CHALLENGES TO ACCURATE OIL & GAS ASSET VALUATIONS …

Craig Davis – CEO [email protected]

Dan Ward – VP [email protected]

Luke Wilkens – VP [email protected]

INEXS Inc.

713-993-0676

www.inexs.com

CHALLENGES TO ACCURATE OIL & GAS ASSET VALUATIONS

LOOKING BEYOND THE 1P RESERVES

INCLUDING ASSESSMENT OF FIELD OPERATIONS

SUMMARY OF INEXS EXPERTISE

Asset Valuations

Independent Review of Third Party Engineering Reserve Reports

Review of Technical Expertise and Management of Portfolio Companies

Full Contract Field Operations

Full Field Equipment Audit

Vertical Vs. Horizontal Drilling And Completions

Challenges Between Conventional Vs. Unconventional Reservoirs

Proved Reserves – 1p, 2p, 3p + Probable & Possible

Risking Proved / Force Ranking Well Operations

Undrilled Acreage – Term and HBP

Valuation Challenges using Precedent Transactions

Valuation Challenges using Drill-Out Option

Field Operations Cost Analysis / Optimization

Field Equipment Audit And Inventory

SUMMARY

2

VERTICAL VS. HORIZONTAL DRILLING AND COMPLETIONS

NOTE: Throughout the presentation, blue dialog boxes such as this one are added to provide the detail and context that remains unexplained without the verbal presentation

HORIZONTAL VS. VERTICAL DRILLING

4

The primary objective in horizontal vs. vertical drilling is to expose more volume of rock to the wellbore for higher production rates

RESERVOIR CHALLENGES

Unconventional Reservoirs Conventional Reservoirs

Tight, low permeability, low porosity reservoir Higher permeability, and higher porosity reservoir

Brittle shale, tight sand, or fractured carbonate Porous sands, porous carbonates, fractured carbonates

Trapped by lack of horizontal permeability Requires a stratigraphic or structural trap

High total organic carbons (TOCs) in reservoir Low total organic carbons (TOCs) within reservoirSourced from high TOC shales above or below

Mostly drilled with horizontal well through reservoir Drilled with vertical well through reservoir

Challenges to geosteer within the formation Clear definition of field and reservoir limits

Generally fraced (fracked) to stimulate production Generally no need to stimulate production

Rarely any risk of water interrupting productionException is fracing to water reservoir above or below

Often water is the drive mechanism for production

Pressure depletion and gas expansion are primary drive mechanisms

Pressure depletion is also a common drive mechanism

Highly repeatable within close proximity Not easy to repeat within close proximity

Reliance on type curves for Estimated Ultimate Recoverable - EUR

Reliance on pressure or volume for EUR

Often insufficient wells for accurate analysis Often insufficient data for accurate analysis

Greater rock heterogeneity than expected Rock heterogeneity is always expected

Normalization of EUR to constant lateral length

Modeling of EUR range based on multiple variables

Rapid phase changes from oil to volatile oil to gas

PROVED RESERVES – 1P, 2P, 3P + PROBABLE & POSSIBLE

RESERVE CATEGORIES

Resource Classes

PDP = Proved Developed ProducingPNP = Proved Not Producing (behind pipe)PUD = Proved Undeveloped (requires drilling new well)

PROB= Probable

POSS = Possible

CONTINGENT (requires further proof of commerciality)

PROSPECTIVE (requires drilling new well to prove)

1P Reserves90% Probability



7

Third Party Reserve Reports

� Rigorous process, standards, and methodology

� Satisfies SPE and SEC reporting standards

� Designed to provide banks, lenders, and investors a high degree of confidence in the accuracy of the numbers

� Options for price deck using flat, projected, or NYMEX strip price

� The PROBABLE and POSSIBLE reserve category are still part of the Commercial Reserves category and acknowledge a certain percentage probability of additional Commercial Reserves beyond the PROVED

� Reserve Categories routinely change with updated results from offset operator drilling

PROVED RESERVES

Well

ProvedReservoir

Probable

Possible

Re

serv

oir

Pre

ssu

re

Cumulative Production

Conventional Water Drive Reservoir

Pressure Depletion Reservoir

#1 Proved Producing

#2 – Proved Undeveloped

#3 - Probable

Adjacent

Operator

Discovery

#3 – Proved Undeveloped

Resource Play Reservoir

8

RISKING PROVED / FORCE RANKING WELL OPERATIONS

APPLYING RISK AND NPV-10/INV RATIO

10

Reserve Category

17-Case Subset

Lease Name Field Reservoir Gross

Oil

(MBbls)

Gross

Gas

(MMcf)

Expense

& Tax

(M$)

Invest.

(M$)

Non-Risked

Cash Flow

$M

NPV-10 Non-

Risked $M

PROB

Geol

PROB

Oper

NPV-10

Risked

$M

RISKED

NPV-10 /INV

AVERAGE

NPV-10 /INV

Proved Undeveloped Lease A GOOD C Sand 95 0 980 75 2118 1859 67 75 934 12.5

Proved Behind Pi pe Leas e H GOOD F Sand 105 0 1316 75 3004 1477 100 50 738 9.8

Probabl e Undeveloped Lease B GOOD A Sand 0 1155 209 75 3238 1651 50 50 413 5.5

Proved Undeveloped Lease C GOOD C Sand 163 0 1835 0 4237 3466 75 75 1,949 5.3

Proved Behind Pi pe Lease C GOOD C Sand 122 0 1467 566 2957 1862 75 75 1,047 5.3

Probabl e Behind Pi pe Lease E GOOD J Sand 85 0 617 75 2775 1280 60 50 384 5.1

Proved Undeveloped Lease B GOOD A Sand 0 2088 830 75 2655 1494 50 50 374 5.0

Probabl e Undeveloped Lease B GOOD B Sand 0 1128 604 75 2369 992 50 50 248 3.3

Proved Undeveloped Lease A GOOD E Sand 25 0 302 75 641 314 75 75 177 2.4

Proved Undeveloped Lease K GOOD E Sand 122 0 821 550 2106 1690 80 80 1,082 2.0

Proved Behind Pi pe Leas e G GOOD H Sand 107 0 1042 550 2071 1735 75 80 1,041 1.9

Proved Behind Pi pe Lease E GOOD G Sand 24 0 284 75 388 356 75 50 133 1.8

Probabl e Undeveloped Lease F GOOD B Sand 192 0 1191 2635 4297 2098 100 75 1,574 0.6

Proved Undeveloped Lease J GOOD E Sand 0 3341 331 1550 6255 4236 20 50 424 0.3

Probabl e Undeveloped Lease F GOOD A Sand 88 0 435 1520 1154 934 60 50 280 0.2

Proved Undeveloped Leas e D GOOD D Sand 71 0 403 1550 261 53 80 50 21 0.0

Proved Undeveloped Leas e D GOOD F Sand 242 0 149 1550 5247 1966 0 0 0 0.0

Conventi ona l Approach 11,071 45,775 27,463 N/A N/A N/A 2.5

Ri sk Appl ied to 11 Cases 11,071 45,775 27,463 Appl iedAppl ied 10,819 1.0

Ri sk Appl ied & 1.5+ 2,266 28,561 18,175 Appl iedAppl ied 8,520 3.8

False High Ratio - Ignores existing risk & includes non-executable cases

The application of realistic risk reduces the NPV-10/INV to an unattractive ratio

Optimized results obtained by only selecting well operations with > 1.5:1

Geological risk and operational risk assessed and applied

Forced Ranking

Conventional Approach

Risk Applied to all cases

Risk Applied & > 1.5

COMBINING WELL OPERATIONS INTO SINGLE CASE

11

Reserve Category

11-Case Subset

Lease Name Field Reservoir Gross Oil

(MBbls)

Gross Gas

(MMcf)

Expense

& Tax

(M$)

Invest.

(M$)

Non-Risked

Cash Flow

$M

NPV-10 Non-

Risked $M

PROB

Geol

PROB

Oper

NPV-10

Risked $M

RISKED

NPV-10

/INV

INDIVIDUAL

NPV-10 /INV

Probable Undeveloped Lease A-1 GOOD A Sand 412 0 2459 5500 9617 5259 100 100 5,259 1.6 1.0

Probable Behind Pipe Lease A-1 GOOD C Sand 135 635 1699 75 5673 2579 100 100 2,579 1.6 34.4

Probable Behind Pipe Lease A-1 GOOD B Sand 110 0 678 570 3150 2216 100 100 2,216 1.6 3.9

Probable Undeveloped Lease B GOOD 1000' Sa nd 0 1360 305 2047 1049 407 100 100 407 0.6 0.2

Probable Undeveloped Lease B GOOD 900' Sand 0 900 385 75 1973 892 100 100 892 0.6 11.9

Proved Undeveloped Lease C-2 GOOD F Sand 15 0 372 75 254 89 100 100 89 0.8 1.2

Proved Undeveloped Lease C-2 GOOD E Sand 56 0 417 75 1742 855 100 100 855 0.8 11.4

Proved Undeveloped Lease C-2 GOOD D Sa nd 0 0 282 75 0 0 100 100 0 0.8 0.0

Proved Undeveloped Lease C-2 GOOD B Sand 19 0 454 2200 20 -22 100 100 -22 0.8 0.0

Proved Undeveloped Lease C-2 GOOD A Sand 0 1757 2059 570 2003 1500 100 100 1,500 0.8 2.6

Proved Undeveloped Lease C-2 GOOD C Sand 0 0 367 75 0 0 100 100 0 0.8 0.0

False high ratio due to not sharing the drill and completion costs

All well operations in the same wellbore are grouped together to generate a shared Risked NPV-10/INV Ratio

CONVENTIONAL VS. OPTIMIZED APPROACH

Reserve Category

Full Database PUD

& PRUD

Lease Name Field Reservoir Gross

Oil

(MBbls)

Gross

Gas

(MMcf)

Expense

& Tax

(M$)

Invest.

(M$)

Non-Risked

Cash Flow

$M

NPV-10 Non-

Risked $M

PROB

Geol

PROB

Oper

NPV-10

Risked

$M

Cases

Considered

AVERAGE

NPV-10 /INV

Conventional Approach PUD + PRUD GOOD PUD + PRUD 5,682 45,527 76,301 92,365 181,841 81,156 None None N/A ALL 0.9

Optimized PUD + PRUD GOOD PUD + PRUD 3,345 7,356 34,154 15,191 97,481 57,593 Appl iedAppl ied 47,938 1.5+ 3.2

When applied to all wells and all cases an optimized result is obtained

Executing all of the well operations results in 1/6 of the capital investment to generate more than half the same cash flow

UNDRILLED ACREAGE – TERM AND HBP

MINERAL RIGHTS

� US Government Land and Sea

� State Lands and Waterways

� Private Mineral Ownership

14

RED = Gas FieldsGREEN = Oil Fields

ALL OTHER COLORS = Acreage Controlled by Various Departments of the Federal Government’

Basic Lease Terms

� Negotiated with private mineral owner or state or US Government

� Royalty – generally1/8 to 1/4 (12.5% to 25%)

� Lease Bonus – $20/acre to $20,000+/acre

� Rentals – often fully paid up but certain states have annual rental payments

� Term – often 3 to 5 years, but can be 10 years or more

� Renewals – options available

Restrictions and Limitations

� Pugh Clauses – depth limitation

� Continuous Drilling Clauses

� Held by Production – HBP

TERM LEASES

15

VALUATION CHALLENGES USING PRECEDENT TRANSACTIONS

Multiple variables simultaneously interact both positively and negatively to impact the valuation of undrilled acreage including:

� Date and oil/gas prices at time of transaction

� Market trend increasing or decreasing at time of transaction

� Costs for pipeline transportation, processing, compression, and basis differential(s)

� Type curve(s) supporting precedent transaction vs type curve(s) for valuation target

� Geological setting in basin relative to TOC (total organic content), depth, reservoir thickness, maturity

� Local basin drilling rig and drilling permitting activity

� Drilling and completion costs for precedent transaction vs. valuation target

� Identification of ‘best practices’ drilling and completion techniques for model

� Normalization of lateral lengths to EUR (estimated ultimate recovery)

� Normalization of frac stages and proppant to valuation target

� Number of acres

� Percentage of acres in contiguous blocks to create production units

� Percentage of “loose” acreage scattered throughout area

17

PRECEDENT TRANSACTION VALUATION

MARCELLUS TRANSACTION COMPS

Announce

DateBuyers Sellers

Deal Value

($MM)Acres $/Acre (Est.)

