Note 1 - Summary of Accounting Policies

Basis of Presentation

Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States. Our operations are considered to fall within a single industry segment, which are the acquisition, development, exploitation and production of crude oil properties in the United States. Our consolidated financial statements include our wholly owned subsidiaries and our majority owned subsidiary Rantoul Partners (through December 31, 2012).

Rantoul Partners was formed in 2011 by our contribution of certain oil assets totaling $2,282,918 to the partnership for 100% ownership in the entity. The assets were valued at their historic cost which approximated market. In 2011 Rantoul Partners sold 11.75% of the partnership to 2 investors for $2,350,000. 11.75% of the book value of Rantoul Partners after the investment by non-controlling entities was $544,368. The difference between the investment amount ($2,350,000) and the book value bought ($544,368) is accretive to EnerJex in the amount of $1,805,632. This amount was recorded as EnerJex paid in capital. In 2012 an additional $2,650,000 was invested by the two non-controlling owners for an additional 13.75% ownership (bringing their total to 25%). 13.75% of the book value of Rantoul Partners after the additional investments by the non-controlling entities was $1,229,541. The difference between the investment amount ($2,650,000) and the book value bought ($1,229,541) is accretive to Enerjex in the amount of $1,420,459. This amount was recorded as paid in capital.

On December 31, 2012 Rantoul Partners was liquidated. At the time of liquidation we owned 75% of Rantoul Partners and 75% of the working interest of Rantoul Partners. We received 75% of the net assets less liabilities of Rantoul Partners that totaled approximately $4,792,380 and a 75% working interest in the oil properties of Rantoul Partners. The non-controlling owners of Rantoul Partners received 25% of the assets less liabilities ($1,597,461) and 25% of the working interest in the properties of Rantoul Partners.

All significant intercompany balances and transactions have been eliminated upon consolidation. Certain reclassifications have been made to the prior year financial statements to conform to the current year presentation.

Nature of Business

We are an independent energy company engaged in the business of producing and selling crude oil. This crude oil is obtained primarily by the acquisition and subsequent exploration and development of mineral leases. Development and exploration may include drilling new exploratory or development wells on these leases. These operations are conducted primarily in Eastern Kansas and South Texas.

Use of Estimates in the Preparation of Financial Statements

The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates included in the consolidated financial statements are: (1) oil revenues and reserves; (2) depreciation, depletion and amortization; (3) valuation allowances associated with income taxes (4) accrued assets and liabilities; (5) stock-based compensation; (6) asset retirement obligations and (7) valuation of derivative instruments. Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates. Actual results could differ from those estimates.

Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear any interest. We regularly review receivables to insure that the amounts will be collected and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. There were no reserves for uncollectible amounts in the periods presented.

Share-Based Payments

The value we assign to the options and warrants that we issue is based on the fair market value as calculated by the Black-Scholes pricing model. To perform a calculation of the value of our options and warrants, we determine an estimate of the volatility of our stock. We need to estimate volatility because there has not been enough trading of our stock to determine an appropriate measure of volatility. We believe our estimate of volatility is reasonable, and we review the assumptions used to determine this whenever we issue a new equity instruments.

Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets arise when expenses are recognized in the financial statements before the tax returns or when income items are recognized in the tax return prior to the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Deferred tax liabilities arise when income items are recognized in the financial statements before the tax returns or when expenses are recognized in the tax return prior to the financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was enacted.

We routinely assess the reliability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset is reduced by a valuation allowance. In addition we routinely assess uncertain tax positions, and accrue for tax positions that are not more-likely-than-not to be sustained upon examination by taxing authorities.

Uncertain Tax Positions

We follow guidance in Topic 740 of the Codification for its accounting for uncertain tax positions. Topic 740 prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. To recognize a tax position, we determine whether it is more-likely-than-not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based solely on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement.

We have no liability for unrecognized tax benefits recorded as of December 31, 2012 and 2011. Accordingly, there is no amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there is no amount of interest or penalties currently recognized in the statement of operations or statement of financial position as of December 31, 2012. In addition, we do not believe that there are any positions for which it is reasonably possible that the total amounts of unrecognized tax benefits will significantly increase or decrease within the next twelve months. We recognize related interest and penalties as a component of income tax expense.

