Document:

Long-Term Incentive Plan

 Exhibit 10.1 
 QC Holdings, Inc. 
 Long-Term Incentive Plan 

The following is the structure for the QC Holdings, Inc. Long-Term Incentive Plan for 2012 and successive years. 

 

			
	Covered Officers	  	All executive officers, other than the Chairman of the Board and Chief Executive Officer and the Vice Chairman of the Board. Such other officers as the Compensation Committee may
designate at the time of each annual grant of LTI Awards.
		
	LTI Awards	  	LTI Awards will consist of Performance Units, comprising 75% of each LTI Award, and time-vested Restricted Stock Units, comprising 25% of each LTI Award.
		
	Performance Period	  	Each Performance Period will cover three calendar years. LTI Awards will be granted annually to the Covered Officers, and earned/paid, at the end of three full calendar years.
E.g., 2012 LTI Awards will cover calendar years 2012 – 2014.
		
	Targeted $ Amount of LTI Awards	  	The targeted dollar amount of LTI Awards will be set by the Compensation Committee at the time of each LTI Award based on targeted long-term incentive compensation for each
Covered Officer for each year.
		
	Performance Measure	  	The performance measure for the Performance Unit portion of each LTI Award will be set by the Compensation Committee from time to time. The target or goal for the performance
measure will be set by the Compensation Committee annually. The initial performance measure for the Performance Units will be annual Return on Average Assets for the Performance Period.
		
	Performance Units (75%) of LTI Award	  	$100 per Unit value, granted in whole Units only. Threshold/Target/Maximum payout of the Performance Units will range between 50% and 200% based on achievement of 80% - 120% of
the targeted Performance Measure (e.g. Return on Average Assets) for the Performance Period. Payout in cash at end of the 3-year Performance Period based on actual Performance Measure compared to the targeted Performance Measure. If 80% threshold
performance is not achieved, the Performance Units will lapse as of the end of the 3-year Performance Period. 120% of targeted Performance Measure will result in 200% maximum payout of Performance Units.

  
 -1-

			
		
	Performance Units – Vesting and Change of Control Event	  	 Performance Units vest at end of the Performance Period subject to continued employment by the Covered Officer throughout the
Performance Period (i.e., 3-year cliff vesting as of close of business on December 31 of the third year of the Performance Period).
  

Performance Units vest upon a Change of Control Event, as defined in the 2004 Equity Incentive Plan. Performance Units will be paid upon a Change of
Control based on the pro rated amount thereof based on (i) passage of time for that Performance Period, and (ii) achievement of targeted Performance Measure as of the end of the most recent fiscal quarter prior to the Change of Control Event. E.g.,
a Change of Control Event 18 months into a 3-year Performance Period during which the Company has hit 100% of the targeted performance measure would payout at 50% of the target amount of Performance Units. The Compensation Committee shall compute
the payout, if any, of the Performance Units upon a Change of Control Event based on these two variables.

		
	Restricted Stock Units (25%) of LTI Award	  	 Restricted Stock Units equal to 25% of the targeted total dollar amount of the LTI Award for each Covered Officer, divided by the
average weighted trailing 3-month stock price of QC Holdings Common Stock prior to the beginning of the Performance Period (e.g. for the three months ended December 31, 2011 for the 2012 LTI Awards).

 
 Payout of Restricted Stock Units will be made in cash at the end of the Performance
Period based on number of Restricted Stock Units times the average weighted trailing 3-month stock price of QC Holdings Common Stock as of December 31 of the third year of the Performance Period.

		
	Restricted Stock Units – Vesting and Change of Control Event	  	 Restricted Stock Units vest at end of the Performance Period subject to continued employment by the Covered Officer throughout the
Performance Period (i.e., 3-year cliff vesting as of close of business on December 31 of the third year of the Performance Period).
  

