WELLS RANCH SEC. 25: OBSERVATIONS

FROM A UNDERGROUND IN-SITU

LABORATORY

January 21, 2015

Dave Koskella

Bob Parney

David brock

Forward-looking Statements and Other Matters Slide 2

This presentation contains certain “forward-looking statements” within the meaning of the federal securities law. Words such as “anticipates,”

“believes,” “expects,” “intends,” “will,” “should,” “may,” and similar expressions may be used to identify forward-looking statements. Forward-

looking statements are not statements of historical fact and reflect Noble Energy’s current views about future events. They include estimates of

oil and natural gas reserves and resources, estimates of future production, assumptions regarding future oil and natural gas pricing, planned

drilling activity, future results of operations, projected cash flow and liquidity, business strategy and other plans and objectives for future

operations. No assurances can be given that the forward-looking statements contained in this presentation will occur as projected, and actual

results may differ materially from those projected. Forward-looking statements are based on current expectations, estimates and assumptions

that involve a number of risks and uncertainties that could cause actual results to differ materially from those projected. These risks include, without limitation, the volatility in commodity prices for crude oil and natural gas, the presence or recoverability of estimated reserves, the ability

to replace reserves, environmental risks, drilling and operating risks, exploration and development risks, competition, government regulation or

other actions, the ability of management to execute its plans to meet its goals and other risks inherent in Noble Energy’s business that are

discussed in its most recent Form 10-K and in other reports on file with the Securities and Exchange Commission. These reports are also

available from Noble Energy’s offices or website, http://www.nobleenergyinc.com. Forward-looking statements are based on the estimates and

opinions of management at the time the statements are made. Noble Energy does not assume any obligation to update forward-looking

statements should circumstances or management's estimates or opinions change.

This presentation also contains certain historical and forward-looking non-GAAP measures of financial performance that management believes

are good tools for internal use and the investment community in evaluating Noble Energy’s overall financial performance. These non-GAAP

measures are broadly used to value and compare companies in the crude oil and natural gas industry. Please also see Noble Energy’s website

at http://www.nobleenergyinc.com under “Investors” for reconciliations of the differences between any historical non-GAAP measures used in

this presentation and the most directly comparable GAAP financial measures. The GAAP measures most comparable to the forward-looking

non-GAAP financial measures are not accessible on a forward-looking basis and reconciling information is not available without unreasonable

effort.

The Securities and Exchange Commission requires oil and gas companies, in their filings with the SEC, to disclose proved reserves that a

company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing

economic and operating conditions. The SEC permits the optional disclosure of probable and possible reserves, however, we have not

disclosed our probable and possible reserves in our filings with the SEC. We use certain terms in this presentation, such as “discovered

unbooked resources”, “resources”, “risked resources”, “recoverable resources”, “unrisked resources”, “unrisked exploration prospectivity” and

“estimated ultimate recovery” (EUR). These estimates are by their nature more speculative than estimates of proved, probable and possible

reserves and accordingly are subject to substantially greater risk of being actually realized. The SEC guidelines strictly prohibit us from

including these estimates in filings with the SEC. Investors are urged to consider closely the disclosures and risk factors in our most recent

Form 10-K and in other reports on file with the SEC, available from Noble Energy’s offices or website, http://www.nobleenergyinc.com.

Life Cycle of a Resource Play

3

Demonstrate Economic Productivity

Minimize Cost Structure

Optimize Well Spacing

Demonstrate Productivity

Economically Develop Reserves

Current State

Confirm Resource/OOIP

Greater Wattenberg Area

4

WY

CO

NE

B Chalk

Smo

key

Hill

Mem

ber

N

iob

rara

Fo

rmat

ion

Ft Hays Ls

Carlile

Pierre Shale

Sharon Springs

A Chalk

C Chalk

A Marl

B Marl

C Marl

D Chalk

Codell Ss

Tur.

C

on

iaci

an

San

ton

ian

C

am.

