Callon Petroleum Co - FORM 10-K - EX-99.1

Attached files

file	filename
10-K - FORM 10-K - Callon Petroleum Co	h71486e10vk.htm
EX-4.6 - EX-4.6 - Callon Petroleum Co	h71486exv4w6.htm
EX-23.1 - EX-23.1 - Callon Petroleum Co	h71486exv23w1.htm
EX-32.2 - EX-32.2 - Callon Petroleum Co	h71486exv32w2.htm
EX-31.2 - EX-31.2 - Callon Petroleum Co	h71486exv31w2.htm
EX-32.1 - EX-32.1 - Callon Petroleum Co	h71486exv32w1.htm
EX-31.1 - EX-31.1 - Callon Petroleum Co	h71486exv31w1.htm
EX-23.3 - EX-23.3 - Callon Petroleum Co	h71486exv23w3.htm

Exhibit 99.1

Huddleston & Co., Inc.
Petroleum and Geological Engineers
1 Houston Center
1221 McKinney, Suite 3700
Houston, Texas 77010

PHONE (713) 209-1100 w FAX (713) 752-0828

February 24, 2010

Callon Petroleum Company
200 North Canal Street
Natchez, Mississippi 39120


Re:		Callon Petroleum Company Estimated Future Reserves and Revenues As of December 31, 2009

Gentlemen:

Pursuant to your request, we have estimated oil, condensate, and natural gas reserves and projected revenues for properties owned by Callon Petroleum Company. The properties are located in Louisiana, Texas, and in the federal waters of the Gulf of Mexico.

Our conclusions, as of December 31, 2009, follow:


	Net To Callon Petroleum Company*
	Proved Developed					Proved			Total
Constant Product Prices	Producing		Nonproducing			Undeveloped			Proved
Estimated Future Net Oil/Cond., Mbbl		2,100.3		2,245.6			2,132.8			6,478.7
Estimated Future Net (Sales) Gas, MMcf		9,322.1		2,979.2			6,801.3			19,102.6

Estimated Future Gross Revenue, $M		161,007.7		141,926.0			159,674.7			462,608.4
Estimated Future Operating Expenses, $M		56,239.3		76,741.2			25,502.8			158,483.3
Estimated Future Production Taxes, $M		2,855.1		142.3			2,531.0			5,528.3
Estimated Future Capital Costs, $M		16,469.4		16,133.6			49,291.3			81,894.3
Estimated Future Net Revenue (“FNR”), $M		85,443.9		48,908.9			82,349.6			216,702.5
Estimated FNR Discounted at 10%, $M		69,831.8		42,948.1			24,588.0			137,367.9

Projected Revenues by Year — Constant Product Prices, $M**

2010		43,696.1		(2,495.4	)		(14,971.4	)		26,229.4
2011		24,731.6		1,117.2			3,186.5			29,035.3
2012		7,070.0		11,127.7			3,894.7			22,092.4
Thereafter		9,946.2		39,159.4			90,239.8			139,345.4
Total		85,443.9		48,908.9			82,349.6			216,702.5

Estimated 2010 Production

Oil/Cond., Mbbl		759.9		6.5			51.6			818.1
Gas (Sales), MMcf		4,592.4		324.9			44.8			4,962.1


*		Numbers subject to rounding.

**		Certain negative values are attributable to operating cost allocation for the producing and nonproducing categories.

Callon Petroleum Company
February 24, 2010
Page Two

Report Preparation

Purpose of Report — The purpose of this report is to provide the management of Callon with a projection of future reserves and revenues for an assessment of oil and gas properties owned by Callon. The Proved reserve and revenue projections shown herein have been prepared in accordance with Securities and Exchange Commission (“SEC”) requirements for reporting purposes as described below. Although we have prepared projections of Probable and Possible reserves, it is our understanding that Callon has elected to exclude such reserve volumes for public reporting purposes.

Reporting Requirements — SEC Regulation S-K, Item 102, and Regulation S-X, Rule 4-10, require oil and gas reserve information to be reported by publicly held companies as supplemental financial data. These regulations were revised by the SEC effective for filings beginning January 1, 2010. The revised regulations provide for certain changes in Proved reserve definitions, add definitions for Probable and Possible reserves, and require that revenues associated with Proved reserves be reported on the basis of the average of the preceding 12-month, first-of-month product prices. Revenues are to be discounted at 10%, consistent with that required in prior years.