Tax years open for audit by federal tax authorities as of December 31, 2012 are the years ended December 31, 2009, 2010, 2011 and 2012. Tax years ending prior to 2009 are open for audit to the extent that net operating losses generated in those years are being carried forward or utilized in an open year.

Fair Value Measurements

Accounting guidance establishes a single authoritative definition of fair value based upon the assumptions market participants would use when pricing an asset or liability and creates a fair value hierarchy that prioritizes the information used to develop those assumptions. Additional disclosures are required, including disclosures of fair value measurements by level within the fair value hierarchy. We incorporate a credit risk assumption into the measurement of certain assets and liabilities

Cash and Cash Equivalents

We consider all highly liquid investment instruments purchased with original maturities of three months or less to be cash equivalents for purposes of the consolidated statements of cash flows and other statements. We maintain cash on deposit, which, at times, exceed federally insured limits. We have not experienced any losses on such accounts and believe we are not exposed to any significant credit risk on cash and equivalents.

Revenue Recognition

Oil revenues are recognized net of royalties when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collection of the revenue is probable. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met.

Property and Equipment

Property and equipment are recorded at cost. Depreciation is on a straight-line method using the estimated lives of the assets. (3-15 years). Expenditures for maintenance and repairs are charged to expense.

Debt issue costs

Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt on the straight-line method of amortization over the estimated life of the debt.

Oil Properties

We follow the full-cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities.

Proved properties are amortized using the units of production method (UOP). Currently we only have operations in the Unites States of America. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the cost of these reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (DD&A), estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs, less related salvage value.

The cost of unproved properties are excluded from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until development projects are placed into service. Geological and geophysical costs not associated with specific properties are recorded to proved property immediately. Unproved properties are reviewed for impairment quarterly.

Under the full-cost-method of accounting, the net book value of oil properties, less deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is (a) the present value of future net revenues computed by applying current prices of oil & gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil & gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of 10 percent and assuming continuation of existing economic conditions plus (b) the cost of properties not being amortized plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized less (d) income tax effects related to differences between book and tax basis of properties. Future cash outflows associated with settling accrued retirement obligations are excluded from the calculation. Estimated future cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months held flat for the life of the production, except where prices are defined by contractual arrangements.

Any excess of the net book value of proved oil properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the statement of operations. The ceiling calculation is performed quarterly. During the years ended December 31, 2012 and 2011 there were no impairments resulting from the quarterly ceiling tests.

Proceeds from the sale or disposition of oil properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25%) of our reserve quantities are sold, in which case a gain or loss is recognized in income.

Long-Lived Assets

Impairment of long-lived assets is recorded when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying value. The carrying value of the assets is then reduced to their estimated fair value that is usually measured based on an estimate of future discounted cash flows.

Asset Retirement Obligations

The asset retirement obligation relates to the plug and abandonment costs when our wells are no longer useful. We determine the value of the liability by obtaining quotes for this service and estimate the increase we will face in the future. We then discount the future value based on an intrinsic interest rate that is appropriate for us. If costs rise more than what we have expected there could be additional charges in the future, however, we monitor the costs of the abandoned wells and we will adjust this liability if necessary.

Major Purchasers

For the years ended December 31, 2012, and 2011 we sold all of our produced oil to Coffeyville Resources, Plains Marketing, L.P., and Sunoco, Inc. on a month-to-month basis.

Marketable Securities Available for Sale

The Company classifies its marketable equity securities as available-for-sale and they are carried at fair market value, with the unrealized gains and losses included in accumulated other comprehensive income and reported in stockholders’ equity. The difference between cost and market totals $552,589 for the years ended December 31, 2012 and 2011.

Reclassifications

Certain reclassifications have been made to prior periods to conform to current presentations.

Recent Accounting Pronouncements Applicable to the Company

The Company does not believe there are any recently issued, but not yet effective; accounting standards that would have a significant impact on the Company’s financial position or results of operations.