Spot

Price of

NG/Mcf

$/Acre

(Adjusted)

New Deal

Value ($MM)

6/9/2014 American Energy Partners LP East Resources Inc $1,750 75001 $23,333.00 4.59 $ 8,124.30 $609

6/30/2014 Antero Resources Corp¹ Undisclosed Seller $95 6363 $14,930.00 4.59 $ 5,198.47 $33

7/7/2014 Rice Energy Inc Chesapeake; Statoil $330 33051 $9,969.55 4.05 $ 4,085.88 $135

7/29/2014

Mountaineer Keystone

Energy LLC

PDC; Lime Rock

Partners $500 131000 $4,750.00 4.05 $ 1,946.72 $255

8/13/2014 Shell¹ Ultra Petroleum $925 154993 $5,968.00 3.91 $ 2,563.57 $397

9/30/2014 Antero Resources Corp¹ Undisclosed Seller $185 12000 $15,417.00 3.92 $ 6,599.74 $79

10/16/2014 Southwestern Energy Chesapeake; Statoil $4,975 413000 $12,046.00 3.78 $ 5,416.37 $2,237

12/2/2014 Southwestern Energy WPX Energy Inc $288 46700 $6,167.00 3.48 $ 3,108.37 $145

12/22/2014 Southwestern Energy¹ Statoil $365 64238 $5,682.00 3.48 $ 2,863.91 $184

4/3/2015 TH Exploration LLC Trans Energy Inc $71 5159 $10,100.00 2.61 $ 7,841.61 $40

5/26/2015 Antero Resources Corp¹

Magnum Hunter

Resources Corp $41 5210 $7,869.00 2.85 $ 5,316.89 $28

7/1/2015 Alpha Natural Resources¹ EDF $126 12500 $10,080.00 2.84 $ 6,847.83 $86

Source: PLS, A&D Center

(1) Transaction only included acreage

The original $/acre payment is adjusted and normalized to current gas prices and takes into account operating and transportation costs to calculate the Adjusted $/acre


Source: PLS

$0.00

$5,000.00

$10,000.00

$15,000.00

$20,000.00

$25,000.00

4/21/2014 6/10/2014 7/30/2014 9/18/2014 11/7/2014 12/27/2014 2/15/2015 4/6/2015 5/26/2015 7/15/2015 9/3/2015

$/A

cre

Date

Transaction Comps

$/Acre (Actual)

$/Acre (Adjusted)

The Adjusted $/acre oscillates around $5000/acre


20

Rig CountNat. Gas PricesPermits

Source: PLS, Drilling Info, and Baker Hughes

It is important to compare all precedent transactions to key developments in the basin and industry including dropping natural gas prices, rig counts, and drilling permits

VALUATION CHALLENGES USING DRILL-OUT OPTION

.

The fundamental assumption with this option is that the operator will attempt to drill all of the possible undrilled wells on term and HBP acreage, with the following concerns, necessities, and limitations

� Identify all potential well locations on undrilled acreage

� Remove all PDP and PUD locations

� How much of the acreage is clustered into sufficient density to create drilling units?

� What percentage of acreage does the operator control within a unit?

� What are the actual or predicted drilling, completion, and lease operating expenses?

� What are the gathering system, processing, compression, and pipeline costs?

� What basis differential at final sales point?

� What is the EUR – Estimated Ultimate Recoverable reserves per well?

� What price deck – NYMEX strip?

� What is the rig availability?

� What permitting time, restrictions (e.g. migratory birds and deer), and limitations exist?

� If the answer to all is positive IRR and NPV then continue, otherwise move to next area

� THE definitive answer to EUR for any resource play is the All Important Type Curve

THE DRILL OUT OPTION

22

.

Definition and Application

� Quantitative and qualitative method of analyzing reservoir and field production

� Performed by using a sample set of wells in a given area or reservoir and evaluating the average historical production to determine the decline curve that best matches that production

� Decline curve then used to project future production on a single well basis through the manipulation of many variables that affect the overall decline of the curve

� Variables include hyperbolic exponent (b-factor), initial production (IP), effective initial decline, and terminal decline

� Estimated ultimate recovery (EUR) can be calculated using these variables

� The wells that factor into a type curve must be cautiously categorized into groups with similar well traits

� Traits include but are not limited to operator, basin, field, reservoir, well status, production date, and drill type

� With a precise EUR calculation, many different economic scenarios can be ran to determine a reasonably accurate value for acreage

THE ALL IMPORTANT TYPE CURVE

Type Curve Projection

Definition and Application

� B factor is a coefficient used in the Arps decline curve equation to model either exponential or hyperbolic decline, depending on the reservoir and production characteristics

� Exponential decline, using the b value of zero is exhibited by a straight line on a semi-log graph, whereas hyperbolic decline with b values ranging from zero to 1 represent a decline that is characterized by an early steep drop followed by flattening, which is typical of tight gas formations including shale

� When modeling shale gas decline, it is not uncommon for reservoir engineers to use b-factors in excess of 1

� The problem with values greater than 1, is that they will approach unreasonable amounts over the entire life of the well

� Therefore, after a substantial b-factor has been applied to the initial decline (1.1-1.4), a terminal exponential decline should be used to realistically project the EUR

THE B-FACTOR

Exponential Decline (b = 0)

EUR = 3.1 Bcf

Hyperbolic Decline (b = .8)

EUR = 4.2 Bcf

Hyperbolic Decline (b = 1)

EUR = 5.9 Bcf

Hyperbolic Decline (b = 1.2)

EUR = 7.4 Bcf

Hyperbolic Decline (b = 1.4)

EUR = 11.6 Bcf

24

MARCELLUS ACREAGE

25

The following slides demonstrate an example of analyzing a cluster of wells surrounding an undrilled acreage position in southwestern Pennsylvania. The comparison looks at where the wells sit in the basin, and how selectively choosing different wells to generate the type curves yields significantly different results

MARCELLUS ACREAGE W/ THICKNESS

26

The yellow acreage has numerous producing wells around it. The question to be answered is which wells should be included in a type curve and why. The Marcellus thickness map suggests that the southern wells are more similar in thickness to the yellow acreage than the northern wells

MARCELLUS ACREAGE W/ DEPTH

27

The Marcellus depth map is further evidence that the southern wells are more similar to the acreage than the shallower northern wells

TYPE CURVE ALL WELLS

28

Source: DrillingInfo(1) Source: EQT(2) PV 10 Net Revenue after 25 years, $35.00 oil, $2.25 gas, 100% WI, $10,000 LOE/mo, 80% NRI, economic limit of 30 boe/dNOTE: # of wells reported will differ from data shown on bubble map and type curve due to lack of information on publicly available data

PV 0: $20,458,000D&C¹: $5,750,000

PV 10²: $4,217,000

41 Wells

Observations

� While the type curve for all these wells is fairly decent, it is important to break out certain areas and completion techniques to understand which wells are contributing the most to the curve.

All 41 wells generate a type curve with an EUR of 9.1 BCF and PV-10 of $4.2 MM

TYPE CURVE NORTHERN WELLS

29


PV 0: $16,557,000D&C¹: $5,750,000

PV 10²: $1,739,000

13 Wells

Observations

� These wells North of the acreage have lower reservoir thickness as well as lower depth compared to the wells South of the acreage

The northern 13 wells generate a type curve with an EUR of 7.4 BCF and PV-10 of $1.7 MM

TYPE CURVE SOUTHERN WELLS

30


PV 0: $22,663,000D&C¹: $5,750,000

PV 10²: $5,618,000

28 Wells

Observations

� These wells South of the acreage have slightly greater depths and reservoir thickness than the wells to the North, which could explain the difference in IP and EUR

The southern 28 wells generate a type curve with an EUR of 10.1 BCF and PV-10 of $5.6 MM

TYPE CURVE (2010-2013)

31


2011-PV10: $6.4MM-EUR: 10.6 Bcf-Avg. Lat. Length: 3,700 ft -b-factor: 1.3




Breaking out the wells to the year they were drilled yields the clear trend of longer laterals, higher EURs, and higher NPV-10 with the most recent drilling, suggesting that new drill wells will achieve the same or better results

P2

P5

P10

P20

P30

P40

P50

P60

P70

P80

P90

P95

P98

P90

P50Mean

P10

1.0 10.0 100.0 1,000.0 10,000.0 100,000.0

Cumulative

Probability >>>

EUR GAS (MMCF)

Distribution

Data Points

P99 = 2501.4

P90 = 3702.8

P50 = 5990.8

Mean = 6343.4

P10 = 9692.5

P1 = 14347.9

Swansons Mean 6,414.90

Statistical Mean -Untruncated

6,428.20

Arithmetic Mean 6,335.97

TESTING EUR SENSITIVITY TO LATERAL LENGTH

ADJUSTED EUR GAS (MMCF) TO 5000’ LATERAL2010-2013 HORIZONTAL WELLS (13 WELLS)

Calculating the BCF yield per 1000 ft of lateral length then plotting the distribution of wells allows an estimate of average EUR based on lateral length

P2

P5

P10

P20

P30

P40

P50

P60

P70

P80

P90

P95

P98

P90

P50Mean

P10

1.0 10.0 100.0 1,000.0 10,000.0 100,000.0

Cumulative

Probability >>>

EUR GAS (MMCF)

Distribution

Data Points

P99 = 3001.6

P90 = 4443.3

P50 = 7188.9

Mean = 7612.1

P10 = 11631.0

P1 = 17217.5

Swansons Mean 7,697.88

Statistical Mean -Untruncated

7,713.84

Arithmetic Mean 7,603.17

ADJUSTED EUR GAS (MMCF) TO 6000’ LATERAL2010-2013 HORIZONTAL WELLS (13 WELLS)

TESTING EUR SENSITIVITY TO LATERAL LENGTH

FIELD OPERATIONS COST ANALYSIS / OPTIMIZATION

Production operations

require continuous

monitoring during the life

of a field

Optimization is

dependent upon

producing conditions and

pricing environment

PRODUCTION COST OPTIMIZATION

� The valuation of producing assets is based upon the current production rates, EUR, LOEs, downtime, ‘non-recurring costs’, future CAPEX and D&C costs

� The level of production optimization employed by an operator dramatically affects the current valuation, as well as the upside potential to be gained by production optimization

35

Operations need to be optimized to maximize profit and equipment service life

� Facility equipment including pumps, electric motors and gas compressors probably installed early in life of field

� Declining rates and pressures could provide opportunity to reduce costs

� Pumps could be swapped out or modified to fit current application reducing repair costs and downtime

� Electric motors could be properly matched to horsepower requirements, reducing power consumption and cost

� Compressors could be modified or swapped out reducing costs and downtime

� Numerous types of artificial lift equipment may be utilized within a field

� Surfactant Injection (capillary string)

� Plunger Lift

� Progressive cavity pump

� Gas lift

� Rod pump

� Hydraulic pump

� Electrical submersible pump (ESP)

� The more liquid a lift method can handle, the more expensive it is to maintain and operate

36

SURVEYING FIELD OPERATIONS

Increasing liquid volume handling capacity

Many variables affect the efficiency of an artificial lift system. A partial list of variables for a rod pumped well are shown below.

� Pumping unit size

� Stroke length and speed

� Sucker rod size and type

� Downhole pump type and size

� Pump intake pressure

� Gas oil ratio, well head pressure

� Type of fluid produced

� Pump spacing, compression ratio

� Plunger/barrel clearance

Changing conditions during well life cycle necessitate revising equipment design to maximize efficiency

37

ARTIFICIAL LIFT

� A major operating cost driver is well failures

� Controlling equipment failures is critical to optimizing field operations and profitability

� Operating artificial lift equipment outside of design capacities increase equipment failures

� ESP equipment operating below its designed range will prematurely fail

� Over stressed rod pump equipment will lead to premature sucker failures due to buckling and increased tubing wear

� Optimization of operating practices for mitigating scale, corrosion, emulsions, paraffin and H2S will reduce costs and failures

� Example: running a plunger in a gas lifted well may remove paraffin build up more effectively than chemical treating

� Determine the proper balance between maximum production rate operating cost

� Optimization work could have the best rates of return of any project within a company’s portfolio

38

CONTROLLING DOWNTIME

The following slide demonstrates a Wellbore Utility Chart which is critical to develop for EVERY field to identify exactly what the well has produced from each formation, where it currently is producing, and what future uphole (PBP or PDNP) exists.