The Proved reserves included herein under “Constant Product Prices” have been prepared in accordance with our understanding of the methodologies specified under SEC and Financial Accounting Standards Board guidelines.

Standards of Practice — This report has been prepared in accordance with our understanding of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information as promulgated by the Society of Petroleum Engineers and the Guidelines for Application of the Definitions for Oil and Gas Reserves prepared by the Society of Petroleum Evaluation Engineers. However, the projected reserves have been prepared with consideration for reserve classification definitions specified by the SEC that do not necessarily conform to definitions promulgated by the Society of Petroleum Engineers and the World Petroleum Congress.

Definitions for reserves as outlined in SEC Regulation S-X, Rule 4-10 are included herein.

Economic Limits — In some cases the projections have been prepared with consideration for overall field production, resulting in negative cash flow projections for certain properties. In our opinion, the projections shown herein properly reflect the expected operations. The projections for some properties include consideration for abandonment costs, resulting in negative future revenues and discounted revenues.

Cash Flow Projections — The cash flow projections were run on the aries computer program utilizing Callon’s computer facilities. However, Huddleston & Co., Inc., supplied all of the input parameters for the reserve projections.

The attached cash flow projections have been sorted by reserve classification, then state, field, and lease. Properties located in federal waters have been grouped as “Gulf Federal”.

Cash Flow Presentation — The gross and net reserve volume columns in the cash flow projections have been separated into three different columns: oil (Mbbl), produced gas (MMcf), and sales gas (MMcf). Product prices, net revenues before taxes, and severance taxes are shown separately for each product.

Huddleston & Co., Inc.

Callon Petroleum Company
February 24, 2010
Page Three

Reserve Estimates

Extrapolation of performance history and material balance estimates were utilized for projecting future recoverable reserves for the producing properties where sufficient history was available to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to nonproducing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production.

Approximately 51% of the future net revenues discounted at 10% are included in the Proved Developed Producing category. The remaining 49% of discounted net revenues are included in the Nonproducing and Undeveloped classifications. Reserve estimates for those properties in the Nonproducing and Undeveloped categories will be subject to a significantly greater level of variation than estimates for producing properties exhibiting established decline trends.

We have utilized certain geologic and engineering data furnished by Callon. However, in all cases we have exercised the final judgments for the estimated reserves and future schedules of production.

Gas Volumes — Gas volumes are reported at the prevailing pressure base of the state in which the reserves are located and at 60 degrees Fahrenheit. The projections reflect gas streams for production gas and sales gas. The difference between the two is intended to reflect fuel and lease usage.

Property Descriptions

Mississippi Canyon 538/582 — The Medusa Prospect, drilled by Murphy on Mississippi Canyon Blocks 538 and 582 during 1999 and more fully delineated as a result of drilling conducted in 2000 and 2001, successfully tested a number of horizons in two separate fault blocks. Drilling operations conducted during 2002 resulted in certain minor revisions in geological interpretations and reserves were adjusted to reflect a revised study of geological and petrophysical characteristics. Reserve estimates for a total of 17 reservoirs, representing 11 horizons, have been based on volumetric calculations utilizing 3-D seismic data and subsurface control for mapping, as well as petrophysical calculations derived from well logs and sidewall cores.

Production operations for this property were initiated in November 2003 and there were 8 wellbores producing at the time of report preparation. The estimated reserves for those reservoirs completed in the existing wells have been revised from our original projections to reflect the performance of the wells to date. In some cases Nonproducing and Undeveloped reserve assignments have been adjusted to conform with the performance of the existing completions. On an overall basis the estimated ultimate oil reserves have been decreased 3.3% and gas reserves have been increased 6.6% in comparison to our previous report. The Medusa Prospect represents 68.1% and 17.1% of the oil and gas, respectively, net to Callon.

Undeveloped reserves projected for a sidetrack of the A-1 wellbore are scheduled to be developed upon depletion of reserves assigned to the existing well. We have been informed that the scheduling of development operations is the result of facilities limitations and cost considerations associated with drilling a separate wellbore.

Garden Banks 341 — The Habanero Prospect drilled by Shell during the first half of 1999 encountered two productive horizons: the Habanero 52 oil sand and the Habanero 55 gas sand. The productive horizons were also tested in a downdip, nonproductive sidetrack that allows for the calculation of hydrocarbon limits in both horizons. Proved reserves were assigned on the basis of information derived

Huddleston & Co., Inc.