Nevada		88-0422242
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

4040 Broadway
Suite 508
San Antonio, Texas		78209
(Address of principal executive offices)		(Zip Code)

Large accelerated filer ¨	Accelerated filer ¨

Non-accelerated filer ¨ (Do not check if a smaller reporting company)	Smaller reporting company x

		Page
PART I		5
ITEMS 1 AND 2.	BUSINESS AND PROPERTIES	5
ITEM 1A.	RISK FACTORS	18
ITEM 1B.	UNRESOLVED STAFF COMMENTS	31
ITEM 3.	LEGAL PROCEEDINGS	31
PART II		31
ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	31
ITEM 6.	SELECTED FINANCIAL DATA	33
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	33
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	37
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	38
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	38
ITEM 9A	CONTROLS AND PROCEDURES	38
ITEM 9B.	OTHER INFORMATION	38
Part III		38
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	38
ITEM 11.	EXECUTIVE COMPENSATION	42
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	44
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	45
ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	45
Part IV		46
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	46

	·	inability to attract and obtain additional development capital;
	·	inability to achieve sufficient future sales levels or other operating results;
	·	inability to efficiently manage our operations;
	·	effect of our hedging strategies on our results of operations;
	·	potential default under our secured obligations or material debt agreements;
	·	estimated quantities and quality of oil reserves;
	·	declining local, national and worldwide economic conditions;
	·	fluctuations in the price of oil;
	·	continued weather conditions that impact our abilities to efficiently manage our drilling and development activities;
	·	the inability of management to effectively implement our strategies and business plans;
	·	approval of certain parts of our operations by state regulators;
	·	inability to hire or retain sufficient qualified operating field personnel;
	·	increases in interest rates or our cost of borrowing;
	·	deterioration in general or regional (especially Eastern Kansas and South Texas) economic conditions;
	·	adverse state or federal legislation or regulation that increases the costs of compliance, or adverse findings by a regulator with respect to existing operations;
	·	the occurrence of natural disasters, unforeseen weather conditions, or other events or circumstances that could impact our operations or could impact the operations of companies or contractors we depend upon in our operations;
	·	inability to acquire mineral leases at a favorable economic value that will allow us to expand our development efforts; and
	·	changes in U.S. GAAP or in the legal, regulatory and legislative environments in the markets in which we operate.

	·	On March 30, 2012, we amended the Rantoul Partners General Partnership Agreement to provide for the accelerated funding of capital commitments from one of the general partners, among other things. The general partner funded capital commitments of $1,000,000 on April 1, 2012, $1,000,000 on May 1, 2012, and $650,000 on December 1, 2012.

	·	On July 10, 2012, we entered into transactions in which we hedged an additional 45,000 barrels of oil and replaced an existing oil hedge that consisted of 27,600 barrels of oil at a price of $62.20. This was completed pursuant to our fixed price swap agreement with BP Corporation North America, Inc. Following this transaction, our outstanding hedges were as follows:

x	ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

¨	TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Period of Time	Barrels Per Month		Average Oil Price
July - December 2012		5,600	$	82.39
January - December 2013		4,900	$	80.00
January - December 2014		4,450	$	80.26
January - December 2015		4,000	$	81.96

	·	Numerous Acquisition Opportunities in Fragmented Markets. The exploration and production business in Eastern Kansas is highly fragmented and consists of many small operators that operate producing oil properties on relatively small budgets. Consequently, numerous acquisition opportunities with drilling and expansion potential exist in the area.

	·	Opportunity to Enhance Operational Efficiency of Mature Leases. Many potential acquisition targets include significant opportunities for enhanced operational efficiencies and increased ultimate recoveries of oil through the application of modern engineering technologies, professional approaches to reservoir engineering and operations management, and the potential application of a number of enhanced oil recovery technologies.

	·	Opportunity to Reduce Operating Costs per Barrel Through Economies of Scale. A significant portion of expenses at the field level are fixed (primarily labor and equipment). These costs are scalable, and lease operating expenses per barrel may be significantly reduced by increasing production in current areas of operation by drilling low risk development wells, acquiring producing properties in close proximity to existing operations, and utilizing modern enhanced oil recovery technologies.

