Investors looking for publicly traded natural gas companies to purchase are presented with a confusing amount of information that is particular to this industry. This can present a roadblock to understanding and analyzing the sector. Here are some explanations of some common concepts and terms that investors should know.

TUTORIAL: Commodities

Reserves are a general term that refers to the amount of natural gas and other hydrocarbons that a company has present on its properties. The industry categorizes these hydrocarbons as either proved, probable or possible reserves.

The most important category of reserves are proved reserves, which are defined as natural gas and other hydrocarbons that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under current economic methods, government regulations, and operating conditions. The economics of the proved reserves must be determined using a 12-month average price using the price on the first day of each of the preceding 12 months.

Many natural gas companies will also present in marketing materials the amount of proved reserves using different prices than the ones mandated by the regulatory authorities. Investors should be conscious of what prices are used to calculate proved reserves when comparing different companies to each other.

Natural gas companies also have the option of disclosing the amount of probable or possible reserves to investors in regulatory filings, but since both these categories are less certain, investors should not rely on them too heavily. (How a company accounts for its expenses affects how its net income and cash flow numbers are reported. Check out Accounting For Differences In Oil And Gas Accounting.)

Reserves to Production Ratio
The reserves to production ratio is a measure of the length of time it would take for a natural gas company to produce all of its proved reserves. The ratio is expressed in years and a higher ratio is generally better. Whiting Petroleum (NYSE:WLL) reported a reserves to production ratio of 13.9 years at the end of 2009. This is based on proved reserves of 275 million BOE and 2009 production of approximately 19.7 million barrels. This is an unrealistic static measure in some ways as a natural gas company is constantly adding to its proved reserves, and like all metrics this should be looked at in the context of other factors.

Basis Differentials
Basis differentials refer to the regional price discounts that some operators experience when they sell natural gas into the market. These discounts are caused by many factors including the weather, natural gas pipeline capacity, regional demand and the quality of the hydrocarbons. Ultra Petroleum (NYSE:UPL), which is a major producer of natural gas in Wyoming, sells its production into a hub in the Rocky Mountain area. In 2009, the company received an average of 77% of the price of natural gas sold into the Henry Hub in Louisiana.

Production is a measure of the amount of natural gas or other hydrocarbons that are produced from wells that a natural gas company has interests in. Since crude oil and natural gas liquids are measured in barrels, and natural gas is measured in cubic feet, there must be a way to convert each hydrocarbon to a standardized form of measurement so that the total production of a company can be analyzed.

The natural gas industry uses a measure called natural gas equivalents to convert any crude oil and natural gas liquids production. Each barrel of crude oil or natural gas liquids is converted to natural gas equivalents using a ratio of one barrel to six thousand cubic feet of natural gas produced. Here is an example of a conversion from Range Resources (NYSE:RRC) for 2009:

Type Original Converted
Natural Gas (Cubic Feet) 130,649,000,000 130,649,000,000
Crude Oil (Barrels) 2,557,000 6,000 15,342,000,000
Natural Gas Liquids (Barrels) 2,187,000 6,000 13,122,000,000
Natural Gas Equivalents 159,113,000,000
Range Resources produced 130.65 billion cubic feet of natural gas in 2009. The company also produced 2.6 million barrels of crude oil and 2.2 million barrels of natural gas liquids. After converting these oil and liquids at the 6,000 to 1 ratio, Range Resources produced 159.12 billion cubic feet of natural gas equivalents.

Natural gas companies also hedge production using collars, swaps, puts and other derivatives. This is done to reduce the volatility of cash flows associated with selling a commodity. Natural gas companies usually present this information in marketing presentations. In 2010, for example, Petrohawk Energy (NYSE:HK), hedged 62% of its estimated 2011 production, and 24% of its estimated 2012 production. (Find out how to stay on top of data reports that could cause volatility in these markets. See Become An Oil And Gas Futures Detective.)

Natural gas companies like to present a non-GAAP measure called EBITDAX when they report quarterly earnings. EBITDAX is an acronym that means earnings before interest, taxes, depreciation, amortization and exploration expenses. Some companies also exclude property impairments and non-cash equity compensation expense when presenting this measure. Here's an example of how Continental Resources (NYSE:CLR) calculated EBIITDAX in the first quarter of 2010.

