PEDEVCO CORP - FORM 8-K/A - EX-99.3 - RESERVE REPORT PREPARED BY SOUTH TEXAS RESERVOIR ALLIANCE LLC.

Attached files

file	filename
8-K/A - CURRENT REPORT - PEDEVCO CORP	ped_8k.htm
EX-99.2 - UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION - PEDEVCO CORP	ped_ex992.htm
EX-23.2 - CONSENT OF PETROLEUM ENGINEERS - PEDEVCO CORP	ped_ex232.htm
EX-23.1 - CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM - PEDEVCO CORP	ped_ex231.htm
EX-99.1 - STATEMENT OF REVENUES - PEDEVCO CORP	ped_ex991.htm

Exhibit 99.3

Document Control

PEDEVCO Corp. Reserve Report Issued April 10th, 2015

Run Using a January 1st, 2015 As Of Date On the Petroleum Properties of Golden Globe Energy (US), LLC

Prepared by South Texas Reservoir Alliance LLC

State of Texas Registration Number F-13460

Prepared by Michael Rozenfeld, State of Texas Professional Engineer #107701

Signature:

Disclosures

This report is provided to PEDEVCO Corp. LLC (“PEDCO”) using reserve and contingent resource definitions and disclosure guidelines contained in the Securities and Exchange Commission (SEC), Society of Petroleum Engineers (SPE), World Petroleum Council (WPC), and American Association of Petroleum Geologists (AAPG)

This report utilizes assumptions, data, methods and procedures that are appropriate for the purpose served by the report as required by the Securities and Exchange Commission. Significant data was collected and examined using volumetric calculations and decline curve analysis. Offset production, logs, maps, analog information and accounting statements were all studied.

This report covers one hundred percent (100%) of the reserves of Golden Globe Energy (US), LLC [GGE]. All of the reserves of GGE are located in Weld and Morgan County, Colorado. This report covers GGE’s working and net revenue interest in all wells.

New regulations could have an adverse effect on the reserves calculated in this report. Importantly a ban on hydraulic fracturing in the area could significantly decrease or eliminate this report’s reserves.

South Texas Reservoir Alliance LLC (“STXRA”) has used all methods and procedures as it considers necessary under the circumstances to prepare this report.

Michael Rozenfeld supervised or performed all of the relevant technical work during the creation of this report. He is a member of South Texas Reservoir Alliance LLC, a Delaware Limited Liability Company. STXRA is certified professional engineering company in the state of Texas. STXRA’s state of Texas registration number is F-13460. Michael Rozenfeld has a B.S. degree in Petroleum Engineering from the University of Texas at Austin. He is a registered professional engineer in the state of Texas. His state of Texas professional engineering number is 107701. Michael Rozenfeld has nine years of experience in creating reserve reports and completing reserve analysis for conventional and unconventional fields in the United States.

Scope of Investigation

This report is an appraisal, as of January 1st, 2015, of the extent and value of the proved, probable and possible crude oil, condensate, and natural gas reserves of properties owned by GGE. The reserves and resources recorded on the ‘as of’ date were calculated using the current field economic and productivity conditions. Changes to these conditions may significantly affect reserves. The reserves presented in this report have been prepared in accordance with guidelines set by the Securities and Exchange Commission, the World Petroleum Council, the American Association of Petroleum Geologists, and the Society of Petroleum Evaluation Engineers. The reserves estimated for this report are for producing wells, undeveloped locations and behind pipe volumes of oil and gas.