Callon Petroleum Company
February 24, 2010
Page Four

from the two wellbores and supported by seismic interpretations. Additional drilling activities conducted during 2001 resulted in establishing the updip productive limits in both reservoirs and established a separate productive fault block in the Habanero 52 gas sand.

After being sidetracked to its current location in May 2003, production operations were initiated during November 2003 with the No. 2 well being completed in the Habanero 52 sand at a rate of 12,000 BOPD and 19 MMcf/day. In addition, the No. 1 was tested at a rate of 4,700 BOPD and 8.3 MMcf/day; however, the sliding sleeve separating the Habanero 52 and 55 sands was found to be in the open position resulting in the co-mingling of the two zones. A subsequent workover in the No. 1 wellbore resulted in a single completion in the Habanero 52 sand. We have been informed that the Habanero 55 sand is no longer mechanically able to be produced in the No. 1 well and the reserves for this horizon have been eliminated from our report.

The estimated reserves shown herein include consideration for two producing completions in the Habanero 52 oil sand, and two sidetrack locations to produce the Habanero 52 gas sand. Projected ultimate oil recoveries are unchanged and gas recoveries have been revised upward 3.2% to reflect well performance.

The undeveloped reserves for this property have been included in our projected reserves since 2001 and currently are scheduled to be developed at the depletion of the existing completions in 2014. We have been informed that it is the intention of the operator to sidetrack the existing wellbores to exploit these reserves. The timing of such operations is the result of physical facilities limitations and economic considerations with respect to both drilling operations for new wellbores and reconfiguration of the facilities.

On an overall basis the estimated reserves attributable to the Habanero Prospect represent 11.2% of the estimated Proved net oil and 24.8% of the Proved net gas for Callon. Approximately 60% of the oil reserves and 91% of the gas reserves for this property have been included in the Undeveloped category.

Wolfberry Properties — In 2009 Callon acquired ownership in four West Texas fields: Block 5, Carpe Diem, East Bloxum, and Kayleigh, located in Crockett, Midland, Upton, and Ector Counties, respectively. The subject properties are located within the Wolfberry trend. On an overall basis the properties include 22 producing wells and 17 undeveloped locations.

Reserve assignments for the producing completions were assigned on the basis of the extrapolation of performance data. Analogy was considered in determining hyperbolic exponents for the estimation of future reserves for those completions that did not have sufficient production history to definitively project the proper decline profile. Reserves for the undeveloped locations were projected on the basis of analogy to existing completions. In all cases, the undeveloped locations are direct offsets to existing completions.

In aggregate, these properties represent 19.1% and 11.0% of oil and gas reserves, respectively, net to Callon. Approximately 58% of the estimated reserves, on an equivalent barrel basis, are in the undeveloped category. We have been informed by Callon that development operations are to be commenced on the properties in 2010.

West Cameron Block 295 — West Cameron Block 295, discovered in 2005, is defined by two separate gas accumulations that are productive from similar geologic intervals. However, there is some evidence that the M-1 sands in the two existing wells have some degree of pressure communication though produced fluids vary somewhat in composition. The No. A-1 (formerly No. 2) wellbore encountered productive sands in the Rob M-1 horizon (15,370’ MD) and the Rob L horizon (13,100’ MD). The well

Huddleston & Co., Inc.

Callon Petroleum Company
February 24, 2010
Page Five

was completed in the Rob M-1 and is currently on production with the Rob L behind-pipe. A development well, designed to effectively drain the M-1 reservoir (No. A-2), was drilled during 2006 and encountered the target horizon. The initial completion in the Rob M-1 Lower depleted during 2007 and the well has been recompleted to the Rob M-1.

The previous reserve assignments included a behind-pipe recompletion in the Rob L sand in the A-1 wellbore. However, this zone is no longer included in the Proved category as a result of mechanical concerns associated with recompletion operations.

Reserve estimates for the property were increased to reflect the performance of the existing completions. Ultimate gross recovery for the field is estimated to be approximately 28.5 Bcf. The property represents 9.0% of remaining gas reserves net to Callon.