Restricted Stock Units constitute Restricted Stock Awards for purposes of the 2004 Equity Incentive Plan. Accordingly, Restricted Stock Units vest upon a
Change of Control Event, as defined in the 2004 Equity Incentive Plan. Restricted Stock Units will be paid in cash upon the Change of Control Event based on the number of Restricted Stock Units times the per share price paid for the Common Stock in
the Change of Control Event. If the Change of Control Event does not entail the payment for Common Stock in cash or other consideration, the Restricted Stock Units will be paid based on the number of Restricted Stock Units times the average weighted
trailing 3-month stock price of QC Holdings Common Stock immediately prior to the Change of Control Event.

  
 -2-

			
	 Administration
	  	 LTI Awards will be made by the Compensation Committee pursuant to the terms of the LTI Plan and, with respect to the Restricted Stock
Units, the QC Holdings, Inc. 2004 Equity Incentive Plan. Any conflict between the terms of the LTI Plan and the 2004 Equity Incentive Plan will be resolved by the Compensation Committee, with priority given to the terms of the LTI Plan.

 
 The Compensation Committee retains the authority to interpret the terms of the LTI
Plan, to amend, modify or suspend the LTI Plan at any time, in its sole and absolute discretion, and to modify, amend or adjust the Covered Officers, the performance measure for future LTI Plan awards, and to make other adjustments to LTI Plan
awards as the Committee deems fair and equitable to adjust for any events or circumstances that were not foreseen as of the date of each LTI Plan award.

		
	Timing of LTI Awards and Payouts	  	 LTI Awards will normally be made each February in conjunction with the Compensation Committee review of financial and executive
performance for the prior calendar year.
  
 LTI Award payouts, if any, will
normally be made each February, commencing February 2015 for the 2012 LTI Awards. Payout of Performance Units will be based on actual performance of the Company during the Performance Period compared to the targeted Performance Measures for the
Performance Period. Payout of Restricted Stock Units will be based on the market value of the QC Holdings common stock as of the end of the Performance Period, as described above.

 
 Cash payouts of both the Performance Units and the Restricted Stock Units will be
made promptly by the Company after the Compensation Committee has certified LTI Award payouts for each Performance Period in accordance with normal payroll and withholding practices of the Company.

  
 -3-Consent letter of Ryder Scott Company, L.P.

 Exhibit 10.1 

 

									
	

	 	

	 		 	
	 	  

TBPE REGISTERED ENGINEERING FIRM F-1580
	 		 	FAX (713) 651-0849
	 	1100 LOUISIANA     SUITE 3800	 	HOUSTON, TEXAS 77002-5235	 	TELEPHONE (713) 651-9191

 April 24, 2012 
 Dr. Juan José Suárez Coppel 
 Director General 

Petróleos Mexicanos 
 Avenida Marina
Nacional No. 329 
 Colonia Petróleos Mexicanos, 
 Torre Ejecutiva, Piso 41 
 11311 México, D.F. México 

Dear Dr. Suárez Coppel: 
 We hereby consent to the references to Ryder Scott Company L.P. as set forth under the heading “Exploration and Production (Reserves)” in the annual report on Form 20-F of Petróleos
Mexicanos for the year ended December 31, 2011 (the “Form 20-F”) and to the filing as an exhibit to the Form 20-F our report describing our review of the estimates of proved oil, condensate, natural gas and oil equivalent reserves
owned by the United Mexican States (“Mexico”) as of January 1, 2012, for 260 fields located onshore in and offshore from Mexico in the Northern Region. These estimates were prepared in accordance with the applicable reserves
definitions of Rule 4-10(a) of Regulation S-X of the United States Securities and Exchange Commission. 
  

	
	/S/ RYDER SCOTT COMPANY, L.P.
	RYDER SCOTT COMPANY, L.P.
	TBPE Firm Registration No. F-1580

 Houston, Texas 
 April 24, 2012 
  

							
	1015 4TH STREET, S.W. SUITE 600	  	CALGARY, ALBERTA T2R 1J4	  	TEL (403) 262-2799	  	FAX (403) 262-2790
	621 17TH STREET, SUITE 1550	  	DENVER, COLORADO 80293-1501	  	TEL (303) 623-9147	  	FAX (303) 623-4258Report on Reserves Data by Ryder Scott Company, L.P.