The Wellbore Schematic Diagram on the next slide presents a cross-section of the well showing the casing, plugs, tubing, packers, and current state of the wellbore.

If an operator does not have both of these organizational tools and does not constantly update them, then there is a risk of future mechanical problems, lost or forgotten behind pipe pay, and future risks when plugging and abandoning the wells

QUESTION TO BE RESOLVED

1/27/2012 Injector POSSIBLY WET

NMOCD res test by May 31,

2012

NMOCD restest by May 31,

2012


2012

NMOCD restes t by May 31,

2012

WELL Name

TWIN LAKES SAN ANDRES

UNIT 1


UNIT 2


UNIT 3


UNIT 4


UNIT 5


UNIT 6


UNIT 7


UNIT 8


UNIT 9


UNIT 10


UNIT 11


UNIT 12


UNIT 13


UNIT 14


UNIT 15


UNIT 16


UNIT 17


UNIT 18


UNIT 19


UNIT 20


UNIT 21


UNIT 22


UNIT 23


UNIT 24


UNIT 25


UNIT 26


UNIT 27


UNIT 28


UNIT 29


UNIT 30


UNIT 31


UNIT 32

TWIN LAKES SAN ANDRES UNIT

33


UNIT 34 WELL NUMBER

STATUS Injection Well-Shut in Injection Well-Shut in

TxA (no pump jack

or no inj string) Injection Well-Shut in

TxA (no pump jack

or no inj string) Injection Well-Shut in probably P&A,

TxA (no pump jack


TxA (no pump jack

or no inj string) Injection Well-Unknown Pumping Injection Well-Shut in

TxA (no pump jack or no inj

string) Injection Well-Shut in Shut-in Injection Well-Shut in Shut-in Active P&A Injection Well-Shut in P&A P&A P&A Injection Well-Shut in Pumping Active Injector Shut-in Shut-in


string) P&A Injection Well-Shut in P&A Injection Well-Shut in STATUS

Comments

annulus on vacuum, slight

pressure on tubing

water injection plumbed

into tubing and annulus

no pump jack; capped

tubing string

water to surface, slight

pressure on annulus

annulus open to

atmosphere, no pump jack

no pressure on annulus nor

tubing no pump jack no pump jack

shown as inj on paper map;

listed as Inj in Drill ing Info

production reported July

2011; not surveyed by BJ

prod reported in June, July

2011; no pump jack

slight pressure on tubing

and annulus

pressure on tubing & annulus

while shut-in; old prod curve

indicates steady rate at only 1

1/2 bopd.

water to surface, no

pressure on annulus near Satellite A


tubing PxA, BJ confirmed PxA, BJ confirmed PxA, BJ confirmed

up and running as of Jan 1, 2012

with new motor; however, wrist

pin bearings may need repair

water to surface in tubing, no

pressure on annulus; BJ report

inactive

annulus open to atmosphere, no

pressure on tubing; good pump

jack, shut-in since June 2009

annulus open to

atmosphere; good pump

jack

no sign, tubing open to

atmosphere

PxA; appears to have been

redrilled by #123

injection head looks

functional


functional

SCHEMATIC 2002 1981 2001 SCHEMATIC

NM Lot NM Lot

API 30-005-62070 30-005-60648 30-005-60601 30-005-60579 30-005-60572 30-005-60596 30-005-60748 30-005-60492 30-005-60598 30-005-60571 30-005-60563 30-005-60578 30-005-60558 30-005-60597 30-005-62565 30-005-60470 30-005-60039 30-005-60536 30-005-60560 30-005-60 570 30-005-60658 30-00 5-60823 30-005-60965 3 0-005-60732 30-005-60334 30-005-60031 30-005-60521 30-005-61633 30-005-60569 30-005-60595 30-005-60695 30-005-60795 30-005-60814 30-005-60033 API

Old Name O'Brien F#9 O'Brien F#4 O'Brien Fee 25 #4 O'Brien Fee 25 #3 O'Brien K#2 O'Brien K#3 O'Brien F#7 O'Brien F#1 O'Brien F#3 O'Brien F#2 O'Brien Fee 25 #1 O'Brien Fee 25 #1 O'Brien K#1 O'Brien J#1 Pelto ?? State CH #3 Citgo A State #5 Citgo A State #6 Citgo A State #7 O'Brien I#1 O'Brien I#4 O'Brien J#8 O'Brien J#9 O'Brien F#6 State CH #2 Citgo State #1 Citgo State #4 Citgo State #7 Citgo State A#8 O'Brien I#2 O'Brien I#5 O'Brien J#3 O'Brien J#7 Citgo State CH#1

GR/KB elevation 3930/3941 3920 / 3926 3931 / 3937 3938 / 3944 3945 / 3951 3948 / 3954 3936 / 3942 3918 / 3922 3926 / 3932 3921 / 3923 3938 / 3944 3950 3954 / 3906 ?? 3966 / 3973 3930 / 3936 3951 / 3956 3939?? / 3947/3952 3955 / 3961 3965 / 3971 3974 / 3980 3972-3982.8 3974 / 3989 3940 / 3947 3932 / 3943 3957 3942 / 3948 3950 / 3960 3857 / 3862 3868 / 3874 3990 / 3996 3990 / 3998 3985 / 3995 3857.6 / 3862.6 KB elevation

Total Depth 2,691 2,770 2,829 0 2,870 2,760 2563 2,760 2,714 2,750 2,750 2,730 2,875 2907(PBTD 2822) 2,600 2,602 2,700 2,746 2,907 2,950 2750(PBTD 2730) 0 2,614 2,694 2,740 2,730 2918 (PBTD 2880) 2,861 2907( PBTD 2892) 2611 (PBTD 2600) Total Depth

Drill Year Drill Year

Location S:25, T:8S, R:28E S:25, T:8S, R:28E S:25, T:8S, R:28E S:30, T:8S, R:29E S:30, T:8S, R:29E S:26, T:8S, R:29E S:25, T:8S, R:28E S:25, T:8S, R:28E S:25, T:8S, R:28E S:25, T:8S, R:28E S:25, T:8S, R:28E S:30, T:8S, R:29E S:30, T:8S, R:29E S:30, T:8S, R:29E S:36, T:8S, R:28E S:36, T:8S, R:28E S:36, T:8S, R:28E S:36, T:8S, R:28E S:31, T:8S, R:29E S:31, T:8S, R:29E S:36, T:8S, R:28E S:36, T:8S, R:28E S:36, T:8S, R:28E S:36, T:8S, R:28E S:36, T:8S, R:28E S:31, T:8S, R:29E S:31, T:8S, R:29E S:31, T:8S, R:29E S:31, T:8S, R:29E S:36, T:8S, R:28E Location

;SA Q : 1490; SA: 1990

perf 2578-2623 2566-2604 2573-2614 2610-2656 2625-2660 2645-2690 2571-2594 2536-2563?? 2543-2578 2565-2599 2590-2631 2618-2700 2635-2680 2647-2698 2701-2748.5 2540-2583 2551-2606 2589-2632 2609-2655 2645.5-2683.5 2682.5-2719 2708-2749 2724.5-2744.5 2539-2573 2530-2583 2564-2608 2581-2620 2611-2647 2623-2664 2661.5-2694.5 2691-2722.5 2709.5-2752 2747.5-2778 2576-2581

cum oil - Bbl 1,521 18,677 16,868 765 0 85 0 69,836 83,735 7 0 7,419 0 17,328 74,882 534 75,711 65,915 0 12,898 118,340 74,300 34,349 530 1,430 274

cum gas - mcf 1,754 76,085 5,530 0 0 841 0 140,310 60,447 0 0 741 0 50,237 71,127 0 90,736 60,228 0 43,690 72,681 64,352 14,417 0 0 214,505

cum water - Bbl 62,368 41,085 71,877 499,007 68,267 11,771 89,496 52,260 156,113 100 368,824 144,626 42,991 234,528 66,418 10,645 359,260 687,631 53,093 151,691 223,419 270,487 443,149 10,647 262,793 265,882 191,881

firs t prod Jan-84 Feb-83 Sep-79 Mar-96 Jan-01 Mar-79 Feb-03 Jul-79 Jun-79 Jun-11 Jan-01 Sep-95 Feb-03 Jan-08 Feb-68 Jan-08 May-79 Mar-80 Jan-01 Jan-08 Oct-67 Jan-08 Jul-82 Jan-08 Jan-01 Jan-01 Oct-71

las t prod Dec-08 Dec-08 Jul-11 Jun-11 Jul-11 Sep-03 Dec-08 Jul-11 Jul-11 Jul-11 Jul-11 Jul-11 Jul-11 May-11 Jan-88 May-11 Jul-11 Jul-11 Dec-08 Jul-11 Jun-09 Jul-11 Jun-11 Apr-11 Jun-11 Jul-11 Jan-88

net sand

running as of Jan 1, 2012

with new motor; however,

wrist pin bearings may need repair

comments

formation top TVDSS

perf Pot'l 2644-2664 Pot'l 2627-2647 Pot'l 2642-TD 2658 Pot'l 2679-2698 Pot'l 2690-2728 Pot'l 2690-2728 Pot'l 2616-2634 NDE Pot'l 2606-2654 Pot'l 2628-2648 Pot'l 2660-2675 Pot'l 2682-2700 Pot'l 2700-2722 Pot'l 2724-2752 Pot'l 2778-2794 NDE NDE Pot'l 2670-2688 Pot'l 2684-2704 Pot'l 2712-2733 Fish @ 2758 Pot'l 2773-2794 Pot'l 2795-2814 2608-2621 NDE 2623-2660 Pot'l 2648-2678 Pot'l 2602-2674 ?? Pot'l 2690-2710 Pot'l 2830-2840 NDE? Pot'l 2750-2772 2782-2789 2606-2611

cum oil - Bbl 2734-2738 2618-2700

cum gas - mcf

cum water - Bbl

firs t prod

las t prod

net sand

FB

comments

formation top TVDSS

perf

cum oil - Bbl

cum gas - mcfcum water - Bbl

firs t prod

las t prod

net sand


2012


2012

NMOCD restest by Ma y 31,

2012

WELL Name


UNIT 35


UNIT 36


UNIT 37


UNIT 38


UNIT 39


UNIT 40


UNIT 41


UNIT 42


UNIT 43


UNIT 44


UNIT 45


UNIT 46


UNIT 47


UNIT 48


UNIT 49


UNIT 50


UNIT 51


UNIT 52


UNIT 53


UNIT 54


UNIT 55


UNIT 56


UNIT 57


UNIT 58


UNIT 59


UNIT 60


UNIT 61


UNIT 62


UNIT 63


UNIT 64


UNIT 65


UNIT 66


67


UNIT 68

STATUS InjectorTxA ProducerTxA Pumping InjectorPxA ProducerShut-in Flowing Active Injection Well Active Dry hole Pumping Active Pumping Flowing Pumping InjectorShut-in TxA (no pump jack) Injection Well Active Injector Injection Well Active Shut-in Pumping Flowing Active Shut-in Injection Well Active Pumping Active Pumping Flowing

gas pressure on annulus;

tubing open to

atmosphere.

old pump jack, no motor,

with rods in well

active producer, annulus

open to atmosphere

PxA; pole with info for #38;

not listed in DI, though

parted rods per Anderson,

after previ ous workover; l at

l ong per BJ must have a typo;

s tuck with or igi nal data in

table gas pressure on annulus

no pump jack, rods in hole,

annulus and tubing open

to atmosphere no pump jack

lat long estimated from MS

map; Bruce searched and

could not find; last

injection 2009, no plugging

permit

TxA, lat long estimated

from paper map; last

production 1992

recently repaired pump

jack and returned to

production

horse head, rods, stuffing

box damaged

confirmed prod; need

production test and water

cut

#50 will take water and

maintain surface pressure

No pump jack. Tbg string is

capped off. Casing string

will flow pure oil for 2

seconds then die.