Product Prices

As we understand the SEC requirements issued on January 14, 2009, oil and gas prices utilized to determine the Standardized Measure of discounted cash flows should be based on the trailing twelve-month average of the first-of-the-month prices. The estimated revenues shown herein reflect the actual average of first-of-the-month prices received by Callon on a property by property basis. The projected prices for both oil and gas were based on our understanding of SEC requirements. It is noted that the pricing requirements vary significantly from those previously required for reporting purposes.

Gas prices have been adjusted to reflect the Btu content, transportation charges, and other fees specific to the individual properties. Gas prices for certain properties include consideration for processing arrangements and the price shown herein has been adjusted to reflect such arrangements in comparison to produced gas volumes. On an overall basis, the wellhead gas prices utilized herein are approximately 25% less than the values utilized as of December 31, 2008. In some cases the reduced prices may have resulted in marginally lower levels of economically recoverable gas. Market level gas prices are subject to a significant level of variation depending on location and marketing considerations specific to the individual properties. In our opinion, it is likely that there will be a substantial degree of variation in prices in the future. Spot prices for natural gas have experienced a large degree of volatility during recent years, which can be attributed to seasonal demands and other market considerations.

The projected oil prices for individual properties have been adjusted to reflect all wellhead deductions and premiums on a property by property basis, including transportation costs, location differentials, and crude quality. The weighted average wellhead prices shown herein are approximately 56% less than those utilized for our report prepared as of December 31, 2008, which has had a material impact on estimated future revenues and in some cases has marginally affected economically recoverable reserves. Variations in oil prices are the result of changes in market conditions and future prices are likely to be affected by a variety of factors including OPEC actions, political and market considerations, and overall economic conditions.

All deductions and premiums to individual oil and gas prices were held constant over the life of the properties. Variations in future product prices may materially affect actual revenues in comparison to the projections shown herein.

Product price hedges, if any, were not considered for the purposes of this report.

Huddleston & Co., Inc.

Callon Petroleum Company
February 24, 2010
Page Six

A comparison of the average product prices, weighted as a composite for all Proved properties, follows:


	2010		Maximum		Average Over Life
Oil, $/bbl		57.43		57.74		57.40
Gas, $/Mcf		4.15		6.48		4.75

Operating Expenses

Operating expenses, generally shown as dollars per well per month for onshore properties, were provided by Callon and adjusted for nonrecurring costs where applicable. In some cases, particularly for the offshore properties, operating costs were projected on a total-unit or platform basis and the projections were continued until the unit or facility reached the economic limit. Severance and ad valorem taxes were calculated at the rates applicable to each property and have been deducted from the cash flow. Operating costs were held constant over the economic life of the properties.

Capital Costs

Capital costs necessary to perform recompletions and to drill new wells were supplied by Callon. We have generally reviewed the projected expenditures and they are consistent with our perception of current costs necessary to perform the intended operations. Capital costs were held constant over the life of the properties.

Other Considerations

Additional Costs — Costs were not deducted for depletion, depreciation, and/or amortization. Consideration has also been excluded for federal and/or state income taxes, if any.

Abandonment costs for all offshore properties and certain onshore properties were included in the projections where Callon has determined the total cost associated with abandoning the facilities and platforms will exceed salvage value. In some cases, funds have been escrowed to cover anticipated future abandonment costs. The projections reflect a total of $31,723,660 in abandonment costs.

Additional Potential Values — Values were not assigned to nonproducing acreage or to acreage held by production, if any. In general, the salvage of surface and subsurface equipment for the onshore properties was assumed to be equal to abandonment costs.

Context — The estimated reserves and revenues shown herein should be considered on an overall basis and estimates for individual properties should not be taken out of context with the total or overall projections.

THE REVENUES AND PRESENT WORTH OF FUTURE NET REVENUES ARE NOT REPRESENTED TO BE MARKET VALUES EITHER FOR INDIVIDUAL PROPERTIES OR ON A TOTAL PROPERTY BASIS.

Data Sources — Essentially all data were furnished by Callon, including production statistics, product prices, operating costs, ownership, and basic well information. We have accepted the data as represented. We express no opinions and make no representations as to legal or accounting interpretations provided by Callon. Production statistics for the significant Callon-operated properties and for several of the other more significant properties were available through December 2009.

Huddleston & Co., Inc.

Callon Petroleum Company
February 24, 2010
Page Seven

We retain in our files plotted production histories for all properties and certain other information that we believe pertinent. We have not inspected the properties evaluated in this report nor have we conducted independent well tests.