 Exhibit 10.2 
 Pemex – Exploración y Producción 
 Estimated

 Future Reserves 
 Attributable to Certain 
 Oil and Gas Interests 

SEC Parameters 
 As of 
 December 31, 2011 

 

					
		 	 /s/    Guale
Ramirez        
	 	
		 	Guale Ramirez, P.E.	 	 

		 	TBPE License No. 48318	 
		 	Managing Senior Vice President – International	 
		 		 
		 	RYDER SCOTT COMPANY, L.P.	 
		 	TBPE Firm Registration No. F-1580	 
		 		 

 RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

									
	

	 	

	 		 	
	 	  

TBPE REGISTERED ENGINEERING FIRM F-1580
	 		 	FAX (713) 651-0849
	 	1100 LOUISIANA     SUITE 3800	 	HOUSTON, TEXAS 77002-5235	 	TELEPHONE (713) 651-9191

 March 19, 2012 
 Ing. Carlos Morales Gil 
 Director General de Pemex – Exploración y Producción

 Av. Marina Nacional #329, Piso 41 T.E. 
 Colonia Petróleos Mexicanos 
 México 11311, D.F. 

Dear Ing. Morales: 
 At the
request of Pemex – Exploración y Producción (PEP), a wholly owned subsidiary of Petróleos Mexicanos (Pemex), Ryder Scott Company (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves owned by
the United Mexican States as of December 31, 2011 and operated by Pemex. The estimates we audited were prepared by PEP’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities
and Exchange Commission contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009, in the Federal Register (SEC regulations). Our third party reserves audit, completed on
February 10, 2012, and presented herein, was prepared for public disclosure by Pemex in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The properties reviewed by Ryder Scott are
comprised of those properties located in PEP’s Northern Region. The subject properties are located in the states of Coahuila, Nuevo León, Puebla, San Luis Potosí, Tamaulipas and Veracruz. Certain properties are located in
territorial waters, offshore in the Gulf of Mexico. There are other properties located in the Northern Region that are not operated by PEP and were not reviewed by Ryder Scott. The proved net reserves attributable to the properties that we reviewed
account for 90.8 percent of the total proved net oil equivalent barrels (BOE) for the Northern Region. 
 Pemex also operates
properties located in other regions of Mexico. The reserves estimated by PEP for such other regions were not reviewed by Ryder Scott. Based on the estimates of total net proved reserves prepared by PEP, the reserves audit conducted by Ryder Scott
addresses 10.4 percent of the total proved net reserves on a barrel of oil equivalent basis. 
 As prescribed by the Society of
Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent
facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data
relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities.”

 Based on our review, including the data, technical processes and interpretations presented by PEP, it is our opinion that the
overall procedures and methodologies utilized by PEP in preparing their estimates of the proved reserves as of December 31, 2011 comply with the current SEC regulations, and that the overall proved reserves for the reviewed properties as
estimated by PEP are, in the aggregate, reasonable and within the established audit tolerance guidelines of 10 percent set forth in the SPE auditing standards. 
  

							
	SUITE 600, 1015 4TH STREET, S.W.	  	CALGARY, ALBERTA T2R 1J4	  	TEL (403) 262-2799	  	FAX (403) 262-2790
	621 17TH STREET, SUITE 1550	  	DENVER, COLORADO 80293-1501	  	TEL (303) 623-9147	  	FAX (303) 623-4258

 Pemex – Exploración y Producción 

March 19, 2012 
 Page 2 

 

 The estimated reserves presented in this report are related to hydrocarbon prices. PEP
has informed us that in the preparation of their reserve and income projections, as of December 31, 2011, they used average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the
unweighted arithmetic averages of the prices in effect on the first-day-of- the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary
significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by PEP attributable to
Pemex’s operated properties that we reviewed and the reserves of properties that we did not review are summarized as follows: 
 SEC PARAMETERS 
 Estimated Net Reserves 

Attributable to Certain Properties Operated by Pemex 
 in the Northern Region 
 As of December 31, 2011 

 
  

																	
	 	  	Proved	 
	 	  	Developed	 	  	 	 	  	Total	 
	 	  	Producing	 	  	Non-Producing	 	  	Undeveloped	 	  	Proved	 
	 Net Reserves of Properties
	  				  				  				  			