lat long estimated from

paper map, pad confirmed

in Google Earth, last

injection 2009

PxA; pole on ground; lat

long adj per google earth

Previous producer (pad);

check lat long; BJ lat long is

off; lat long taken from

Google Earth using pad

location in Drill ing Info

slight pressure on tubing,

annulus on vacuum,

located next to PxA #4 (per

BJ…but #4 is not on our

map)

recently replaced stuffing

box

motor used to trip on

overload; confirm status

pressure on annulus with

water at surface; no

pressure on tubing water to surface in annulus

probably TxA, lat long

estimated from paper

map, pad confirmed in

Google Earth, last prod

1994, no plugging permit

injection tubing open to

atmosphere; not

connected at Inj manifold

pump jack has major gear

box damage

pump unit needs to be

reset no pressure on annulus

repairing electrical surge

protector, ordered pitman arm

bearings; good well

#68 will take water on a

vacuum

SCHEMATIC

NM Lot

API 30-005-60026 30-005-60329 30-005-60973 30-005-60533 30-005-60657 30-005-60696 30-005-60768 30-005-60802 30-005-60829 30-005-60717 30-005-00342 30-005-60291 30-005-60010 30-005-60697 30-005-60767 30-005-60796 30-005-60810 30-005-60961 30-005-10140 30-005-00349 30-005-60297 30-005-60028 30-005-61135 30-005-61031 30-005-60807 30-005-60824 30-005-60920 30-005-60962 30-005-62563 30-005-62069 30-005-60293 30-005-60468 30-005-61096 30-005-61007

Citgo StatE A#3 Citgo State #2 Citgo State #6 Citgo State #5 Citgo State I#3 O'Brien I#6 O'Brien J#2 O'Brien J#5 O'Brien N#1 O'Brien F#5 Citgo A State #2 Citgo A State #1 Citgo State #3 O'Brien I#7 O'Brien I#8 O'BrienJ #4 O'Brien J #6 O'Brien N #2-Y O'Brien B #2 O'Brien C #2 O'Brien C #6 O'Brien C #5 O'Brien E #7 O'Brien L #12 O'Brien L #1 O'Brien L #2 O'Brien L #3 O'Brien L #6 Pelto ?? TO BE DRILLED O'Brien E #9 O'Brien C #7 O'Brien E #1 O'Brien E #6 O'Brien L #10

GR elevation / KB elevatiom 3965 / 3966 3942 / 3950 3947/3952 3956 '/ 3962 3685 / 3991 4000 / 4010 3990 / 3997 3950 3846 3980 3936 3979 3984 4002 4009 3984 3951 3940 3940 3966 3965 3995

Total Depth 2,615 2,645 2,750 2730 (PBTD 2719) 2,870 2,903 2,930 2,950 3,000 2,800 2,630 2,695 6,370 2,901 2,900 2,950 2,950 7,346 7,350 2,770 9,800 2,867 2,950 2,960 3,100 2,680 0 2,575 2,740 2,810

Drill Year

Location S:36, T:8S, R:28E S:36, T:8S, R:28E S:36, T:8S, R:28E S:31, T:8S, R:29E S:31, T:8S, R:29E S:31, T:8S, R:29E S:31, T:8S, R:29E S:32, T:8S, R:29E S:36, T:8S, R:28E S:36, T:8S, R:28E S:36, T:8S, R:28E S:31, T:8S, R:29E S:31, T:8S, R:29E S:31, T:8S, R:29E S:31, T:8S, R:29E S:32, T:8S, R:29E S:1, T:9S, R:28E S:1, T:9S, R:28E S:1, T:9S, R:28E S:1, T:9S, R:28E S:6, T:9S, R:29E S:6, T:9S, R:29E S:6, T:9S, R:29E S:6, T:9S, R:29E S:5, T:9S, R:29E S:1, T:9S, R:28E S:1, T:9S, R:28E S:1, T:9S, R:28E S:1, T:9S, R:28E S:6, T:9S, R:29E RESERVOIR

formation top TVDSS

perf 2563-2603 2586-2638 2603-2634.5 2600-2650 2656-2702.5 2697-2639 2717-2756 2753-2783 2806-2832 2664-2698 2714-2731 2737-2776 2783-2811 2665-2690 2703-2732 2734-2763 2755-2795 2780-2823 2675-2707

cum oil - Bbl 89,927 44,087 32,064 37,483 2,146 201 60 75,816 16,848 32,536 2,537 25,651 83,116 0 49,466 15,423 37,977 0 28,912 16,419 0 0 3,914 16,406 1,435 24,775

cum gas - mcf 213,291 40,464 23,513 0 0 0 0 201,612 24,086 8,330 0 37 65,024 0 40,968 38,413 27,743 0 4,244 0 0 0 6,080 33 0 1,855

cum water - Bbl 33,801 191,451 280,415 728,912 327,535 188,866 328,014 37,652 384,106 130,518 255,904 172,210 702,059 545,524 65,343 283,762 430,617 42,696 208,633 52,939 197,362 202,629 875,139 468,953 19,220 219,168 274,171 43,626 150,090 446,396

firs t prod Sep-67 May-75 Sep-81 Jan-93 Jan-01 Jun-93 Apr-96 Jan-01 Jan-70 Jan-75 Dec-77 Jan-01 Jan-93 Jan-01 Jul-99 Jan-01 Dec-50 May-74 Sep-67 May-01 Jan-93 Jan-01 Jan-93 Jan-01 Feb-01 Feb-84 Jan-93 Feb-03 Jan-93 Jan-01

las t prod Jun-87 May-11 Jul-11 Jun-11 Jul-11 Jun-11 Dec-00 Dec-08 Jul-11 Jul-11 May-11 Jun-11 Jul-11 Jul-11 Jul-11 Dec-08 Jul-11 Jul-11 Jul-11 Jul-11 Jul-11 Jul-11 May-11 Jul-11 Dec-08 May-11 May-11 Jun-11 Jul-11 Jul-11

net sand

confirmed prod; need prod test; bucket test was not

successful (too much

pressure)

FB

comments

formation top TVDSS

perf NDE 2671.5-2687 2681-2695 Pot'l 2724-2752 xxxx-xxxx 2785-2795 xxxx-xxxx Pot'l 2606-2619 XXXX-XXXX???? Pot'L 2756-2763 2813-2834 NDE XXXX-XXXX Pot'l 2608-2660 Pot'l 2690-TD 2729-2743 2767-2777 2800-2824 Pot'l 2845-2880 Pot'l 2688-2708 2736-2758

cum oil - Bbl

cum gas - mcf

cum water - Bbl

firs t prod

las t prod

net sand

FB

comments Deeper

formation top TVDSS

perf

cum oil - Bbl

cum gas - mcf

cum water - Bbl

firs t prod

las t prod

net sand

FB

comments


2012


2012


2012

WELL Name


UNIT 69


UNIT 70


UNIT 71


UNIT 72


UNIT 73


74


75


76


77


UNIT 78


UNIT 79


UNIT 80


UNIT 81


UNIT 82


UNIT 83


UNIT 84


UNIT 85


UNIT 86


UNIT 87


UNIT 88


UNIT 89


UNIT 90


UNIT 91


UNIT 92


UNIT 93


UNIT 94


UNIT 95


UNIT 96


UNIT 97


UNIT 98


UNIT 99


UNIT 100


101 WELL NUMBER

STATUS Pumping Flowing Active Injection Well Shut-in Injection Well Shut-in Flowing Pumping Pumping Active Injector Active Injection Well Shut-in Flowing Active Active Pumping Pumping Active Active Active Active STATUS

S/I Dec 2011, back on l ine

Jan 1, 2012; wrist pin worn

out, needs repair; ordered

bearings


vacuum

pump does not move fluid;

unit has pump off

controller that doesn't

function PxA; PxA;

shut-in injector; note: a

PxA pole for #74 is laying

on site; maybe had plans

for PxA and never

implemented?



map; pad confirmed in

Google Earth, last

production in 2000. no pressure on tubing

no pump jack; tubing open

to atmosphere no pressure on tubing pump does not move fluid pump does not move fluid active per BJ and Anderson PxA PxA PxA

pump jack out of

alignment, no pressure on

tubing, annulus open to

atmosphere water to surface in annulus pump jack removed

no pressure on tubing nor

annulus pump jack removed

probably PxA, lat long

estimated from MS Map,

applied for plugging

permit. Prior producer,

convert to inj, then

plugged

gas pressure on tubing and

annulus, blows down

quickly normally active well PxA

won't pump fluid to

surface; good pump jack;

water to surface on tubing;

closed at inj manifold PxA date 10/19/1999


estimated from MS Map;




plugged PxA

tubing and annulus open

to atmosphere, no

pressure; no motor

no pressure on tubing,

pressure in annulus with

oil/water at surface;

closed at inj manifold;

review history; newer pump jack, no motor

SCHEMATIC SCHEMATIC

NM Lot NM Lot

API 30-005-60984 30-005-60885 30-005-62212 30-005-60886 30-005-60983 30-005-60248 30-005-60469 30-005-60809 30-005-61032 30-005-60995 30-005-60982 30-005-62213 30-005-60993 30-005-60994 30-005-62564 30-005-61363 30-005-60659 30-005-60794 30-005-61030 30-005-61006 30-005-61022 30-005-61033 30-005-60790 30-005-61095 30-005-61603 30-005-61106 30-005-61107 30-005-61076 30-005-61110 30-005-61362 30-005-61261 30-005-61105 30-005-61452 API

O'Brien L#8 O'Brien L#4 O'Brien L#15 O'Brien L#5 O'Brien L#7 O'Brien C#3 O'Brien E#2 O'Brien E#5 O'Brien L#13 O'Brien L#9 O'Brien FF#1 O'Brien L#16 O'Brien FF#2 O'Brien FF#3 Drilled? O'Brien E#8 O'Brien E#3 O'Brien E#4 O'Brien L#11 O'Brien FF#4 O'Brien FF#5 O'Brien FF#6 O'Brien D#2 O'Brien D#3 Moonshine 7#12 Moonshine 7 #5 Moonshine 7 #6 O'Brien GG #1 O'Brien GG #2 O'Brien D #5 O'Brien D #4 Moonshine 7 #4 Moonshine 7 #10

GR elevation 3996 3951 3976 3981 3981 3870 3962 3945 3943 3910 KB elevation

Total Depth 2,850 2,850 2,900 7,318 2,730 2,820 2,825 2,850 2,925 2,880 2,800 2,774 2,800 2,880 2,810 2,740 0 2,840 0 2,780 2,780 Total Depth


Location S:6, T:9S, R:29E S:6, T:9S, R:29E S:6, T:9S, R:29E S:1, T:9S, R:28E S:1, T:9S, R:28E S:1, T:9S, R:28E S:6, T:9S, R:29E S:6, T:9S, R:29E S:6, T:9S, R:29E S:6, T:9S, R:29E S:6, T:9S, R:29E S:1, T:9S, R:28E S:1, T:9S, R:28E S:6, T:9S, R:29E S:6, T:9S, R:29E S:6, T:9S, R:29E S:12, T:9S, R:28E S:12, T:9S, R:28E S:7, T:9S, R:29E S:7, T:9S, R:29E S:12, T:9S, R:28E S:7, T:9S, R:29E S:7, T:9S, R:29E Location RESERVOIR

formation top TVDSS formation top TVDSS

perf 2689-2627 2715-2749 2725-2767 2729-2756 2768-2822 2585-2611 ????-???? 2617-2256 2648-2684 2683-2712 2696-2736 2715-2757 2712-2753 2757-2799 2850-2894 2579-2607 2591-2624 2612-2647 2655-2679 2687-2721 2701-2737 2746-2792 2590-2629 2619-2644 2670-2689 2683-2717 2703-2740 2730-2775 2816-2852 2589-2610 ??2593-2614?? 2606-2645 2645-2657 perf

cum oil - Bbl 38,193 36,967 0 504 0 238 39,415 25,134 10,297 0 5,220 14,637 0 38,376 95,124 38,151 14,597 0 31,249 cum oil - Bbl

cum gas - mcf 7,061 0 0 0 0 0 1,778 19 0 0 8,592 0 0 467 23,592 9,276 0 0 8,142 cum gas - mcf

cum water - Bbl 253,259 811,742 1,450,920 43,164 48,655 45,187 1,384 674,542 800,883 1,300,146 768,906 351,539 32,963 4,684 572,338 397,082 66,607 166,780 132,747 99,022 293,756 172,355 249,094 cum water - Bbl

firs t prod Jan-93 Jan-01 Jan-93 Jul-03 Apr-93 May-01 May-95 Feb-01 Jan-93 Jan-93 Jan-01 Jan-93 Aug-02 Sep-95 Jan-01 Jan-93 May-01 Jan-93 Nov-81 Oct-81 Jan-93 Aug-01 Apr-82 first prod

las t prod Jul-11 Jul-11 Dec-10 Dec-08 Dec-00 Oct-10 Jul-11 Jul-11 Feb-11 Jan-11 Jul-11 May-11 Jul-11 Jul-11 Jul-11 Jun-11 Dec-08 Apr-11 May-11 Jul-11 May-11 Jul-11 May-11 last prod