Summary

The estimated net proved, probable and possible reserves, as of January 1st, 2015, of the properties appraised are summarized as follows, and expressed in thousands of barrels (MBBL) or millions of cubic feet (MMCF):

	Net Oil	Net Gas	NPV Undiscounted	NPV Discounted 10%
Category	Reserves (MBBL)	Reserves (MMCF)	(M$)	(M$)
Proved Developed Producing (PDP)	391	828	22,776	15,988
Proved Behind Pipe (PDNP)	0	0	0	0
Proved Undeveloped (PUD)	4,171	8,902	113,377	29,148
TOTAL PROVED	4,562	9,730	136,152	45,136
TOTAL 1P RESERVES	4,562	9,730	136,152	45,136
Probable Developed Producing (PBDP)	112	250	6,360	2,708
Probable Behind Pipe (PBDNP)	0	0	0	0
Probable Undeveloped (PBUD)	897	1,826	50,905	14,049
TOTAL PROBABLE	1,009	2,076	57,265	16,757
TOTAL 2P RESERVES (PROVED + PROBABLE)	5,571	11,806	193,418	61,893
Possible Developed Producing (PSDP)	188	403	10,682	3,471
Possible Behind Pipe (PSDNP)	0	0	0	0
Possible Undeveloped (PSUD)	1,262	2,460	67,199	13,542
TOTAL POSSIBLE	1,449	2,863	77,882	17,013
TOTAL 3P RESERVES (PROVED + PROBABLE + POSSIBLE)	7,020	14,669	271,299	78,906

Reserves estimated in this report are expressed as gross and net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after the specified as of date. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by GGE after deducting all interests owned by others. This report presents values that were estimated for reserves using reasonable estimated costs and prices calculated using the average of the first day of every month in the year prior.

Values shown in this report for reserves are expressed in terms of estimated future gross revenue, future net revenue, and present worth. Future gross revenue is that revenue which will accrue to the appraised interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated production taxes, ad valorem taxes, operating expenses, transportation costs, and capital costs from the future gross revenue. All costs presented in this report are based on current market conditions and best engineering judgment and are subject to change. Operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities. Future income taxes were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a specified arbitrary discount rate compounded monthly over the expected period of realization. In this report, present worth values using a discount rate of 10 percent are reported in detail.

Estimates of oil, condensate, and natural gas reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information becomes available. Not only are such reserves and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Information used in the preparation of this report was obtained from GGE and from public sources.

Estimation of Reserves

Estimates of reserves were prepared by the use of standard geological and engineering methods generally accepted by the petroleum industry. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history. Decline curve analysis was the primary method used to calculate reserves in place.

Reserves were estimated for 253 locations and current producers identified by PEDCO. The locations are generally well positioned to develop the acreage available in accordance with the geologic interpretation. Consideration was given to information on offset producing wells to determine the categorization of reserves for each location.

Oil reserves estimated herein are those to be recovered by normal lease separation. Gas volumes estimated herein are expressed as wet gas and sales gas. Wet gas is defined as the total gas to be produced before reductions for volume loss due to fuel and flare consumption and reduction for plant processing. Sales gas is defined as that portion of the wet gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and plant processing, if applicable. Gross gas volumes are reported as wet gas. Net volumes are reported as sales gas. All gas volumes are expressed at standard temperature and pressure.

Valuation of Reserves

This report has been prepared using industry standard price and cost assumptions. The oil price was based on historical EIA reported WTI spot prices for the previous twelve months. The gas price was based on historical EIA reported Henry Hub spot prices for the previous twelve months. The price of each commodity was determined on the first day of each of the prior months and then averaged together to yield one oil price and one gas price. Oil and gas offsets were calculated by comparing the historical EIA prices to lease operating statements provided by PEDCO along with deductions and gains for items such as crude & gas quality, processing, and transportation. All prices were held flat throughout all future dates. The following illustrates the prices and offsets used in this report:

For Red Hawk Petroleum:

Oil Price ($/Bbl)				Oil Price Offset ($/Bbl)				Realized Oil Price ($/Bbl)				Gas Price ($/MMbtu)				BTU Factor (BTU/scf)				Effective Gas Price ($/Mcf)
$	94.99				-10.94			$	84.05			$	4.35				1380			$	6.00

Operating Expenses and Capital Costs

All costs presented in this report are based on current market conditions and best engineering judgment and are subject to change. Operating expenses were based on historical prices seen in the appropriate field that the PDP, PUD and PDNP is located.