	 Audited by Ryder Scott
	  				  				  				  			
	 Oil/Condensate – MM Barrels
	  	 	163.4	  	  	 	138.1	  	  	 	505.2	  	  	 	806.7	  
	 Plant Products(1) – MM Barrels
	  	 	26.1	  	  	 	21.1	  	  	 	54.0	  	  	 	101.2	  
	 Dry Gas(2) – MM Barrels Equivalent
	  	 	238.8	  	  	 	107.1	  	  	 	176.4	  	  	 	522.3	  
	
BOE(3) – MM Barrels
	  	 	428.3	  	  	 	266.3	  	  	 	735.6	  	  	 	1,430.2	  
	 Gross Gas(4) – MMMCF
	  	 	1,382.6	  	  	 	652.5	  	  	 	1,144.3	  	  	 	3,179.4	  
					
	 Net Reserves of Properties
	  				  				  				  			
	 Not Audited by Ryder Scott
	  				  				  				  			
	 Oil/Condensate – MM Barrels
	  	 	3.2	  	  	 	0.6	  	  	 	2.6	  	  	 	6.4	  
	 Plant Products(1) – MM Barrels
	  	 	5.4	  	  	 	4.4	  	  	 	5.0	  	  	 	14.8	  
	 Dry Gas(2) – MM Barrels Equivalent
	  	 	52.2	  	  	 	27.8	  	  	 	43.8	  	  	 	123.8	  
	
BOE(3) – MM Barrels
	  	 	60.8	  	  	 	32.8	  	  	 	51.4	  	  	 	145.0	  
	 Gross Gas(4) – MMMCF
	  	 	286.8	  	  	 	152.7	  	  	 	239.4	  	  	 	678.9	  
					
	 Total Net Reserves
	  				  				  				  			
	 Oil/Condensate – MM Barrels
	  	 	166.6	  	  	 	138.7	  	  	 	507.8	  	  	 	813.1	  
	 Plant Products(1) – MM Barrels
	  	 	31.5	  	  	 	25.5	  	  	 	59.0	  	  	 	116.0	  
	 Dry Gas(2) – MM Barrels Equivalent
	  	 	291.0	  	  	 	134.9	  	  	 	220.2	  	  	 	646.1	  
	
BOE(3) – MM Barrels
	  	 	489.1	  	  	 	299.1	  	  	 	787.0	  	  	 	1,575.2	  
	 Gross Gas(4) – MMMCF
	  	 	1,669.4	  	  	 	805.2	  	  	 	1,383.7	  	  	 	3,858.3	  

  

	(1)	Includes liquids generated through the transportation process and at the petrochemical plants. 

	(2)	Dry gas reserves are the dry, sweetened gas available for sale by Pemex – Gas y Petroquimica Básica at the tailgate of the processing plants.

	(3)	Barrels of oil-equivalent are based on dry gas conversion factors provided by PEP. 

	(4)	Gross Gas represents produced volumes of gas before any losses for fuel use, venting, transporting or plant shrinkage. 

  
 RYDER SCOTT
COMPANY    PETROLEUM CONSULTANTS 

 Pemex – Exploración y Producción 

March 19, 2012 
 Page 3 

 

 Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are
reported on an “as-sold” basis expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. The net remaining reserves are also shown herein on an equivalent
unit (BOE) basis wherein natural gas is converted to oil equivalent barrels using a factor of 5,200.9 cubic feet of natural gas per one barrel of oil equivalent. MMBOE represents million barrels of oil equivalent. 

Reserves Included in This Report 
 In our opinion, the proved reserves reviewed by us and presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An
abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report. 
 The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report. The proved developed non-producing reserves included
herein consist of the shut-in and behind pipe categories. 
 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.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that
the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the
time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be
recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At PEP’s request, this report addresses only the proved reserves
attributable to the properties reviewed herein. 
 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.” The proved reserves included herein were estimated using deterministic methods. If
deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered”. 
 Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as
changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or
remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included
in this report are estimates only and should not be construed as being exact quantities, and if recovered, could be more or less than the estimated amounts. 