net sand

S/I Dec 2011, back on line


out, needs repair net sand

FB FB

comments comments


perf 2761-2779 2773-2788 2789-2714 Pot'l 2794-2813 2845-2862 Pot'l 2630-2758 ????-???? Pot'l 2684-2700 2724-2741 2744-2758 2757-2775 2782-2807 2776-2793 Pot'l 2831-2845 Pot'l 2915-2933 Pot'l 2641-2660 ??? Hole Deep enough Pot'l 2679-2698 Pot'l 2710-2734 2740-2760 2764-2778 2804-2825 Pot'l 2648-2674 Pot'l 2664-2668 2700-2730 Lck 2720-2770 in P2 Pot'l 2756-2760 2796-2820++ NDE? 2878-2895 ??? Pot'l 2650-2665 Pot'l 2665-2708 Pot'l 2678-2702 perf

cum oil - Bbl 2897-2924 2757-2775 cum oil - Bbl

cum gas - mcf cum gas - mcf

cum water - Bbl cum water - Bbl

firs t prod first prod

las t prod last prod

net sand net sandFB FB

comments comments Deeper

formation top TVDSS

perf P3: 2706-2714+ formation top TVDSS

cum oil - Bbl perf

cum gas - mcf Pot'l P3:2712-2725 cum oil - Bbl

cum water - Bbl cum gas - mcf

firs t prod cum water - Bbl

las t prod first prod

net sand last prod

FB net sand

comments FB


2012


2012

WELL Name


UNIT 102


UNIT 103


UNIT 104


UNIT 105


UNIT 106


UNIT 107


UNIT 108


UNIT 109


UNIT 110


UNIT 111


UNIT 112


UNIT 113


UNIT 114


UNIT 115


UNIT 116


UNIT 117


UNIT 118


UNIT 119


UNIT 120


UNIT 121


UNIT 122


UNIT 123


UNIT 200


UNIT 201


UNIT 202


UNIT 203


UNIT 302


UNIT 311


UNIT 316


UNIT 319


UNIT 321


UNIT 326


329


UNIT 331 TWIN LAKES SAN ANDRES UNIT 333 WELL NUMBER

STATUS Shut-in Active Shut-in Active Injection Well Active Injection Well Active Injection Well Shut-in Injection Well Shut-in Injection Well Injection Well Shut-in Pumping Pumping Pumping Pumping Shut-in Pumping Pumping Pumping Active Pumping Pumping ProducerTxA (no pump jack) STATUS

newer pump jack, no

motor


presssure on annulus;

closed at inj manifold



confirmed pad in Google

Earth, applied for plugging

permit

no pressure on tubing or

annulus but water to

surface; closed at inj

manifold

broken pump jack, no

motor

tubing on vacuum, annulus

with pressure and slight oil

to surface (note, this is an

injector)


motor

oil seeping at the wellhead

- INJECTOR! ; lat long from

Google Earth using Drilling

Info pad location.

pump jack with no motor,

no head. Rod sticking out

of wellhead. closed at inj manifold no pump jack water to surface in annulus PxA

no pump jack, tubing open

to atmosphere PxA



map, confirmed pad in

Google Earth; applied for

plugging permit

tubing string on vacuum;

not connected at inj

manifold closed at inj manifold





plugging permit

tubing open to

atmosphere PxA confirmed prod confirmed prod no pump jack and no pad confirmed prod confirmed prod no pump jack, no flowine confirmed prod confirmed prod

up and running as of Jan 1,

2012; replaced burnt

motor

electric power

disconnected confirmed prod confirmed prod

prod reported in June, July 2011; no pump

jack

RESERVOIR

SCHEMATIC SCHEMATIC

NM Lot NM Lot

API 30-005-60844 30-005-61075 30-005-61116 30-005-62068 30-005-61332 30-005-61104 30-005-61334 30-005-61772 30-005-61556 30-005-61453 30-005-61333 30-005-61604 30-005-61622 30-005-61655 30-005-61735 30-005-61454 30-005-61736 30-005-61623 30-005-61624 30-005-62819 30-005-62818 30-005-62845 30-005-63138 30-005-63139 30-005-63147 30-005-63140 30-005-63191 30-005-63194 30-005-63185 30-005-63187 30-005-63188 30-005-63189 30-005-63190 30-005-63192 30-005-63193 API

Moonshine 7 #1 Moonshine 7 #2 O'Brien GG #3 O'Brien D #6 Moonshine 7 #7 Moonshine 7 #3 Moonshine 7 #9 O'Brien DB #3 O'Brien DB #1 Moonshine 7 #11 Moonshine 7 #8 Moonshine 7 #13 Moonshine 7 #14 O'Brien DB #2 Moonshine 18 #4 Moonshine 18 #1 Moonshine 18 #5 Moonshine 18 #2 Moonshine 18 #3 EDC #121 TLSAU ??? EDC #123 TLSAU Marbob #200 TLSAU Marbob #201 TLSAU Marbob #202 TLSAU Marbob #203 TLSAU Hanagan #302 TLSAU

GR elevation 3915 3905 3929 3928 3931 3928 3967 3974 3958 3951 3585 / 3591 3922 / 3929 3940 / 3947 3953 / 3927 3971 / 3977 4003 / 4009 3981 / 3987 4003 / 4009 3985 / 3991 3965 / 3971 3938 KB elevation

Total Depth 2,780 2,726 2,700 2,840 2,788 2,747 2,780 2,800 3,793 2,800 2,805 2,900 3,100 3,100 2,800 2,750 2,862 2,700 2,767 2,903 2,816 2,855 2,855 2,830 2,830 Total Depth


Location S:7, T:9S, R:29E S:7, T:9S, R:29E S:12, T:9S, R:28E S:7, T:9S, R:29E S:7, T:9S, R:29E S:7, T:9S, R:29E S:12, T:9S, R:28E S:12, T:9S, R:28E S:7, T:9S, R:29E S:7, T:9S, R:29E S:7, T:9S, R:29E S:12, T:9S, R:28E S:18, T:9S, R:29E S:18, T:9S, R:29E S:5, T:9S, R:29E S:31, T:8S, R:29E S:12, T:9S, R:28E S:36, T:8S, R:28E S:6, T:9S, R:29E S:25, T:8S, R:28E S:36, T:8S, R:28E S:31, T:8S, R:29E S:31, T:8S, R:29E S:31, T:8S, R:29E S:6, T:9S, R:29E S:6, T:9S, R:29E S:6, T:9S, R:29E Location


perf 2653-2672 2688-2706 2726-2773 ????-???? 2599-2639(2608-2646Log) 2667-2696 2683-2717 2632-2669 2630-2666 2640-2686 2675-2726 2724-2740 2739-2772 2675-2723 2698-2738 2745-2759 2732-2786 2837-2892 2642-2677 2616-2642 2626-2649 2545-2587 2670-2707 2572-2616 2681-2708 2638-2684 2670-2706 2712-2756 2694-2739 Lck 2697-2726 Lck 2708-2742 perf San Andres P1

cum oil - Bbl 37,966 0 0 3,851 0 17,371 0 5,437 0 59,535 0 114 0 0 71 30,705 30,825 18,196 45,645 319 5,678 6,186 7,386 3,697 12,589 10,960 1,711 cum oil - Bbl

cum gas - mcf 15,802 0 0 0 0 1,717 0 0 0 18,166 0 0 0 0 0 50 84 0 39 0 15 0 0 0 42 0 0 cum gas - mcf

cum water - Bbl 124,889 86,276 138,554 78,321 62,524 80,670 130,361 206,430 126,208 294,033 94,417 20,859 46,647 108,296 51,363 706,679 903,212 603,313 1,994,107 7,924 116,229 111,944 131,667 118,666 223,440 140,204 44,083 cum water - Bbl

firs t prod Mar-98 Aug-01 Feb-01 May-95 Aug-01 Mar-98 Feb-01 Jan-93 Aug-01 Sep-93 Feb-01 Mar-98 Feb-01 Feb-01 May-91 Jan-93 Sep-97 Sep-97 Oct-97 May-99 Feb-99 Jan-99 Jan-99 Jan-99 Jan-99 Jan-99 Apr-99 first prod

las t prod May-11 Jul-11 Jul-11 Apr-11 Jul-11 May-11 Dec-08 May-11 Jul-11 Jul-11 Jul-11 Jul-11 Dec-08 Nov-09 May-98 Jul-11 Jul-11 Jul-11 Jul-11 Apr-08 Jul-11 Jul-11 Jul-11 Jun-11 Jul-11 Jul-11 Jul-11 last prod

net sand net sand

FB FB

comments confirmed prod confirmed prod confirmed prod confirmed prod comments

formation top TVDSS NDE NDE 2797-2817 Lck 2794-2800 rathole? NDE Pot'l 2662-2788 Pot'l 2789-2826 2909-2913 2706-2711 2800-2824 2680-2684 Pot'l 2676-2690 2615-2626 2733-2740 Pot'l 2640-2658 2734-2772 Lck Pot'l 2705-2724 Pot'l 2736-2774 2777-2815 Pot'l 2758-2778 Lck 2746-2775 Lck Pot'l 2762-2782 formation top TVDSS

perf 2695-2726 Lck Channel to 2740 2800-2823 Pot'l 2652-2674 No Pay/ NDE ?(2670-92Log) Pot'l 2712-2735 No Pay/NDE Lck Pot'l 2685-2710 Pot'l 2682-2700 No Pay Rathole? Rathole? perf San Andres P2

cum oil - Bbl cum oil - Bbl





net sand net sand

FB FB

comments comments

formation top TVDSS

perf formation top TVDSS

cum oil - Bbl 2535-2549 2518-2532 2496-2512 2493-2500 2500-2514 perf Shallower

PDNP PDNP

SI GAS SI OIL

Active Injector

San Andres - P1

ABANDONED ?

Non-Canyon

San Andres - P1

San Andres - P2

Deeper

SI GAS PDNPPRODUCING OIL

Twin Lakes San Andreas Unit

WELLBORE UTILIZATION PRODUCING GAS

PDP PDPABANDONED COMPLETION

PDNP

ABANDONED COMPLETION

PLUGGED BACK orSI OIL

production reported in

July/July 2011; not surveyed

San Andres - P2

San Andres - P1

San Andres - P2

QUESTION TO BE RESOLVED

1/27/2012 Injector POSSIBLY WET


2012


2012


2012


2012

WELL Name


UNIT 1


UNIT 2


UNIT 3


UNIT 4


UNIT 5


UNIT 6


UNIT 7


UNIT 8


UNIT 9


UNIT 10


UNIT 11


UNIT 12


UNIT 13


UNIT 14


UNIT 15


UNIT 16


UNIT 17


UNIT 18


UNIT 19


UNIT 20


UNIT 21


UNIT 22


UNIT 23


UNIT 24


UNIT 25


UNIT 26


UNIT 27


UNIT 28


UNIT 29


UNIT 30


UNIT 31


UNIT 32


33


UNIT 34 WELL NUMBER

STATUS Injection Well-Shut in Injection Well-Shut in

TxA (no pump jack


TxA (no pump jack

or no inj string) Injection Well-Shut in probably P&A,

TxA (no pump jack


TxA (no pump jack

or no inj string) Injection Well-Unknown Pumping Injection Well-Shut in


string) Injection Well-Shut in Shut-in Injection Well-Shut in Shut-in Active P&A Injection Well-Shut in P&A P&A P&A Injection Well-Shut in Pumping Active Injector Shut-in Shut-in


string) P&A Injection Well-Shut in P&A Injection Well-Shut in STATUS

Comments

annulus on vacuum, slight

pressure on tubing

water injection plumbed

into tubing and annulus

no pump jack; capped

tubing string

water to surface, slight

pressure on annulus

annulus open to

atmosphere, no pump jack


tubing no pump jack no pump jack

shown as inj on paper map;

listed as Inj in Drill ing Info

production reported July

2011; not surveyed by BJ

prod reported in June, July

2011; no pump jack

slight pressure on tubing

and annulus

pressure on tubing & annulus

while shut-in; old prod curve

indicates steady rate at only 1

1/2 bopd.