Comments on the Independence of South Texas Reservoir Alliance

In creation of this report South Texas Reservoir Alliance (STXRA) served as an independent third party contractor. South Texas Reservoir Alliance LLC has a non-exclusive consulting contract with PEDCO. The compensation from this contract is paid in cash once a month using hourly billings provided to PEDCO by STXRA.

STXRA also holds an immaterial (less than 1%) ownership in PEDEVCO Corp through public stock.

To further clarify STXRA:

1.	Is not on the board of PEDCO

2.	Has zero control over PEDCO and serves solely in the capacity as a consultant

3.	Has no voting power over PEDCO

4.	STXRA works on an arm’s length basis from PEDCO

5.	STXRA is a private company with 100% of its ownership held by certain employees of STXRA.

Definitions and Guidelines for Petroleum Resources

The reserves and presented in this report have been prepared in accordance with the Securities and Exchange Commission, the World Petroleum Council, the American Association of Petroleum Geologists, and the Society of Petroleum Evaluation Engineers. Links to these definitions and guidelines can be found here:

http://www.ecfr.gov/cgi-bin/text-idx?tpl=/ecfrbrowse/Title17/17cfr210_main_02.tpl

http://www.spe.org/industry/reserves.php

Document Control

Red Hawk Reserve Report Issued April 10th 2015

Run Using Two as of Dates: December 31st, 2012, December 31st, 2013

On the Petroleum Properties of Golden Globe Energy (US), LLC

Prepared by South Texas Reservoir Alliance LLC

State of Texas Registration Number F-13460

Prepared by Michael Rozenfeld, State of Texas Professional Engineer #107701

Signature:

Disclosures

This report is provided to Red Hawk Petroleum, LLC (“Red Hawk”) to satisfy the requirements contained in Item 1202(a)(8) of U.S. Securities and Exchange Commission Regulation S-K.

This report utilizes assumptions, data, methods and procedures that are appropriate for the purpose served by the report as required in Item 1202(a)(8)(iv). The purpose of this report is to estimate proved oil and gas reserves for properties of Golden Globe Energy (US), LLC using industry standard assumptions and methods. Significant data was collected and examined using volumetric calculations and decline curve analysis. Offset production, logs, maps, analog information and accounting statements were all studied.

This report covers one hundred percent (100%) of the reserves of Golden Globe Energy (US), LLC. All of the reserves of Golden Globe Energy (US), LLC are located in Weld and Morgan counties, Colorado. It is expressly stated and understood that these properties were not owned by Red Hawk on the as of dates listed within this report. However, all models and projections within this report were run as-if Red Hawk owned the properties on the stated as of dates.

The definitions found in Rule 4-10(a) of U.S. Securities and Exchange Commission Regulation S-X were used in this report.

STXRA has used all methods and procedures as it considers necessary under the circumstances to prepare this report.