  
 RYDER SCOTT
COMPANY    PETROLEUM CONSULTANTS 

 Pemex – Exploración y Producción 

March 19, 2012 
 Page 4 

 

 Audit Data, Methodology, Procedure and Assumptions 

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of
recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations
Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods:
(1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators
must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated
performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property. 
 In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the
method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the
deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable
and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than
not to be achieved.” The SEC states that “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.” The
SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable
plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above. 
 Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves
quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as
previously noted herein. 
 The proved reserves for the properties that we reviewed were estimated by performance methods, the
volumetric method, analogy, or a combination of methods. Approximately 95 percent of the proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods. These performance methods
include, but may not be limited to, decline curve analysis and material balance which utilized extrapolations of historical production and pressure data available through December, 2011, in those cases where such data were considered to be
definitive. The data utilized in this analysis were furnished to Ryder Scott by PEP and were considered sufficient for the purpose thereof. The remaining 5 percent of the proved producing reserves that we reviewed were estimated by the volumetric
method, analogy, or a combination of methods. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was
considered to be inappropriate. 

  
 RYDER SCOTT
COMPANY    PETROLEUM CONSULTANTS 

 Pemex – Exploración y Producción 

March 19, 2012 
 Page 5 

 

 All of the proved developed non-producing and undeveloped reserves that we reviewed were
estimated by the volumetric method, analogy, or a combination of methods. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by PEP for our review that were available through December, 2011. The data utilized
from the analogues in conjunction with well and seismic data incorporated into the volumetric analysis were considered sufficient for the purpose thereof. 
 To estimate economically recoverable proved oil and gas reserves we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological,
geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved
reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably
be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance
with rules adopted by the SEC, omitted from consideration in conducting this review. 
 As stated previously, proved reserves
must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved
reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by PEP relating to hydrocarbon prices and costs as noted herein. 

The hydrocarbon prices furnished by PEP for the properties reviewed by us are based on SEC price parameters using the average prices
during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were
defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations exclusive of inflation adjustments, were used until expiration of the contract. Upon contract
expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described. 
 The initial SEC
hydrocarbon prices in effect on December 31, 2011 for the properties reviewed by us were determined using the 12-month average first-day-of-the-month prices appropriate to the geographic areas where the hydrocarbons are sold. These prices are
the actual prices received by PEP for the sale of hydrocarbon products to its affiliates such as Pemex – Refinación. 
 The table below summarizes Pemex’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us by geographic areas and referred to herein as Pemex’s
“average realized prices.” The average realized prices shown in the table below were determined from PEP’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and PEP’s estimate of
the total net reserves for the properties reviewed by us for each of the areas referred to as Activos in the Northern Region. The data shown in the table below is presented in accordance with SEC disclosure requirements for each of the geographic
areas within the Northern Region reviewed by us. 

  
 RYDER SCOTT
COMPANY    PETROLEUM CONSULTANTS 

 Pemex – Exploración y Producción 

March 19, 2012 
 Page 6 

 

							
	 Geographic Area (Activo)
	  	Product	  	Average
Realized
Prices	 
			
	 AIPRA Area
	  	Oil	  	 	$97.69/Bbl  	  
	  	Gas	  	 	$4.13/MCF 	  
	 ATG Area Chicontepec
	  	Oil	  	 	$99.75/Bbl  	  
	  	Gas	  	 	$3.89/MCF 	  
	 Burgos Area
	  	Oil/Condensate	  	 	$88.06/Bbl  	  
	  	Gas	  	 	$3.75/MCF 	  
	 Veracruz Area
	  	Oil/Condensate	  	 	$83.43/Bbl  	  
	  	Gas	  	 	$3.96/MCF 	  

 The effects of derivative instruments designated as price hedges of oil and gas quantities are not
reflected in PEP’s individual property evaluations. 
 Accumulated gas production imbalances, if any, were not taken into
account in the proved gas reserve estimates reviewed. The proved gas volumes included herein do not attribute gas consumed in operations as reserves. 
 Operating costs furnished by PEP are based on the operating expense reports of PEP and include only those costs directly applicable to the fields or wells for the properties reviewed by us. The operating
costs include a portion of general and administrative costs allocated directly to the fields and wells. The operating costs furnished by PEP were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an
independent verification of the data used by PEP. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the fields or wells. 