water to surface, no

pressure on annulus near Satellite A


tubing PxA, BJ confirmed PxA, BJ confirmed PxA, BJ confirmed






inactive

annulus open to atmosphere, no

pressure on tubing; good pump

jack, shut-in since June 2009

annulus open to

atmosphere; good pump

jack

no sign, tubing open to

atmosphere

PxA; appears to have been

redrilled by #123


functional


functional

SCHEMATIC 2002 1981 2001 SCHEMATIC

NM Lot NM Lot

API 30-005-62070 30-005-60648 30-005-60601 30-005-60579 30-005-60572 30-005-60596 30-005-60748 30-005-60492 30-005-60598 30-005-60571 30-005-60563 30-005-60578 30-005-60558 30-005-60597 30-005-62565 30-005-60470 30-005-60039 30-005-60536 30-005-60560 30-005-60 570 30-005-60658 30-00 5-60823 30-005-60965 3 0-005-60732 30-005-60334 30-005-60031 30-005-60521 30-005-61633 30-005-60569 30-005-60595 30-005-60695 30-005-60795 30-005-60814 30-005-60033 API

Old Name O'Brien F#9 O'Brien F#4 O'Brien Fee 25 #4 O'Brien Fee 25 #3 O'Brien K#2 O'Brien K#3 O'Brien F#7 O'Brien F#1 O'Brien F#3 O'Brien F#2 O'Brien Fee 25 #1 O'Brien Fee 25 #1 O'Brien K#1 O'Brien J#1 Pelto ?? State CH #3 Citgo A State #5 Citgo A State #6 Citgo A State #7 O'Brien I#1 O'Brien I#4 O'Brien J#8 O'Brien J#9 O'Brien F#6 State CH #2 Citgo State #1 Citgo State #4 Citgo State #7 Citgo State A#8 O'Brien I#2 O'Brien I#5 O'Brien J#3 O'Brien J#7 Citgo State CH#1

GR/KB elevation 3930/3941 3920 / 3926 3931 / 3937 3938 / 3944 3945 / 3951 3948 / 3954 3936 / 3942 3918 / 3922 3926 / 3932 3921 / 3923 3938 / 3944 3950 3954 / 3906 ?? 3966 / 3973 3930 / 3936 3951 / 3956 3939?? / 3947/3952 3955 / 3961 3965 / 3971 3974 / 3980 3972-3982.8 3974 / 3989 3940 / 3947 3932 / 3943 3957 3942 / 3948 3950 / 3960 3857 / 3862 3868 / 3874 3990 / 3996 3990 / 3998 3985 / 3995 3857.6 / 3862.6 KB elevation

Total Depth 2,691 2,770 2,829 0 2,870 2,760 2563 2,760 2,714 2,750 2,750 2,730 2,875 2907(PBTD 2822) 2,600 2,602 2,700 2,746 2,907 2,950 2750(PBTD 2730) 0 2,614 2,694 2,740 2,730 2918 (PBTD 2880) 2,861 2907( PBTD 2892) 2611 (PBTD 2600) Total Depth


Location S:25, T:8S, R:28E S:25, T:8S, R:28E S:25, T:8S, R:28E S:30, T:8S, R:29E S:30, T:8S, R:29E S:26, T:8S, R:29E S:25, T:8S, R:28E S:25, T:8S, R:28E S:25, T:8S, R:28E S:25, T:8S, R:28E S:25, T:8S, R:28E S:30, T:8S, R:29E S:30, T:8S, R:29E S:30, T:8S, R:29E S:36, T:8S, R:28E S:36, T:8S, R:28E S:36, T:8S, R:28E S:36, T:8S, R:28E S:31, T:8S, R:29E S:31, T:8S, R:29E S:36, T:8S, R:28E S:36, T:8S, R:28E S:36, T:8S, R:28E S:36, T:8S, R:28E S:36, T:8S, R:28E S:31, T:8S, R:29E S:31, T:8S, R:29E S:31, T:8S, R:29E S:31, T:8S, R:29E S:36, T:8S, R:28E Location

;SA Q : 1490; SA: 1990

perf 2578-2623 2566-2604 2573-2614 2610-2656 2625-2660 2645-2690 2571-2594 2536-2563?? 2543-2578 2565-2599 2590-2631 2618-2700 2635-2680 2647-2698 2701-2748.5 2540-2583 2551-2606 2589-2632 2609-2655 2645.5-2683.5 2682.5-2719 2708-2749 2724.5-2744.5 2539-2573 2530-2583 2564-2608 2581-2620 2611-2647 2623-2664 2661.5-2694.5 2691-2722.5 2709.5-2752 2747.5-2778 2576-2581

cum oil - Bbl 1,521 18,677 16,868 765 0 85 0 69,836 83,735 7 0 7,419 0 17,328 74,882 534 75,711 65,915 0 12,898 118,340 74,300 34,349 530 1,430 274

cum gas - mcf 1,754 76,085 5,530 0 0 841 0 140,310 60,447 0 0 741 0 50,237 71,127 0 90,736 60,228 0 43,690 72,681 64,352 14,417 0 0 214,505

cum water - Bbl 62,368 41,085 71,877 499,007 68,267 11,771 89,496 52,260 156,113 100 368,824 144,626 42,991 234,528 66,418 10,645 359,260 687,631 53,093 151,691 223,419 270,487 443,149 10,647 262,793 265,882 191,881

firs t prod Jan-84 Feb-83 Sep-79 Mar-96 Jan-01 Mar-79 Feb-03 Jul-79 Jun-79 Jun-11 Jan-01 Sep-95 Feb-03 Jan-08 Feb-68 Jan-08 May-79 Mar-80 Jan-01 Jan-08 Oct-67 Jan-08 Jul-82 Jan-08 Jan-01 Jan-01 Oct-71

las t prod Dec-08 Dec-08 Jul-11 Jun-11 Jul-11 Sep-03 Dec-08 Jul-11 Jul-11 Jul-11 Jul-11 Jul-11 Jul-11 May-11 Jan-88 May-11 Jul-11 Jul-11 Dec-08 Jul-11 Jun-09 Jul-11 Jun-11 Apr-11 Jun-11 Jul-11 Jan-88

net sand



wrist pin bearings may need repair

comments

formation top TVDSS

perf Pot'l 2644-2664 Pot'l 2627-2647 Pot'l 2642-TD 2658 Pot'l 2679-2698 Pot'l 2690-2728 Pot'l 2690-2728 Pot'l 2616-2634 NDE Pot'l 2606-2654 Pot'l 2628-2648 Pot'l 2660-2675 Pot'l 2682-2700 Pot'l 2700-2722 Pot'l 2724-2752 Pot'l 2778-2794 NDE NDE Pot'l 2670-2688 Pot'l 2684-2704 Pot'l 2712-2733 Fish @ 2758 Pot'l 2773-2794 Pot'l 2795-2814 2608-2621 NDE 2623-2660 Pot'l 2648-2678 Pot'l 2602-2674 ?? Pot'l 2690-2710 Pot'l 2830-2840 NDE? Pot'l 2750-2772 2782-2789 2606-2611

cum oil - Bbl 2734-2738 2618-2700

cum gas - mcf

cum water - Bbl

firs t prod

las t prod

net sand

FB

comments

formation top TVDSS

perf

cum oil - Bbl

cum gas - mcfcum water - Bbl

firs t prod

las t prod

net sand


2012


2012

NMOCD restest by Ma y 31,

2012

WELL Name


UNIT 35


UNIT 36


UNIT 37


UNIT 38


UNIT 39


UNIT 40


UNIT 41


UNIT 42


UNIT 43


UNIT 44


UNIT 45


UNIT 46


UNIT 47


UNIT 48


UNIT 49


UNIT 50


UNIT 51


UNIT 52


UNIT 53


UNIT 54


UNIT 55


UNIT 56


UNIT 57


UNIT 58


UNIT 59


UNIT 60


UNIT 61


UNIT 62


UNIT 63


UNIT 64


UNIT 65


UNIT 66


67


UNIT 68

STATUS InjectorTxA ProducerTxA Pumping InjectorPxA ProducerShut-in Flowing Active Injection Well Active Dry hole Pumping Active Pumping Flowing Pumping InjectorShut-in TxA (no pump jack) Injection Well Active Injector Injection Well Active Shut-in Pumping Flowing Active Shut-in Injection Well Active Pumping Active Pumping Flowing

gas pressure on annulus;

tubing open to

atmosphere.

old pump jack, no motor,

with rods in well

active producer, annulus

open to atmosphere

PxA; pole with info for #38;

not listed in DI, though

parted rods per Anderson,

after previ ous workover; l at

l ong per BJ must have a typo;

s tuck with or igi nal data in

table gas pressure on annulus

no pump jack, rods in hole,

annulus and tubing open

to atmosphere no pump jack

lat long estimated from MS

map; Bruce searched and

could not find; last

injection 2009, no plugging

permit

TxA, lat long estimated

from paper map; last

production 1992

recently repaired pump

jack and returned to

production

horse head, rods, stuffing

box damaged

confirmed prod; need

production test and water

cut

#50 will take water and

maintain surface pressure

No pump jack. Tbg string is

capped off. Casing string

will flow pure oil for 2

seconds then die.

lat long estimated from

paper map, pad confirmed

in Google Earth, last

injection 2009

PxA; pole on ground; lat

long adj per google earth

Previous producer (pad);

check lat long; BJ lat long is

off; lat long taken from

Google Earth using pad

location in Drill ing Info

slight pressure on tubing,

annulus on vacuum,

located next to PxA #4 (per

BJ…but #4 is not on our

map)

recently replaced stuffing

box

motor used to trip on

overload; confirm status

pressure on annulus with

water at surface; no

pressure on tubing water to surface in annulus



map, pad confirmed in

Google Earth, last prod

1994, no plugging permit

injection tubing open to

atmosphere; not

connected at Inj manifold

pump jack has major gear

box damage

pump unit needs to be

reset no pressure on annulus

repairing electrical surge

protector, ordered pitman arm

bearings; good well


vacuum

SCHEMATIC

NM Lot

API 30-005-60026 30-005-60329 30-005-60973 30-005-60533 30-005-60657 30-005-60696 30-005-60768 30-005-60802 30-005-60829 30-005-60717 30-005-00342 30-005-60291 30-005-60010 30-005-60697 30-005-60767 30-005-60796 30-005-60810 30-005-60961 30-005-10140 30-005-00349 30-005-60297 30-005-60028 30-005-61135 30-005-61031 30-005-60807 30-005-60824 30-005-60920 30-005-60962 30-005-62563 30-005-62069 30-005-60293 30-005-60468 30-005-61096 30-005-61007

Citgo StatE A#3 Citgo State #2 Citgo State #6 Citgo State #5 Citgo State I#3 O'Brien I#6 O'Brien J#2 O'Brien J#5 O'Brien N#1 O'Brien F#5 Citgo A State #2 Citgo A State #1 Citgo State #3 O'Brien I#7 O'Brien I#8 O'BrienJ #4 O'Brien J #6 O'Brien N #2-Y O'Brien B #2 O'Brien C #2 O'Brien C #6 O'Brien C #5 O'Brien E #7 O'Brien L #12 O'Brien L #1 O'Brien L #2 O'Brien L #3 O'Brien L #6 Pelto ?? TO BE DRILLED O'Brien E #9 O'Brien C #7 O'Brien E #1 O'Brien E #6 O'Brien L #10

GR elevation / KB elevatiom 3965 / 3966 3942 / 3950 3947/3952 3956 '/ 3962 3685 / 3991 4000 / 4010 3990 / 3997 3950 3846 3980 3936 3979 3984 4002 4009 3984 3951 3940 3940 3966 3965 3995

Total Depth 2,615 2,645 2,750 2730 (PBTD 2719) 2,870 2,903 2,930 2,950 3,000 2,800 2,630 2,695 6,370 2,901 2,900 2,950 2,950 7,346 7,350 2,770 9,800 2,867 2,950 2,960 3,100 2,680 0 2,575 2,740 2,810