	·	Large Oil Reserves in Place and Relatively Low Exploration Risk. A majority of the oil reserves in Eastern Kansas are present at relatively shallow horizons (most at a depth of less than 3,000 feet) and contain significant volumes of oil in place. These shallow reservoirs often have relatively low reservoir pressure and lack a strong natural drive mechanism. As a result, the ultimate recovery of oil in place can be significantly increased through the application of secondary recovery technologies.

Project Name	Developed Acreage				Undeveloped Acreage				Total Acreage
	Gross		Net ⁽¹⁾		Gross		Net ⁽¹⁾		Gross		Net ⁽¹⁾
Mississippian Project		2,840		2,556		0		0		2,840		2,556
Cherokee Project		2,419		1,680		7,875		7,050		10,293		8,730
Other		904		874		00		00		904		874
Total		6,163		5,110		7,875		7,050		14,037		12,160

	·	Develop Our Existing Properties. Creating production, cash flow, and reserve growth by developing our extensive inventory of hundreds of drilling locations that we have identified in our existing properties.

	·	Maximize Operational Control. We seek to operate and maintain a substantial working interest in the majority of our properties. We believe the ability to control our drilling inventory will provide us with the opportunity to more efficiently allocate capital, manage resources, control operating and development costs, and utilize our experience and knowledge of oilfield technologies.

	·	Pursue Selective Acquisitions and Joint Ventures. We believe our local presence in Eastern Kansas and South Texas makes us well-positioned to pursue selected acquisitions and joint venture arrangements.

	·	Reduce Unit Costs Through Economies of Scale and Efficient Operations. As we increase our oil production and develop our existing properties, we expect that our unit cost structure will benefit from economies of scale. In particular, we anticipate reducing unit costs by greater utilization of our existing infrastructure over a larger number of wells.

	·	our ability to source and evaluate potential projects;

	·	our ability to discover commercial quantities of oil;

	·	the market price for oil;

	·	our ability to implement our exploration and development program, which is in part dependent on the availability of capital resources; and

	·	our ability to cost effectively manage our operations.

Drilling Activity
	Gross Wells						Net Wells ⁽¹⁾
Fiscal Year	Total		Successful		Dry		Total		Successful		Dry

2011 - Exploratory		6		0		6		3.4		0		3.4
2012 - Exploratory		-2-		-0-		-2-		-1.8-		-0-		-1.8-

2011 - Development		97		97		0		79.3		79.3		0
2012 - Development		227		226		1		172.6		171.7		0.9

	Year Ended December 31, 2012		Year Ended December 31, 2011
Net Production
Oil (Bbl)		96,842		71,729
Average Sales Prices
Per Bbl of oil	$	87.74	$	87.63
Average Production Cost ⁽¹⁾
Per Bbl of oil	$	47.95	$	63.77
Average Lifting Costs ⁽²⁾
Per Bbl of oil	$	32.03	$	47.96

	Year Ended December 31, 2012			Year Ended December 31, 2011
Production revenues	$	8,496,519		$	6,285,411
Production costs		(3,102,321	)		(3,440,228	)
Depreciation, depletion and amortization		(1,541,069	)		(1,128,712	)
Results of operations for producing activities	$	3,853,129		$	1,716,471

	Active
Project	Gross Oil		Net Oil ⁽¹⁾
El Toro Project		12		4.8
Mississippian Project		173		155.7
Cherokee Project		552		410.5
Other		125		109.8
Total		862		680.8

Proved Reserves Category	Gross STB ⁽¹⁾		Net STB ⁽²⁾		PV10 ⁽³⁾ (before tax)
Proved, Developed Producing		2,398,400		1,546,300		34,737,900
Proved, Undeveloped		1,951,600		1,380,800		26,108,400
Total Proved		4,350,000		2,927,100		60,846,300

	(1)	STB = one stock-tank barrel.
	(2)	Net STB is based upon our net revenue interest, including any applicable reversionary interest.
	(3)	See "Glossary" on page 17 for our definition of PV10 and "Management's Discussion and Analysis of Financial Condition and Results of Operations-Reserves" page 33 for a reconciliation to the comparable GAAP financial measure.