Development costs furnished by PEP are based on authorizations for expenditure for the proposed work or actual costs for similar
projects. The development costs furnished by PEP were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by PEP. At PEP’s request, abandonment costs
were not considered in our economic evaluation. 
 The proved developed non-producing and undeveloped reserves for the
properties reviewed by us have been incorporated herein in accordance with PEP’s plans to develop these reserves as of December 31, 2011. The implementation of PEP’s development plans as presented to us is subject to the approval
process adopted by PEP’s management. As the result of our inquiries during the course of our review, PEP has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal
approvals required by PEP’s management at the appropriate local, regional and/or corporate level. Additionally, PEP has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter
their plans. 
 The project known as Aceite Terciario del Golfo (ATG), and also known as Chicontepec, is authorized by the
government of the United Mexican States having Authorization Number 00102001, which was granted by the Secretaría de Hacienda y Crédito Público (SHCP) to invest in the subject project starting in fiscal year 2007. PEP’s
current investment portfolio includes the continued development and progression of the ATG project, encompassing the required capital investments that 

  
 RYDER SCOTT
COMPANY    PETROLEUM CONSULTANTS 

 Pemex – Exploración y Producción 

March 19, 2012 
 Page 7 

 

 
are necessary to develop a major part of the proven plus probable reserves. As such, there exists a high degree of certainty or reasonable expectation that the investments required to develop the
proven undeveloped reserves will be expended. Nevertheless, due to the characteristics of the reservoirs that comprise the 29 fields in the ATG project and the delineation strategies for the non-proven reserves, a large number of the wells to be
drilled in the next five years are in the non-proven areas of the project thus resulting in a time period greater than five years in order to drill all of the 6,085 proven undeveloped locations in ATG assigned by PEP. As of January 1, 2012
there were also 2,002 active producers in the ATG project. 
 Current costs used by PEP were held constant throughout the life
of the properties. 
 PEP’s forecasts of future production rates are based on historical performance from wells currently
on production. If no production decline trend has been established, future production rates were held constant until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a
decline trend has been established, this trend was used as the basis for estimating future production rates. 
 Test data and
other related information were used by PEP to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated
date furnished by PEP. Wells or locations that are not currently producing may start producing earlier or later than anticipated in PEP’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors
may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies. 
 The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to,
reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

 Ryder Scott did not evaluate the country and geopolitical risks in the country of Mexico where all of Pemex’s operated
properties are located. PEP’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and use, drilling and
production practices, environmental protection, marketing and pricing policies, various taxes and levies and are subject to change from time to time. The Political Constitution of the United Mexican States provides that the Mexican nation, not Pemex
owns all petroleum and other hydrocarbon reserves located in Mexico. Although Mexican law gives Pemex the exclusive right to exploit Mexico’s hydrocarbon reserves, it does not preclude the Mexican Congress from changing current law and
assigning some or all of these rights to another company. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the
estimated quantities. 
 The estimates of proved reserves presented herein were based upon a detailed study of the properties
operated by Pemex; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by PEP for potential liabilities to
restore and clean up damages, if any, caused by past operating practices. 

  
 RYDER SCOTT
COMPANY    PETROLEUM CONSULTANTS 

 Pemex – Exploración y Producción 

March 19, 2012 
 Page 8 

 

 Certain technical personnel of PEP are responsible for the preparation of reserve
estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical
personnel and had access to their workpapers and supporting data in the course of our audit. 
 PEP has informed us that they
have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of PEP’s forecast of future proved production, we have relied upon
data furnished by PEP with respect to property interests, production and well tests from examined wells, normal direct costs of operating the properties, other costs such as transportation and/or processing fees, recompletion and development costs,
product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness;
however, we have not conducted an independent verification of the data furnished by PEP. The data described herein were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of
question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. We consider the factual data furnished to us by PEP to be appropriate and sufficient for the purpose of our review of
PEP’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by PEP and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we
consider necessary and appropriate under the circumstances to render the conclusions set forth herein. 
 Audit Opinion

