared fairly.

Note 2:

The term “gross interest” is used to differentiate it from “net interest,” which subtracts interest income. Some oil and gas companies have little in cash and cash equivalents, and in those cases interest income is typically immaterial. In addition, the specific interest income is not even reported by some companies, which would reduce comparability if included.

Note 3:

The source of all data is the 10-k and 10-q statements of each company from the SEC database.

I. Raw Data Tables