Scope of Investigation

This report is an appraisal, as of December 31st, 2012, and December 31st, 2013 of the extent and value of the proved producing (PDP) reserves, proved behind pipe (PDNP), and proved undeveloped (PUD) crude oil, condensate, and natural gas reserves of properties owned by Red Hawk Petroleum, LLC. As requested by Red Hawk Petroleum, LLC, the ownership interest in this report was held constant as if Red Hawk Petroleum, LLC held their interest in the properties on both of the dates. Therefore, it is expressly stated and disclosed that Red Hawk Petroleum, LLC did not own any interest in the properties examined in this report until February 23rd, 2015 and the December 31st, 2012, and December 31st, 2013, ‘as of’ dates investigated in this report are done so solely to illustrate what reserves Red Hawk Petroleum, LLC would have had should they have purchased their interest at an earlier date. Further, the reserves recorded on each of the ‘as of’ dates were created by taking the current field economic and productivity conditions and projecting them backwards to the ‘as of’ dates. These backward projections may or may not match what actually occurred in 2012 and 2013. This report is completed using the same information and methods as the report originally issued in May 17, 2014 for Red Hawk Petroleum with no changes or updates made besides appropriate working interest being added. This report can be accessed at the following link (http://ir.stockpr.com/pacificenergydevelopment/all-sec-filings/content/0001214782-14-000029/0001214782-14-000029.pdf). Reasonable engineering estimates were utilized in the recording of non-operated interests and any wells that had a after payout interest only had their reserve category ‘frozen’ with it not being allowed to change as the reserves cannot be booked as PUDs. The proved reserves presented in this report have been prepared in accordance with the definitions found in Rule 4-10(a) of the U.S. Security and Exchange Commission Regulation S-X. All of the following sources were also referred to on a as needed basis: the Petroleum Resources Management System (PRMS) approved in March 2007 by the Society of Petroleum Engineers, the World Petroleum Council, the American Association of Petroleum Geologists, and the Society of Petroleum Evaluation Engineers. A summary of Rule 4-10(a) of the U.S. Security and Exchange Commission Regulation S-X has been provided in the following section. The proved reserves estimated for this report are for producing wells, undeveloped locations and behind pipe reserves of oil and gas. Probable and possible reserves are not investigated in this report.

Summary

The estimated gross and net proved reserves, as of December 31st, 2012 and December 31st, 2013, of the properties appraised are summarized as follows, expressed in thousands of barrels (MBBL) or millions of cubic feet (MMCF):

		Net Oil		Net Gas		NPV Undiscounted		NPV Discounted 10%
As Of Date	Category	Reserves (MBBL)		Reserves (MMCF)		(M$)		(M$)
December 31st, 2012	Proved Developed Producing (PDP)		75.1		146.13		4,854.89		3,412.66
December 31st, 2012	Proved Behind Pipe (PDNP)		0		0		0		0
December 31st, 2012	Proved Undeveloped (PUD)		1,894.39		3,888.75		62,590.63		15,799.16
December 31st, 2012	TOTAL		1,969.49		4,034.88		67,445.52		19,211.82
December 31st, 2013	Proved Developed Producing (PDP)		108.3		195.77		6,627.19		4,604.78
December 31st, 2013	Proved Behind Pipe (PDNP)		0		0		0		0
December 31st, 2013	Proved Undeveloped (PUD)		1,846.42		3,811.01		61,650.44		17,255.68
December 31st, 2013	TOTAL		1,954.72		4,006.78		68,277.63		21,860.46

Reserves estimated in this report are expressed as gross and net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after the specified as of date. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Red Hawk Petroleum, LLC after deducting all interests owned by others. This report also presents values that were estimated for proved reserves using reasonable estimated costs and prices calculated using the average of the first day of every month in the year prior.

Values shown in this report for proved reserves are expressed in terms of estimated future gross revenue, future net revenue, and present worth. Future gross revenue is that revenue which will accrue to the appraised interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated production taxes, ad valorem taxes, operating expenses, transportation costs, abandonment costs, and capital costs from the future gross revenue. All costs presented in this report are based on current market conditions and best engineering judgment and are subject to change. Operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities. Future income taxes were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a specified arbitrary discount rate compounded monthly over the expected period of realization. In this report, present worth values using a discount rate of 10 percent are reported in detail.

Information used in the preparation of this report was obtained from Red Hawk Petroleum, LLC and from public sources.

Estimation of Reserves

Estimates of reserves were prepared by the use of standard geological and engineering methods generally accepted by the petroleum industry. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history. When applicable, the volumetric method was used to estimate original oil in place (OOIP) and original gas in place (OGIP).