 Based on our review, including the data, technical processes and interpretations presented by PEP, it is our opinion
that the overall procedures and methodologies utilized by PEP in preparing their estimates of the proved reserves as of December 31, 2011 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties
as estimated by PEP are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards. 
 We were in reasonable agreement with PEP’s estimates of proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance between PEP’s
estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to PEP when its reserve estimates were prepared. In these cases, PEP revised its estimates to better conform to
our estimates. As a consequence, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves operated by Pemex and owned by the United Mexican States.

 Other Properties 
 Other properties, as used herein, are those properties operated by Pemex which we did not review, both within the Northern Region and in other regions. The proved net reserves attributable to the other
properties account for 89.6 percent of the total proved net equivalent barrels of reserves based on estimates prepared by PEP as of December 31, 2011. 

  
 RYDER SCOTT
COMPANY    PETROLEUM CONSULTANTS 

 Pemex – Exploración y Producción 

March 19, 2012 
 Page 9 

 

 The same technical personnel of PEP were responsible for the preparation of the reserve
estimates for the properties that we reviewed as well as for the properties not reviewed by Ryder Scott. 
 Standards of Independence and
Professional Qualification 
 Ryder Scott is an independent petroleum engineering consulting firm that has been providing
petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our
permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any
privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each
engagement for our services. 
 Ryder Scott actively participates in industry-related professional societies and organizes an
annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their
professional skills by actively participating in ongoing continuing education. 
 Prior to becoming an officer of the Company,
Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license,
or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. 
 We are independent petroleum engineers with respect to PEP. Neither we nor any of our employees have any interest in the subject properties, and neither the employment to do this work nor the compensation
is contingent on our estimates of reserves for the properties which were reviewed. 
 The results of this audit, presented
herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for the review of the reserves information
discussed in this report, are included as an attachment to this letter. 
 Terms of Usage 

The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set
forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Pemex. 
 Pemex
makes periodic filings on Form 20-F with the SEC under the 1934 Exchange Act. Furthermore, Pemex files registration statements with the SEC under the 1933 Securities Act into which filings on Form 20-F are incorporated by reference. We have
consented to the references to our name in and the filing of this report as an exhibit to the annual report on Form 20-F of Pemex for the year ended December 31, 2011. Our written consent for such use will be included as a separate exhibit to
such Form 20-F. In the event the references to our name as well as references to our report are incorporated by reference into any registration statement on Form F-4, then our written consent for such use will be included as a separate exhibit to
such registration statement. 

  
 RYDER SCOTT
COMPANY    PETROLEUM CONSULTANTS 

 Pemex – Exploración y Producción 

March 19, 2012 
 Page 10 

 

 We have provided PEP with a digital version of the original signed copy of this report
letter. In the event there are any differences between the digital version included in filings made by Pemex and the original signed report letter, the original signed report letter shall control and supersede the digital version. 

The data and workpapers used in the preparation of this report are available for examination by authorized parties in our offices. Please
contact us if we can be of further service. 
  

	
	Very truly yours,
	
	RYDER SCOTT COMPANY, L.P.
	TBPE Firm Registration No. F-1580
	
	/s/ Guale Ramirez
	Guale Ramirez, P.E.
	TBPE License No. 48318
	Managing Senior Vice President – International

  

			
	GR(FWZ)/sm	  	

  
 RYDER SCOTT
COMPANY    PETROLEUM CONSULTANTS 

 Professional Qualifications of Primary Technical Person 

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company,
L.P. Guadalupe Ramirez was the primary technical person responsible for overseeing the estimate of the reserves, future production and income. 

Mr. Ramirez, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1981, is a Managing Senior Vice President and also serves as a member of
the Board of Directors. He is responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Ramirez served in a number of
engineering positions with Sun Oil Company and Natomas North America. For more information regarding Mr. Ramirez’s geographic and job specific experience, please refer to the Ryder Scott Company website at
www.ryderscott.com/Experience/Employees. 
 Ramirez earned a Bachelor of Science Degree in Mechanical Engineering with honors from Texas A&M
University in 1976 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers. 