Drill Year

Location S:36, T:8S, R:28E S:36, T:8S, R:28E S:36, T:8S, R:28E S:31, T:8S, R:29E S:31, T:8S, R:29E S:31, T:8S, R:29E S:31, T:8S, R:29E S:32, T:8S, R:29E S:36, T:8S, R:28E S:36, T:8S, R:28E S:36, T:8S, R:28E S:31, T:8S, R:29E S:31, T:8S, R:29E S:31, T:8S, R:29E S:31, T:8S, R:29E S:32, T:8S, R:29E S:1, T:9S, R:28E S:1, T:9S, R:28E S:1, T:9S, R:28E S:1, T:9S, R:28E S:6, T:9S, R:29E S:6, T:9S, R:29E S:6, T:9S, R:29E S:6, T:9S, R:29E S:5, T:9S, R:29E S:1, T:9S, R:28E S:1, T:9S, R:28E S:1, T:9S, R:28E S:1, T:9S, R:28E S:6, T:9S, R:29E RESERVOIR

formation top TVDSS

perf 2563-2603 2586-2638 2603-2634.5 2600-2650 2656-2702.5 2697-2639 2717-2756 2753-2783 2806-2832 2664-2698 2714-2731 2737-2776 2783-2811 2665-2690 2703-2732 2734-2763 2755-2795 2780-2823 2675-2707

cum oil - Bbl 89,927 44,087 32,064 37,483 2,146 201 60 75,816 16,848 32,536 2,537 25,651 83,116 0 49,466 15,423 37,977 0 28,912 16,419 0 0 3,914 16,406 1,435 24,775

cum gas - mcf 213,291 40,464 23,513 0 0 0 0 201,612 24,086 8,330 0 37 65,024 0 40,968 38,413 27,743 0 4,244 0 0 0 6,080 33 0 1,855

cum water - Bbl 33,801 191,451 280,415 728,912 327,535 188,866 328,014 37,652 384,106 130,518 255,904 172,210 702,059 545,524 65,343 283,762 430,617 42,696 208,633 52,939 197,362 202,629 875,139 468,953 19,220 219,168 274,171 43,626 150,090 446,396

firs t prod Sep-67 May-75 Sep-81 Jan-93 Jan-01 Jun-93 Apr-96 Jan-01 Jan-70 Jan-75 Dec-77 Jan-01 Jan-93 Jan-01 Jul-99 Jan-01 Dec-50 May-74 Sep-67 May-01 Jan-93 Jan-01 Jan-93 Jan-01 Feb-01 Feb-84 Jan-93 Feb-03 Jan-93 Jan-01

las t prod Jun-87 May-11 Jul-11 Jun-11 Jul-11 Jun-11 Dec-00 Dec-08 Jul-11 Jul-11 May-11 Jun-11 Jul-11 Jul-11 Jul-11 Dec-08 Jul-11 Jul-11 Jul-11 Jul-11 Jul-11 Jul-11 May-11 Jul-11 Dec-08 May-11 May-11 Jun-11 Jul-11 Jul-11

net sand

confirmed prod; need prod test; bucket test was not

successful (too much

pressure)

FB

comments

formation top TVDSS

perf NDE 2671.5-2687 2681-2695 Pot'l 2724-2752 xxxx-xxxx 2785-2795 xxxx-xxxx Pot'l 2606-2619 XXXX-XXXX???? Pot'L 2756-2763 2813-2834 NDE XXXX-XXXX Pot'l 2608-2660 Pot'l 2690-TD 2729-2743 2767-2777 2800-2824 Pot'l 2845-2880 Pot'l 2688-2708 2736-2758

cum oil - Bbl

cum gas - mcf

cum water - Bbl

firs t prod

las t prod

net sand

FB

comments Deeper

formation top TVDSS

perf

cum oil - Bbl

cum gas - mcf

cum water - Bbl

firs t prod

las t prod

net sand

FB

comments


2012


2012


2012

WELL Name


UNIT 69


UNIT 70


UNIT 71


UNIT 72


UNIT 73


74


75


76


77


UNIT 78


UNIT 79


UNIT 80


UNIT 81


UNIT 82


UNIT 83


UNIT 84


UNIT 85


UNIT 86


UNIT 87


UNIT 88


UNIT 89


UNIT 90


UNIT 91


UNIT 92


UNIT 93


UNIT 94


UNIT 95


UNIT 96


UNIT 97


UNIT 98


UNIT 99


UNIT 100


101 WELL NUMBER

STATUS Pumping Flowing Active Injection Well Shut-in Injection Well Shut-in Flowing Pumping Pumping Active Injector Active Injection Well Shut-in Flowing Active Active Pumping Pumping Active Active Active Active STATUS

S/I Dec 2011, back on l ine


out, needs repair; ordered

bearings


vacuum

pump does not move fluid;

unit has pump off

controller that doesn't

function PxA; PxA;

shut-in injector; note: a

PxA pole for #74 is laying

on site; maybe had plans

for PxA and never

implemented?



map; pad confirmed in

Google Earth, last

production in 2000. no pressure on tubing

no pump jack; tubing open

to atmosphere no pressure on tubing pump does not move fluid pump does not move fluid active per BJ and Anderson PxA PxA PxA

pump jack out of

alignment, no pressure on

tubing, annulus open to

atmosphere water to surface in annulus pump jack removed

no pressure on tubing nor

annulus pump jack removed






plugged

gas pressure on tubing and

annulus, blows down

quickly normally active well PxA

won't pump fluid to

surface; good pump jack;

water to surface on tubing;

closed at inj manifold PxA date 10/19/1999


estimated from MS Map;




plugged PxA

tubing and annulus open

to atmosphere, no

pressure; no motor


pressure in annulus with

oil/water at surface;

closed at inj manifold;

review history; newer pump jack, no motor

SCHEMATIC SCHEMATIC

NM Lot NM Lot

API 30-005-60984 30-005-60885 30-005-62212 30-005-60886 30-005-60983 30-005-60248 30-005-60469 30-005-60809 30-005-61032 30-005-60995 30-005-60982 30-005-62213 30-005-60993 30-005-60994 30-005-62564 30-005-61363 30-005-60659 30-005-60794 30-005-61030 30-005-61006 30-005-61022 30-005-61033 30-005-60790 30-005-61095 30-005-61603 30-005-61106 30-005-61107 30-005-61076 30-005-61110 30-005-61362 30-005-61261 30-005-61105 30-005-61452 API

O'Brien L#8 O'Brien L#4 O'Brien L#15 O'Brien L#5 O'Brien L#7 O'Brien C#3 O'Brien E#2 O'Brien E#5 O'Brien L#13 O'Brien L#9 O'Brien FF#1 O'Brien L#16 O'Brien FF#2 O'Brien FF#3 Drilled? O'Brien E#8 O'Brien E#3 O'Brien E#4 O'Brien L#11 O'Brien FF#4 O'Brien FF#5 O'Brien FF#6 O'Brien D#2 O'Brien D#3 Moonshine 7#12 Moonshine 7 #5 Moonshine 7 #6 O'Brien GG #1 O'Brien GG #2 O'Brien D #5 O'Brien D #4 Moonshine 7 #4 Moonshine 7 #10

GR elevation 3996 3951 3976 3981 3981 3870 3962 3945 3943 3910 KB elevation

Total Depth 2,850 2,850 2,900 7,318 2,730 2,820 2,825 2,850 2,925 2,880 2,800 2,774 2,800 2,880 2,810 2,740 0 2,840 0 2,780 2,780 Total Depth


Location S:6, T:9S, R:29E S:6, T:9S, R:29E S:6, T:9S, R:29E S:1, T:9S, R:28E S:1, T:9S, R:28E S:1, T:9S, R:28E S:6, T:9S, R:29E S:6, T:9S, R:29E S:6, T:9S, R:29E S:6, T:9S, R:29E S:6, T:9S, R:29E S:1, T:9S, R:28E S:1, T:9S, R:28E S:6, T:9S, R:29E S:6, T:9S, R:29E S:6, T:9S, R:29E S:12, T:9S, R:28E S:12, T:9S, R:28E S:7, T:9S, R:29E S:7, T:9S, R:29E S:12, T:9S, R:28E S:7, T:9S, R:29E S:7, T:9S, R:29E Location RESERVOIR


perf 2689-2627 2715-2749 2725-2767 2729-2756 2768-2822 2585-2611 ????-???? 2617-2256 2648-2684 2683-2712 2696-2736 2715-2757 2712-2753 2757-2799 2850-2894 2579-2607 2591-2624 2612-2647 2655-2679 2687-2721 2701-2737 2746-2792 2590-2629 2619-2644 2670-2689 2683-2717 2703-2740 2730-2775 2816-2852 2589-2610 ??2593-2614?? 2606-2645 2645-2657 perf

cum oil - Bbl 38,193 36,967 0 504 0 238 39,415 25,134 10,297 0 5,220 14,637 0 38,376 95,124 38,151 14,597 0 31,249 cum oil - Bbl

cum gas - mcf 7,061 0 0 0 0 0 1,778 19 0 0 8,592 0 0 467 23,592 9,276 0 0 8,142 cum gas - mcf

cum water - Bbl 253,259 811,742 1,450,920 43,164 48,655 45,187 1,384 674,542 800,883 1,300,146 768,906 351,539 32,963 4,684 572,338 397,082 66,607 166,780 132,747 99,022 293,756 172,355 249,094 cum water - Bbl

firs t prod Jan-93 Jan-01 Jan-93 Jul-03 Apr-93 May-01 May-95 Feb-01 Jan-93 Jan-93 Jan-01 Jan-93 Aug-02 Sep-95 Jan-01 Jan-93 May-01 Jan-93 Nov-81 Oct-81 Jan-93 Aug-01 Apr-82 first prod

las t prod Jul-11 Jul-11 Dec-10 Dec-08 Dec-00 Oct-10 Jul-11 Jul-11 Feb-11 Jan-11 Jul-11 May-11 Jul-11 Jul-11 Jul-11 Jun-11 Dec-08 Apr-11 May-11 Jul-11 May-11 Jul-11 May-11 last prod

net sand

S/I Dec 2011, back on line


out, needs repair net sand

FB FB

comments comments


perf 2761-2779 2773-2788 2789-2714 Pot'l 2794-2813 2845-2862 Pot'l 2630-2758 ????-???? Pot'l 2684-2700 2724-2741 2744-2758 2757-2775 2782-2807 2776-2793 Pot'l 2831-2845 Pot'l 2915-2933 Pot'l 2641-2660 ??? Hole Deep enough Pot'l 2679-2698 Pot'l 2710-2734 2740-2760 2764-2778 2804-2825 Pot'l 2648-2674 Pot'l 2664-2668 2700-2730 Lck 2720-2770 in P2 Pot'l 2756-2760 2796-2820++ NDE? 2878-2895 ??? Pot'l 2650-2665 Pot'l 2665-2708 Pot'l 2678-2702 perf

cum oil - Bbl 2897-2924 2757-2775 cum oil - Bbl





net sand net sandFB FB

comments comments Deeper

formation top TVDSS

perf P3: 2706-2714+ formation top TVDSS

cum oil - Bbl perf

cum gas - mcf Pot'l P3:2712-2725 cum oil - Bbl

cum water - Bbl cum gas - mcf

firs t prod cum water - Bbl

las t prod first prod

net sand last prod

FB net sand

comments FB


2012


2012

WELL Name


UNIT 102


UNIT 103


UNIT 104


UNIT 105


UNIT 106


UNIT 107


UNIT 108


UNIT 109


UNIT 110


UNIT 111


UNIT 112


UNIT 113


UNIT 114


UNIT 115


UNIT 116


UNIT 117


UNIT 118


UNIT 119


UNIT 120


UNIT 121


UNIT 122


UNIT 123


UNIT 200


UNIT 201


UNIT 202


UNIT 203


UNIT 302


UNIT 311


UNIT 316


UNIT 319


UNIT 321


UNIT 326


329


UNIT 331 TWIN LAKES SAN ANDRES UNIT 333 WELL NUMBER

STATUS Shut-in Active Shut-in Active Injection Well Active Injection Well Active Injection Well Shut-in Injection Well Shut-in Injection Well Injection Well Shut-in Pumping Pumping Pumping Pumping Shut-in Pumping Pumping Pumping Active Pumping Pumping ProducerTxA (no pump jack) STATUS

newer pump jack, no

motor


presssure on annulus;

closed at inj manifold



confirmed pad in Google

Earth, applied for plugging

permit

no pressure on tubing or

annulus but water to

surface; closed at inj

manifold


motor

tubing on vacuum, annulus

with pressure and slight oil

to surface (note, this is an

injector)


motor

oil seeping at the wellhead

- INJECTOR! ; lat long from

Google Earth using Drilling

Info pad location.