Respectfully submitted,

Peter D. Huddleston, P.E.
Texas Registered Engineering Firm F-1024

PDH:klh

Huddleston & Co., Inc.

Huddleston & Co., Inc.
Petroleum and Geological Engineers
Texas Registered Engineering Firm F-1024
Houston, Texas

SECURITIES AND EXCHANGE COMMISSION
REGULATION S-X, RULE 4-10

§ 210.4-10 Financial accounting and reporting for oil and gas producing activities pursuant to the Federal securities laws and the Energy Policy and Conservation Act of 1975.

This section prescribes financial accounting and reporting standards for registrants with the Commission engaged in oil and gas producing activities in filings under the Federal securities laws and for the preparation of accounts by persons engaged, in whole or in part, in the production of crude oil or natural gas in the United States, pursuant to section 503 of the Energy Policy and Conservation Act of 1975 (42 U.S.C. 6383) (EPCA) and section 11(c) of the Energy Supply and Environmental Coordination Act of 1974 (15 U.S.C. 796) (ESECA), as amended by section 505 of EPCA. The application of this section to those oil and gas producing operations of companies regulated for ratemaking purposes on an individual-company-cost-of-service basis may, however, give appropriate recognition to differences arising because of the effect of the ratemaking process.

Exemption. Any person exempted by the Department of Energy from any record-keeping or reporting requirements pursuant to section 11(c) of ESECA, as amended, is similarly exempted from the related provisions of this section in the preparation of accounts pursuant to EPCA. This exemption does not affect the applicability of this section to filings pursuant to the Federal securities laws.

Definitions

(a)

Definitions. The following definitions apply to the terms listed below as they are used in this section:

	(1)		Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.

	(2)		Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

	(i)		Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

	(ii)		Same environment of deposition;

	(iii)		Similar geological structure; and

	(iv)		Same drive mechanism.

			Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

	(3)		Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

	(4)		Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

	(5)		Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

	(6)		Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

	(i)		Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

	(ii)		Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

(7)

Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

	(i)		Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

	(ii)		Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

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	(iii)		Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

	(iv)		Provide improved recovery systems.

	(8)		Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

	(9)		Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

	(10)		Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

	(11)		Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

	(12)		Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

	(i)		Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or G&G costs.

	(ii)		Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

	(iii)		Dry hole contributions and bottom hole contributions.

	(iv)		Costs of drilling and equipping exploratory wells.

	(v)		Costs of drilling exploratory-type stratigraphic test wells.

	(13)		Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

	(14)		Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

	(15)		Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

	(16)		Oil and gas producing activities.

(i)

Oil and gas producing activities include:

	(A)		The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

	(B)		The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

	(C)		The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

			(1) Lifting the oil and gas to the surface; and

			(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
REGULATION S-X, RULE 4-10
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(D)

Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

	a.		The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

	b.		In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

			Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

	(ii)		Oil and gas producing activities do not include:

	(A)		Transporting, refining, or marketing oil and gas;

	(B)		Processing of produced oil, gas or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

	(C)		Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

	(D)		Production of geothermal steam.

(17)

Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

	(i)		When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

	(ii)		Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

	(iii)		Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

	(iv)		The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

	(v)		Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

	(vi)		Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18)

Probable reserves. Probable reserves are those 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.

(i)

When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
REGULATION S-X, RULE 4-10
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	(ii)		Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

	(iii)		Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

	(iv)		See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

	(19)		Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

	(20)		Production costs.

(i)

Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

	(A)		Costs of labor to operate the wells and related equipment and facilities.

	(B)		Repairs and maintenance.

	(C)		Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

	(D)		Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

	(E)		Severance taxes.

(ii)

Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

	(21)		Proved area. The part of a property to which proved reserves have been specifically attributed.

	(22)		Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, 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.

(i)

The area of the reservoir considered as proved includes:

	(A)		The area identified by drilling and limited by fluid contacts, if any, and

	(B)		Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

	(ii)		In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

	(iii)		Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

	(iv)		Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A)

Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other

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			evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

	(B)		The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

	(23)		Proved properties. Properties with proved reserves.

	(24)		Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

	(25)		Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

	(26)		Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

			Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

	(27)		Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

	(28)		Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

	(29)		Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

	(30)		Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

	(31)		Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

	(i)		Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

	(ii)		Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

	(iii)		Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32)

Unproved properties. Properties with no proved reserves.

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