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen
hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Ramirez fulfills. As part of his 2011 continuing education hours, Mr. Ramirez attended an internally received 18 hours of
formalized training as well as a day-long public forum, the 2011 RSC Reserves Conference relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations,
Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Ramirez has also presented courses on the new SEC Reserves definitions on various occasions during 2009 and 2011 and received 16
hours of formalized external training during 2011, covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software,
unconventional resources and ethics for consultants. 
 Based on his educational background, professional training and more than 34 years of
practical experience in the estimation and evaluation of petroleum reserves, Mr. Ramirez has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007. 

  
 RYDER SCOTT
COMPANY    PETROLEUM CONSULTANTS 

 PETROLEUM RESERVES DEFINITIONS 

As Adapted From: 
 RULE 4-10(a) of REGULATION S-X PART 210 
 UNITED STATES SECURITIES AND
EXCHANGE COMMISSION (SEC) 
 PREAMBLE 
 On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National
Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas
reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be
referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference
should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics
herein). 
 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. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater
or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.
The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as
probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of
probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any
document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202. 

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions
change. 
 Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include
all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and
the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve. 
 Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their
in-place characteristics, extraction method applied, or degree of processing prior to sale. 

  
 RYDER SCOTT
COMPANY    PETROLEUM CONSULTANTS 

 PETROLEUM RESERVES DEFINITIONS 
 Page 2 
  

 Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM),
basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale. 

Reserves do not include quantities of petroleum being held in inventory. 

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves
categories. 
 RESERVES (SEC DEFINITIONS) 
 Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows: 
 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). 
 PROVED RESERVES (SEC DEFINITIONS) 

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows: 

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. 

  
 RYDER SCOTT
COMPANY    PETROLEUM CONSULTANTS 

 PETROLEUM RESERVES DEFINITIONS 
 Page 3 
  

 PROVED RESERVES (SEC DEFINITIONS) CONTINUED 

 

 (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. 

  
 RYDER SCOTT
COMPANY    PETROLEUM CONSULTANTS 

 RESERVES STATUS DEFINITIONS AND GUIDELINES 

As Adapted From: 
 RULE 4-10(a) of REGULATION S-X PART 210 
 UNITED STATES SECURITIES AND
EXCHANGE COMMISSION (SEC) 
 and 
 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS) 
 Sponsored and Approved
by: 
 SOCIETY OF PETROLEUM ENGINEERS (SPE) 
 WORLD PETROLEUM COUNCIL (WPC) 
 AMERICAN ASSOCIATION OF PETROLEUM
GEOLOGISTS (AAPG) 
 SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE) 

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17,
Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS
documents are denoted in italics herein). 
 DEVELOPED RESERVES (SEC DEFINITIONS) 

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows: 

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. 
 Developed Producing (SPE-PRMS
Definitions) 
 While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be
further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing. 
 Developed
Producing Reserves 
 Developed Producing Reserves are expected to be recovered from completion intervals that are
open and producing at the time of the estimate. 
 Improved recovery reserves are considered producing only after the
improved recovery project is in operation. 

  
 RYDER SCOTT
COMPANY    PETROLEUM CONSULTANTS 

 RESERVES STATUS DEFINITIONS AND GUIDELINES 
 Page 2 
  

 Developed Non-Producing 

Developed Non-Producing Reserves include shut-in and behind-pipe reserves. 

Shut-In 
 Shut-in Reserves are expected to be recovered from: 
  

	 	(1)	completion intervals which are open at the time of the estimate, but which have not started producing; 

 

	 	(2)	wells which were shut-in for market conditions or pipeline connections; or 

 

	 	(3)	wells not capable of production for mechanical reasons. 

 Behind-Pipe 
 Behind-pipe Reserves are expected to be
recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production. 
 In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. 
 UNDEVELOPED RESERVES (SEC DEFINITIONS) 
 Securities and Exchange
Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows: 
 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. 

  
 RYDER SCOTT
COMPANY    PETROLEUM CONSULTANTS

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