Maps were prepared to delineate each reservoir and to estimate reservoir volume. Electrical logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP. Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

Proved undeveloped reserves were estimated for 282 locations identified by Red Hawk Petroleum, LLC. These locations are generally positioned to develop the acreage available in accordance with the geologic interpretation. Consideration was given to information on offset producing wells to determine the categorization of reserves for each location. Of note this report does not examine probable or possible reserves and Red Hawk Petroleum, LLC currently has numerous additional potential well locations identified which will allow for more development of Red Hawk Petroleum’s acreage position. At this time there is not enough information to classify these additional well locations as proved.

Valuation of Reserves

This report has been prepared using industry standard price and cost assumptions. These pricing assumptions are from the original report issued May 17, 2014 and is not current SEC pricing. The oil price was based on historical EIA reported WTI spot prices for the previous year prior to the acquisition. The gas price was based on historical EIA reported Henry Hub spot prices for the previous year prior to the acquisition. The price of each commodity was determined on the first day of each of the prior year’s months and then averaged together to yield one oil price and one gas price. Appropriate oil and gas price offsets were calculated by comparing the historical EIA prices to the lease operating statements provided by Red Hawk Petroleum, LLC. All prices were held flat throughout all future dates. The following illustrates the prices and offsets used in this report:

Oil Price ($/Bbl)				Oil Price Offset ($/Bbl)				Realized Oil Price ($/Bbl)				Gas Price ($/MMbtu)				Gas Price Offset ($/MMbtu)				BTU Factor (BTU/scf)				Realized Gas Price ($/Mcf)
$	98.60			$	-11.25			$	87.35			$	4.18			$	+1.90				1380			$	8.39

Operating Expenses and Capital Costs

The operating and capital cost assumptions are from the original report issued May 17, 2014. All costs presented in this report are based on current market conditions and best engineering judgment and are subject to change. Operating expenses were based on historical prices seen in the appropriate field that the PDP, PUD and PDNP is located. .

Comments on the Definition of the ‘As Of Date’ as used in this Report

This report contains six ‘as of dates’. The as of dates requested by the client was one second before midnight on each of the following days: December 31st 2012 and December 31st 2013. However, the economic software used in computing the reserves and economics contained within this report is incapable of computing reserves down to the second. Therefore, when entering the as of dates into the economic software, the dates were entered as the next day. By default the economic software can be considered to start its calculation at one second past midnight on the as of date entered in the software. Therefore, the modeled output as of dates of January 1st 2013, and January 1st 2014 are equivalent to the requested as of dates of December 31st 2012 and December 31st 2013 respectively.

Comments on the Independence of South Texas Reservoir Alliance

In creation of this report South Texas Reservoir Alliance (STXRA) served as an independent third party contractor. South Texas Reservoir Alliance LLC has a non-Exclusive consulting contract (a ‘strategic alliance’) with Pacific Energy Development Company and their wholly owned associated company Red Hawk Petroleum, LLC. The compensation from this contract includes a primary payment of cash (billed on an hourly basis).

In addition to the contracts we have a 30% interest with Pacific Energy Development in an entity with no assets, Pacific Energy Technology Services LLC. This entity has yet to generate any revenue and STXRA has not completed any billable work for the entity.

To further clarify STXRA:

1.	Is not on the board of Pacific Energy Development

2.	Has zero control over Pacific Energy Development and serves solely in the capacity as a consultant

3.	Has no voting power over Pacific Energy Development other than that of a stock holder (less than 1%)

4.	STXRA works on an arm’s length basis from Pacific Energy Development

5.	STXRA is a private company with 100% of its ownership held by certain employees of the company.

Definitions and Guidelines for Petroleum Resources

The definitions found in Rule 4-10(a) of U.S. Securities and Exchange Commission Regulation S-X were used in the creation of this report. A link to these definitions can be found here:

http://www.ecfr.gov/cgi-bin/text-idx?c=ecfr&sid=20c66c74f60c4bb8392bcf9ad6fccea3&rgn=div5&view=text&node=17:2.0.1.1.8&idno=17#17

“(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.

(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

(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.

(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 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.”

(SOURCE: Rule 4-10(a) of U.S. Securities and Exchange Commission Regulation S-X)

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