	·	require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities;

	·	limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and

	·	impose substantial liabilities for pollution resulting from its operations, or due to previous operations conducted on any leased lands.

Term		Definition

Barrel (Bbl)		The standard unit of measurement of liquids in the petroleum industry, it contains 42 U.S. standard gallons. Abbreviated to "bbl".

Basin		A depression in the crust of the Earth, caused by plate tectonic activity and subsidence, in which sediments accumulate. Sedimentary basins vary from bowl-shaped to elongated troughs. Basins can be bounded by faults. Rift basins are commonly symmetrical; basins along continental margins tend to be asymmetrical. If rich hydrocarbon source rocks occur in combination with appropriate depth and duration of burial, then a petroleum system can develop within the basin.

BOPD		Abbreviation for barrels of oil per day, a common unit of measurement for volume of crude oil. The volume of a barrel is equivalent to 42 U.S. standard gallons.

Carried Working Interest		The owner of this type of working interest in the drilling of a well incurs no capital contribution requirement for drilling or completion costs associated with a well and, if specified in the particular contract, may not incur capital contribution requirements beyond the completion of the well.

Completion/Completing		A well-made ready to produce oil.

Development		The phase in which a proven oil field is brought into production by drilling development wells.

Development Drilling		Wells drilled during the Development phase.

Division Order		A directive signed by the royalty owners verifying to the purchaser or operator of a well the decimal interest of production owned by the royalty owner and other working interest owners. The Division Order generally includes the decimal interest, a legal description of the property, the operator's name, and several legal agreements associated with the process. Completion of this step generally precedes placing the royalty owner or working interest owner on pay status to begin receiving revenue payments.

Drilling		Act of boring a hole through which oil may be produced.

Dry Wells		A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Exploration		The phase of operations which covers the search for oil generally in unproven or semi-proven territory.

Exploratory Drilling		Drilling of a relatively high percentage of properties which are unproven.

Farm Out		An arrangement whereby the owner of a lease assigns all or some portion of the lease or licenses to another company for undertaking exploration or development activity.

Field		An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Fixed Price Swap		A derivative instrument that exchanges or "swaps" the "floating" or daily price of a specified volume of oil over a specified period, for a fixed price for the specified volume over the same period (typically three months or longer).

Gathering Line/System		Pipelines and other facilities that transport oil from wells and bring it by separate and individual lines to a central delivery point for delivery into a transmission line or mainline.

Gross Acre		The number of acres in which the Company owns any working interest.

Gross Producing Well		A well in which a working interest is owned and is producing oil. The number of gross producing wells is the total number of wells producing oil in which a working interest is owned.

Gross Well		A well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned.

Held-By-Production (HBP)		Refers to an oil property under lease, in which the lease continues to be in force, because of production from the property.

Horizontal drilling		A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then turned and drilled horizontally. Horizontal drilling allows the wellbore to follow the desired formation.

In-Fill Wells		In-fill wells refers to wells drilled between established producing wells; a drilling program to reduce the spacing between wells in order to increase production and recovery of in-place hydrocarbons.

Oil Lease		A legal instrument executed by a mineral owner granting the right to another to explore, drill, and produce subsurface oil. An oil lease embodies the legal rights, privileges and duties pertaining to the lessor and lessee.

Lifting Costs		The expenses of producing oil from a well. Lifting costs are the operating costs of the wells including the gathering and separating equipment. Lifting costs do not include the costs of drilling and completing the wells or transporting the oil.

Net Acres		Determined by multiplying gross acres by the working interest that the Company owns in such acres.

Net Producing Wells		The number of producing wells multiplied by the working interest in such wells.

Net Revenue Interest		A share of production revenues after all royalties, overriding royalties and other nonoperating interests have been taken out of production for a well(s).

Operator		A person, acting for itself, or as an agent for others, designated to conduct the operations on its or the joint interest owners' behalf.

Overriding Royalty		Ownership in a percentage of production or production revenues, free of the cost of production, created by the lessee, company and/or working interest owner and paid by the lessee, company and/or working interest owner out of revenue from the well.