Net income (loss) $72,465
Unrealized oil derivative gain $(19,676)
Income tax expense (benefit) $44,410
Interest expense $8,360
Depreciation, depletion, amortization and accretion $52,587
Property impairments $15,175
Exploration expense $1,786
Equity compensation $2,852
EBITDAX $177,959
There's nothing wrong with looking at this measure as long as an investor understands that this is not the equivalent of free cash flow, and it should be looked at within the context of other metrics.

Finding and Development Costs
Natural gas companies also present finding and development costs as a metric to judge the company's ability to find oil and natural gas reserves at a reasonable cost. These finding and development costs are presented as a unit of reserves found. Here is the calculation that EXCO Resources (NYSE:XCO) used for its finding and development costs in 2009:

Development and Exploration Expenses $299,837
Proved Reserves Added $242,056
Per Mcfe $1.24
EXCO Resources spent approximately $299 million to add 242 Bcfe of proves reserves, resulting in a drill bit finding and developing cost of $1.24 per Mcfe. Pay close attention to how this metric is calculated, as it will typically exclude revisions to reserves during the year and reserves acquired through acquisitions.

A natural gas company reports certain costs and expenses that are specific to the business that it is in, along with expenses typical of any business enterprise. These costs are usually expressed on a unit of production basis, or per thousand cubic feet equivalent (Mcfe). Here is an example from EOG Resources (NYSE:EOG) for 2009.

Type Per Mcfe
Lease and Well 75 cents
Transportation Costs 37 cents
DDA - Properties $1.89
DDA - Other 12 cents
Selling and Admin 32 cents
Interest 13 cents
Total $3.58
* DDA – Depreciation, Depletion and Amortization
This is not a comprehensive measure of all costs associated with the company, and can exclude things like gathering and processing costs, exploration costs or costs associated with dry holes.

Standardized Measure of Discounted Future Net Cash Flows
Another measure related to proved reserves is the Standardized Measure of Discounted Future Net Cash Flows from those proved reserves. A natural gas company calculates the revenues expected to be realized from the sale of those reserves when produced, and then subtracts the costs related to producing and developing the proved reserves. Taxes are then deducted from the total, and then the remaining cash flows are typically discounted using a 10% discount rate. (Learn how and why investors are using cash flow-based analysis to make judgments about company performance. Read Taking Stock Of Discounted Cash Flow.)

Here is an example of the calculation from Ultra Petroleum (NYSE:UPL) for 2009:

-- 2009
Future Cash Inflows $12,870,816
Future Production Costs $(3,916,222)
Future Development Costs $(2,249,993)
Future Income Taxes $(1,998,114)
Future Net Cash Flows $4,706,487
Discounted At 10% $(2,679,787)
Standardized Measure of $2,026,700
Discounted Future Net Cash Flows
Net Asset Value
Many investors determine a net asset value for a natural gas company and use the Standardized Measure of Discounted Future Net Cash Flows as a starting point for this calculation. The simplest method of calculating the net asset value is to take the Standardized Measure of Discounted Future Net Cash Flows and divide this by the amount of shares outstanding.

An analyst will typically make many adjustments to this calculation to make the result more realistic. These adjustments include using a different price for natural gas to determine future cash inflows, or adding in probable or possible reserves if they feel that these less certain reserves are likely to be realized. Another adjustment made is to deduct debt or working capital deficits from the numerator. The denominator is frequently adjusted to account for stock options and other dilutive securities.

Glossary of Natural Gas Terms

  • Development Well – A well drilled in a known producing area to an existing productive formation.
  • Exploratory Well – A well drilled to find a new natural gas or oil field or reservoir.
  • Gross Acres – The amount of lease acreage that a company has a working interest in.
  • Net Acres – Gross acreage multiplied by the percent working interest the company has in the lease.
  • Royalty Interest – An interest in a natural gas or oil well by an owner without having responsibility for the cost of production.
  • Working Interest – An interest in a natural gas or oil well that conveys the right to conduct operating activities on the well.

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