pump jack with no motor,

no head. Rod sticking out

of wellhead. closed at inj manifold no pump jack water to surface in annulus PxA

no pump jack, tubing open

to atmosphere PxA





plugging permit

tubing string on vacuum;

not connected at inj

manifold closed at inj manifold





plugging permit

tubing open to

atmosphere PxA confirmed prod confirmed prod no pump jack and no pad confirmed prod confirmed prod no pump jack, no flowine confirmed prod confirmed prod

up and running as of Jan 1,

2012; replaced burnt

motor

electric power

disconnected confirmed prod confirmed prod

prod reported in June, July 2011; no pump

jack

RESERVOIR

SCHEMATIC SCHEMATIC

NM Lot NM Lot

API 30-005-60844 30-005-61075 30-005-61116 30-005-62068 30-005-61332 30-005-61104 30-005-61334 30-005-61772 30-005-61556 30-005-61453 30-005-61333 30-005-61604 30-005-61622 30-005-61655 30-005-61735 30-005-61454 30-005-61736 30-005-61623 30-005-61624 30-005-62819 30-005-62818 30-005-62845 30-005-63138 30-005-63139 30-005-63147 30-005-63140 30-005-63191 30-005-63194 30-005-63185 30-005-63187 30-005-63188 30-005-63189 30-005-63190 30-005-63192 30-005-63193 API

Moonshine 7 #1 Moonshine 7 #2 O'Brien GG #3 O'Brien D #6 Moonshine 7 #7 Moonshine 7 #3 Moonshine 7 #9 O'Brien DB #3 O'Brien DB #1 Moonshine 7 #11 Moonshine 7 #8 Moonshine 7 #13 Moonshine 7 #14 O'Brien DB #2 Moonshine 18 #4 Moonshine 18 #1 Moonshine 18 #5 Moonshine 18 #2 Moonshine 18 #3 EDC #121 TLSAU ??? EDC #123 TLSAU Marbob #200 TLSAU Marbob #201 TLSAU Marbob #202 TLSAU Marbob #203 TLSAU Hanagan #302 TLSAU

GR elevation 3915 3905 3929 3928 3931 3928 3967 3974 3958 3951 3585 / 3591 3922 / 3929 3940 / 3947 3953 / 3927 3971 / 3977 4003 / 4009 3981 / 3987 4003 / 4009 3985 / 3991 3965 / 3971 3938 KB elevation

Total Depth 2,780 2,726 2,700 2,840 2,788 2,747 2,780 2,800 3,793 2,800 2,805 2,900 3,100 3,100 2,800 2,750 2,862 2,700 2,767 2,903 2,816 2,855 2,855 2,830 2,830 Total Depth


Location S:7, T:9S, R:29E S:7, T:9S, R:29E S:12, T:9S, R:28E S:7, T:9S, R:29E S:7, T:9S, R:29E S:7, T:9S, R:29E S:12, T:9S, R:28E S:12, T:9S, R:28E S:7, T:9S, R:29E S:7, T:9S, R:29E S:7, T:9S, R:29E S:12, T:9S, R:28E S:18, T:9S, R:29E S:18, T:9S, R:29E S:5, T:9S, R:29E S:31, T:8S, R:29E S:12, T:9S, R:28E S:36, T:8S, R:28E S:6, T:9S, R:29E S:25, T:8S, R:28E S:36, T:8S, R:28E S:31, T:8S, R:29E S:31, T:8S, R:29E S:31, T:8S, R:29E S:6, T:9S, R:29E S:6, T:9S, R:29E S:6, T:9S, R:29E Location


perf 2653-2672 2688-2706 2726-2773 ????-???? 2599-2639(2608-2646Log) 2667-2696 2683-2717 2632-2669 2630-2666 2640-2686 2675-2726 2724-2740 2739-2772 2675-2723 2698-2738 2745-2759 2732-2786 2837-2892 2642-2677 2616-2642 2626-2649 2545-2587 2670-2707 2572-2616 2681-2708 2638-2684 2670-2706 2712-2756 2694-2739 Lck 2697-2726 Lck 2708-2742 perf San Andres P1

cum oil - Bbl 37,966 0 0 3,851 0 17,371 0 5,437 0 59,535 0 114 0 0 71 30,705 30,825 18,196 45,645 319 5,678 6,186 7,386 3,697 12,589 10,960 1,711 cum oil - Bbl

cum gas - mcf 15,802 0 0 0 0 1,717 0 0 0 18,166 0 0 0 0 0 50 84 0 39 0 15 0 0 0 42 0 0 cum gas - mcf

cum water - Bbl 124,889 86,276 138,554 78,321 62,524 80,670 130,361 206,430 126,208 294,033 94,417 20,859 46,647 108,296 51,363 706,679 903,212 603,313 1,994,107 7,924 116,229 111,944 131,667 118,666 223,440 140,204 44,083 cum water - Bbl

firs t prod Mar-98 Aug-01 Feb-01 May-95 Aug-01 Mar-98 Feb-01 Jan-93 Aug-01 Sep-93 Feb-01 Mar-98 Feb-01 Feb-01 May-91 Jan-93 Sep-97 Sep-97 Oct-97 May-99 Feb-99 Jan-99 Jan-99 Jan-99 Jan-99 Jan-99 Apr-99 first prod

las t prod May-11 Jul-11 Jul-11 Apr-11 Jul-11 May-11 Dec-08 May-11 Jul-11 Jul-11 Jul-11 Jul-11 Dec-08 Nov-09 May-98 Jul-11 Jul-11 Jul-11 Jul-11 Apr-08 Jul-11 Jul-11 Jul-11 Jun-11 Jul-11 Jul-11 Jul-11 last prod

net sand net sand

FB FB

comments confirmed prod confirmed prod confirmed prod confirmed prod comments

formation top TVDSS NDE NDE 2797-2817 Lck 2794-2800 rathole? NDE Pot'l 2662-2788 Pot'l 2789-2826 2909-2913 2706-2711 2800-2824 2680-2684 Pot'l 2676-2690 2615-2626 2733-2740 Pot'l 2640-2658 2734-2772 Lck Pot'l 2705-2724 Pot'l 2736-2774 2777-2815 Pot'l 2758-2778 Lck 2746-2775 Lck Pot'l 2762-2782 formation top TVDSS

perf 2695-2726 Lck Channel to 2740 2800-2823 Pot'l 2652-2674 No Pay/ NDE ?(2670-92Log) Pot'l 2712-2735 No Pay/NDE Lck Pot'l 2685-2710 Pot'l 2682-2700 No Pay Rathole? Rathole? perf San Andres P2

cum oil - Bbl cum oil - Bbl





net sand net sand

FB FB

comments comments

formation top TVDSS

perf formation top TVDSS

cum oil - Bbl 2535-2549 2518-2532 2496-2512 2493-2500 2500-2514 perf Shallower

PDNP PDNP

SI GAS SI OIL

Active Injector

San Andres - P1

ABANDONED ?

Non-Canyon

San Andres - P1

San Andres - P2

Deeper

SI GAS PDNPPRODUCING OIL

Twin Lakes San Andreas Unit

WELLBORE UTILIZATION PRODUCING GAS

PDP PDPABANDONED COMPLETION

PDNP

ABANDONED COMPLETION

PLUGGED BACK orSI OIL

production reported in

July/July 2011; not surveyed

San Andres - P2

San Andres - P1

San Andres - P2

ORGANIZATION - WELLBORE UTILITY CHART

39


UNIT 26


UNIT 27

Pumping Active Injector






inactive

30-005-60031 30-005-60521

Citgo State #1 Citgo State #4

3957 3942 / 3948

2,614 2,694

S:36, T:8S, R:28E S:36, T:8S, R:28E

2564-2608 2581-2620

118,340 74,300

72,681 64,352

223,419 270,487

Oct-67 Jan-08

Jun-09 Jul-11



wrist pin bearings may need

repair

2623-2660 Pot'l 2648-2678

Confidential

Confidential

Confidential

ORGANIZATION - WELLBORE SCHEMATIC

40

It is necessary for operators to keep a detailed and up-to-date inventory of each individual wellbore schematic. This applies to newly drilled wells as well as older wells that may have been acquired.

The more detailed and available these schematics are, the easier it is to address potential operational issues.

� INEXS provides full analysis of field operations including wellbore utilization evaluation

� INEXS provides direct field operations supervision including accounting

� Pricing based on $/wellbore, $/BOEPD, and shared upside success

41

FIELD OPERATIONS SUMMARY

FIELD EQUIPMENT AUDIT AND INVENTORY

It is equally important to conduct a complete and thorough inventory of physical equipment in the field, and to complete a detailed written field inventory report so that the producing company can optimize the artificial lift operations, to right size the artificial lift systems, and to monitor and track spills, failed equipment, and potential for future problems

FIELD EQUIPMENT AND INVENTORY

43

Clean Looking site, note top of foremost tank


44

note oil spray:


45

Far right tank appears to have leaked/sprayed oil


46

Remains of another failed tank. Operations improvements indicated


47

Equipment shown here is in service. Maintenance improvements indicated


48

Clean looking site, equipment in good working order


49

Clean looking site, equipment in good working order


50

Wellhead without pumpjack


51

Pumpjack without wellhead or rods.


52

Pipe storage facility?


53

Potential leaking issue. Note discoloration of ground and leaking of wellhead.


54

Field road washed out. Note exposed supply piping, risk of leak.


55

New TubingUsed TubingUnusable

tubing

Exposed, uncapped electrical wiring in operational service box.


56

Note discoloration of ground around push rod. Leak?


57

Cleanout of 3-stage separator.

Base Info Manufacturer Type size/rating Misc InfoCOPAS Cond General Comments Descriptors

Access Road Caliche CNon-COPAS - General Condition of Road and Access Problems Noted

Well Site Pad Caliche 80x60Useful Pad Size (ft x ft)

CGeneral Size of Well PadC=Caliche, N=Native Soil, C/N=Caliche/Native Soil

DeadmanAnchors Yes 3# of visible Anchors

DAll anchors are Copas 'D' until properly tested

Wellhead - Prod String

Flange N/A B F=flanged, T=threaded, I=injector

Wellhead - Conductor String

F=flanged, T=threaded, I=injector

Water Injection Head: F=flanged, T=threaded, I=injector

Tubing: Yes Steel 2-7/8" B Surface Tubing Data Only

Pump System Type Beam Unit Lufkin Conventional LM 228D-144-120 B workingB=beam unit, G=Gaslift, M=Monyo, P=Plungerlift, O=otherC=conventional=Mark, AB=Air Balance

Pump-off-controller No

Prime Mover Electric Motor No Tag Info B Tag missing E=electric motor, G=gas engine

Polish Rod Liner Yes 1-1/2" B P=polish rod only, L=with liner

Stuffing Box Yes 2-7/8" B

Downhole Pump Data required from well files

Rod Rotator

Flowline - Production HDPE HDPE 3" BG=GRP, I=IPC, P=HDPE, S=Steel, O=otherWater Injector

Water Injection Line N/A

Water Injection Hose N/A

Metering

Chemical System Yes

Chemical Pump: Electric LMI .21 GPH A

Chemical Tank: Yes 200 GAL A

Chemical Containment:

Yes 4' x 6' A

Tankage No

Vessel(s)

Solar System: No

Misc Equip - 1 Yes ESP Controller B

Misc Equip - 2 Yes 6 Misc Drums D

Manufacturer size/rating Misc Info

COPAS

Cond General Comments

Access Road C

Well Site Pad 120x100Useful Pad

Size (ft x ft)C

DeadmanAnchors 4# of visible

AnchorsD

Wellhead - Prod String N/Aprod head not

visableCondition N/A

Wellhead - Conductor

String

Water Injection Head:

Tubing:

Pump System Type American D320-NA-120 B

Pump-off-controller

Prime Mover Worldwide Elec HP 1125 RMP B

Polish Rod Liner 1-1/2" B Polish Rod bent

Stuffing Box 2-7/8" B

Electric Motor 25

Yes

Yes

N/A

Beam Unit Conventional

No

Threaded

Not Visible

N/A

Caliche/Native Soil

Caliche/Native Soil

Yes

Base Info Type

INDIVIDUAL WELLSITE INVENTORY

58

� INEXS provides full analysis of field equipment and audit of inventory

� INEXS generates full written reports and incorporates the audit into a field optimization program

SUMMARY OF INEXS EXPERTISE

� Asset Valuations

� Independent Review of Third Party Engineering Reserve Reports

� Review of Technical Expertise and Management of Portfolio Companies

� Full Contract Field Operations

� Full Field Equipment Audit

INEXS

1980 Post Oak Blvd.

Suite 2050

Houston, Texas 77056

713-993-0676

www.inexs.com

[email protected]

[email protected]

[email protected]

59

FIELD EQUIPMENT AUDIT

Documents

CHALLENGES TO ACCURATE OIL & GAS ASSET VALUATIONS …