Pooled Unit		A term frequently used interchangeably with "Unitization" but more properly used to denominate the bringing together of small tracts sufficient for the granting of a well permit under applicable spacing rules.

Probable Reserves		Probable reserves are additional reserves that are less certain to be recovered than proved reserves but which, together with Proved reserves, are as likely as not to be recovered.

Proved Developed Reserves		Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. This definition of proved developed reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

Proved Developed Non-Producing		Proved developed reserves expected to be recovered from zones behind casings in existing wells or from future production increases resulting from the effects of waterflood operations.

Proved Reserves		Proved reserves are estimated quantities of crude oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved Undeveloped Reserves		Proved undeveloped reserves are the portion of proved reserves which can be expected to be recovered from new wells on undrilled proved acreage, or from existing wells where a relatively major expenditure is required for completion. This definition of proved undeveloped reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

PV10		PV10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV10 is a non-GAAP financial measure. See "Management's Discussion and Analysis of Financial Condition and Results of Operations-Reserves" on page 33 for a reconciliation to the comparable GAAP financial measure.

Re-completion		Completion of an existing well for production from one formation or reservoir to another formation or reservoir that exists behind casing of the same well.

Reservoir		The underground rock formation where oil has accumulated. It consists of a porous rock to hold the oil, and a cap rock that prevents its escape.

Reservoir Pressure		The pressure at the face of the producing formation when the well is shut-in. It equals the shut-in pressure at the wellhead plus the weight of the column of oil in the well.

Secondary Recovery		The stage of hydrocarbon production during which an external fluid such as water or natural gas is injected into the reservoir through injection wells located in rock that has fluid communication with production wells. The purpose of secondary recovery is to maintain reservoir pressure and to displace hydrocarbons toward the wellbore. The most common secondary recovery techniques are natural gas injection and waterflooding. Normally, natural gas is injected into the natural gas cap and water is injected into the production zone to sweep oil from the reservoir. A pressure-maintenance program can begin during the primary recovery stage, but it is a form of enhanced recovery.

Shut-In Well		A well which is capable of producing but is not presently producing. Reasons for a well being shut-in may be lack of equipment, market or other.

Stock Tank Barrel or STB		A stock tank barrel of oil is the equivalent of 42 U.S. Gallons at 60 degrees Fahrenheit.

Undeveloped Acreage		Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil regardless of whether such acreage contains proved reserves.

Unitize, Unitization		When owners of oil reservoir pool their individual interests in return for an interest in the overall unit.

Waterflood		The injection of water into an oil reservoir to "push" additional oil out of the reservoir rock and into the wellbores of producing wells. Typically a secondary recovery process.

Water Injection Wells		A well in which fluids are injected rather than produced, the primary objective typically being to maintain or increase reservoir pressure, often pursuant to a waterflood.
Water Supply Wells		A well in which fluids are being produced for use in a water injection well.

Wellbore		A borehole; the hole drilled by the bit. A wellbore may have casing in it or it may be open (uncased); or part of it may be cased, and part of it may be open. Also called a borehole or hole.

Working Interest		An interest in an oil lease entitling the owner to receive a specified percentage of the proceeds of the sale of oil production or a percentage of the production, but requiring the owner of the working interest to bear the cost to explore for, develop and produce such oil.

	·	the future prices of oil;
	·	our ability to raise adequate capital;
	·	success of our development and exploration efforts;
	·	our ability to manage our operations cost effectively
	·	effects of our hedging strategies;
	·	demand for oil;
	·	the level of our competition;
	·	our ability to attract and maintain key management, employees and operators;
	·	transportation and processing fees on our facilities;
	·	fuel conservation measures;
	·	alternate fuel requirements or advancements;
	·	government regulation and taxation;
	·	technical advances in fuel economy and energy generation devices; and
	·	our ability to efficiently explore, develop and produce sufficient quantities of marketable oil in a highly competitive and speculative environment while maintaining quality and controlling costs.

	·	Commodities speculators;
	·	local, national and worldwide economic conditions;
	·	worldwide or regional demand for energy, which is affected by economic conditions;
	·	the domestic and foreign supply of oil;
	·	weather conditions;
	·	natural disasters;
	·	acts of terrorism;
	·	domestic and foreign governmental regulations and taxation;
	·	political and economic conditions in oil producing countries, including those in the Middle East and South America;
	·	impact of the U.S. dollar exchange rates on oil prices;
	·	the availability of refining capacity;
	·	actions of the Organization of Petroleum Exporting Countries, or OPEC, and other state controlled oil companies relating to oil price and production controls; and
	·	the price and availability of other fuels.

	·	geological conditions;
	·	assumptions governing future oil prices;
	·	amount and timing of actual production;
	·	availability of funds;
	·	future operating and development costs;
	·	actual prices we receive for oil;
	·	changes in government regulations and taxation; and
	·	capital costs of drilling new wells

	·	unexpected operational events and/or conditions;
	·	reductions in oil prices;
	·	limitations in the market for oil;
	·	adverse weather conditions;
	·	facility or equipment malfunctions;

	·	title problems;
	·	oil quality issues;
	·	pipe, casing, cement or pipeline failures;
	·	natural disasters;
	·	fires, explosions, blowouts, surface cratering, pollution and other risks or accidents;
	·	environmental hazards, such as oil spills, pipeline ruptures and discharges of toxic gases;
	·	compliance with environmental and other governmental requirements; and
	·	uncontrollable flows of oil or well fluids

	·	injury or loss of life;
	·	severe damage to and destruction of property, natural resources and equipment;
	·	pollution and other environmental damage;
	·	clean-up responsibilities;
	·	regulatory investigation and penalties;
	·	suspension of our operations; and
	·	repairs to resume operations

	·	unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
	·	unable to obtain financing for these acquisitions on economically acceptable terms; or
	·	outbid by competitors.

	·	higher than projected operating costs;
	·	lower-than-expected production;
	·	longer response times;
	·	higher costs associated with obtaining capital;
	·	unusual or unexpected geological formations;
	·	fluctuations in oil prices;
	·	regulatory changes;
	·	shortages of equipment; and
	·	lack of technical expertise.

	·	the validity of our assumptions about reserves, future production, revenues and costs, including synergies;
	·	an inability to integrate successfully the businesses we acquire;
	·	a decrease in our liquidity by using our available cash or borrowing capacity to finance acquisitions;
	·	a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
	·	the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;

	·	the diversion of management's attention from other business concerns;
	·	an inability to hire, train or retain qualified personnel to manage the acquired properties or assets;
	·	the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges;
	·	unforeseen difficulties encountered in operating in new geographic or geological areas; and
	·	customer or key employee losses at the acquired businesses.

	·	location and density of wells;
	·	the handling of drilling fluids and obtaining discharge permits for drilling operations;
	·	accounting for and payment of royalties on production from state, federal and Indian lands;
	·	bonds for ownership, development and production of oil properties;
	·	transportation of oil by pipelines;
	·	operation of wells and reports concerning operations; and
	·	taxation.

	·	being forced to use cash flow to reduce our outstanding balance as a result of an unfavorable borrowing bas redetermination;
	·	our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service our indebtedness;
	·	increasing our vulnerability to general adverse economic and industry conditions;
	·	placing us at a competitive disadvantage as compared to our competitors that have less leverage;
	·	our ability to capitalize on business opportunities and to react to competitive pressures and changes in government regulation;
	·	our ability to, or increasing the cost of, refinancing our indebtedness; and
	·	our ability to enter into marketing, hedging, optimization and trading transactions by reducing the number of counterparties with whom we can enter into such transactions as well as the volume of those transactions.

	·	incur additional indebtedness and provide additional guarantees;
	·	pay dividends and make other restricted payments;
	·	create or permit certain liens;
	·	use the proceeds from the sales of our oil properties;
	·	use the proceeds from the unwinding of certain financial hedges;
	·	engage in certain transactions with affiliates; and
	·	consolidate, merge, sell or transfer all or substantially all of our assets or the assets of our subsidiaries.