27

5’ -

35

0’

Niobrara Stratigraphy

5

Fort Hayes Limestone

C Chalk

C Marl

D Chalk

Cemex Limestone Quarry, Lyons, CO

15

0’

Niobrara Characteristics

6

OOIP 70 MMBOE/Section

TVD 6,700’

H 300’

Phi 9%

K 0.81 uD

P* 0.49 psi/ft

API 40

GOR 5,000 scf/bbl

Sh min 0.75 psi/ft

Sh max > 0.75 psi/ft

Frac Grad 0.85 psi/ft

Sv 1.06 psi/ft

Permeability

(Micro Darcy)

P10 1.48

Pmean 0.81

P90 0.32

In-Situ Underground Laboratory Technologies Employed

7

Multi-Array Down Hole Micro

Seismic (Six Wells)

Ten Down Hole Pressure Gauges

Ten Down Hole Temperature

Gauges

Two wells with Fiber Optic:

DTS Stimulation

DTS Production Logging

DAS

RA Proppant Tracers

Three Wells Traced

Five Wells Logged

Liquid Tracers (Nine Wells):

Water Based

Oil based

FMI’s (Nine Wells)

Core (Two Wells)

Core Laboratory Testing

DFITS (Nine Wells)

VSP

Geochemistry

Core Extracts

Produced Oil

3-D Seismic

In-Situ Underground Laboratory

8

One Section (One Square Mile)

Vertical well

Vertical well:

microseismic monitor

Vertical well:

downhole pressure

Pressure gauge in

horizontal DTS well

Horizontal well

Horizontal DTS well

P

P

m P P P

P P

P

P P

P P

m

m

m

m

140’ 180’

480’

290’

430’ 270’

410’

320’

290’

170’

480’ 510’

1400’ microseismic

listening radius B Chalk

B Marl

C Chalk

DTS Well Construction

9

Laser source and detector

Fiber-optic

cable in

wellbore

formation

packers

Fiber-optic

cable

• Approximately 4000’ lateral:

20 stages, ~200’ per stage

• Open-hole, packer-isolation

• Ball-drop w/ sliding-sleeves

• Fiber optic cable fixed to

outside of casing

• Electric Pressure gauges at

toe and heel

Hybrid Design (Single Stage):

• SLW & XL Pad at 50 bpm

• 28 lb HPG at 50 bpm ramping to 4 ppg

• 140,000 gallons

• 200,000 lbs proppant

DTS During Completion

10

DTS During Completion: Fluid Movement and Warmback

11

2

3

4

Overall, both wells:

Heelward bias: 37% of stages

Toeward bias: 13% of stages

No bias: 50% of stages

DTS During Completion: Packer Leak/Bypass

12

7

8

9

6

Both Wells, By Stage:

Toe Leak/Bypass:

17 of 38 stages (45%)

Heel Leak/Bypass:

4 of 38 stages (11%)

By Packer:

19 of 37 packers (51%)

DTS During Completion: Multiple Packer Leaks/Bypass

13

14

15

16

13

DTS During Completion: Operations Diagnostic Example

14

Harmonic

Debris

Fracture Statistics from DTS

15

Two wells, 38 stages total

Fractures: 135 (avg 3.5 fracs/stage)

0%

20%

40%

60%

80%

100%

0

5

10

15

20

25

30

Cu

mu

lati

ve

Fre

qu

en

cy

Fre

qu

en

cy (

co

un

t)

Inter-Fracture Spacing (ft)

Fracture Spacing Histogram Feature # stages

(of 38)

% of

stages

“Dominant” Frac

(one frac >> others)

18 47%

“Significant” Frac

(long lasting DTS warmback)

12 32%

Frac at toe packer 6 16%

Frac at heel packer 15 39%

Fluid bias: toe 5 13%

Fluid bias: heel 14 37%

Packer Leak/Bypass: toe 17 45%

Packer Leak/Bypass: heel 4 11%

Leak/Bypass by Packer:

19 of 37 packers = 51%

Proppant Tracer Inter-Well Transport

16

0%

5%

10%

15%

20%

25%

0 10 20 30 40 50 60 70 80 90

RA

Tra

cer

Late

ral

Co

vera

ge (

%)

Angle from Horizontal (°)

Down Hole Pressure Monitoring in Vertical Wells

During Stimulation (178 Frac Stages)

17

Vertical

well

monitoring

distances:

140-510’

Pressure Response During Completion of One Well

18

0

1000

2000

3000

4000

5000

6000

7000

0:00 6:00 12:00 18:00 0:00 6:00 12:00 18:00 0:00 6:00 12:00

BH

P (

psi

)

0

3000

6000

9000

0:00 6:00 12:00 18:00 0:00 6:00 12:00 18:00 0:00 6:00 12:00

Tre

atin

g P

Time

0

1000

2000

3000

4000

5000

6000

7000

0:00 6:00 12:00 18:00 0:00 6:00 12:00 18:00 0:00 6:00 12:00

BH

P (

psi

)

Prock face ~6200 Pfrac ext ~5400

Shmin ~5000

Pres ~3300

Drainage Network Geometry

19

Lognormal Elliptical Analysis of Micro-Seismic Events

20

End on view of well bore

Lognormal Elliptical Analysis

21

Microseismic Overview

22

Microseismic &

Pressure Correlation?

23

2000

4000

6000

8000

10000

12000

14000

16000

18000

20000

1000

1500

2000

2500

3000

3500

4000

1/29/2012 9:36:00 1/29/2012 14:24:00

Tre

ati

ng

Pre

ssu

re (

psi)

BH

P (

psi)

Time

67-01HN HEEL

25-06DH

25-08DH

66-01HN TreatingPressure

• Microseismic events along path from frac stage #2 toward and around

vertical monitoring well

• Pressure responses observed in nearby observation wells not correlated

with microseismic events

Inter Well Behavior: Intergrating Pressure &

Microseismic?

24

- Micro seismic events along path from frac well toward

and around vertical monitoring well

- No pressure response observed in nearby vertical well

DTS Analysis for Production Logging: A History-Match

Process

25

Measure

d D

epth

Temperature

Form

atio

n

Te

mp

era

ture

DT

S (

We

ll)

Te

mp

era

ture

inflow

inflow

inflow

• DTS: Early-Time

(Formation)

• DTS: Analysis

Timepoint

• Surface Flow Rates

PLATO

• Energy, momentum, mass

balances

• Iterates on flow profile,

reservoir pressure

• Seeks best fit on

temperature

• Reservoir Properties

• Fluid Properties

Production Log

Oil Production (4 months into production)

26

• By stage oil production

• (Average stage would have 5% flow)

• Best stage: 6.9%

• Poorest stage: 1.4%

• Production profiles do not correlate

to FMI artifacts

• Pmean oil rate 32% better in Toe Stages

Heel

Stages

Oil Production through Producing Life

27

• By-stage oil production results

0%

2%

4%

6%

8%

10%

12%

1234567891011121314151617181920

Pe

rce

nt

of

We

ll To

tal

Stage

Oil, Prod+11mo

Oil, Prod+8mo

Oil, Prod+4mo

(toe) (heel)

Summary

28

Stage Perspective:

• Fracture Initiation: Average 3.5 fractures per 200 foot stage

• “Stress Shadowing”? Heelward fluid bias vs. toeward bias (37% vs.

13%)

Well Perspective:

• More instances of packer leaks/bypass in the heelward half of wells

(78% heel stages vs. 30% toe stages)

• DTS production logging shows all stages producing with no large

redistributions over time. Toeward stages 32% more productive than

heelward stages.

Summary (cont.)

29

Inter-Well Perspective:

• RA Proppant Tracer:

– Horizontally not observed, 0-15 degrees, 0% coverage

– Diagonally observed, 15-50 degrees, 8% coverage

– Vertically observed, 90 degrees, 20% coverage

• Pressure responses << Shmin observed up to 1,520’

• Pressure responses > Shmin rarely seen at distances of 140-510 feet,

7 events out of 178 frac stages

• Dynamic inter-well hydraulic connectivity, shrinking drainage radius

• Microseismic responses seen 1,400’ away

• Inferred drainage ellipse orientation:

– Microsiesmic (horizontal) vs. other data sets (vertical)?

• Pressure and microseismic event correlation is not obvious

• No consistent temperature response seen in offset DTS wells

• Much still to learn….

Acknowledgements

30

Noble Energy, Inc.

Pinnacle

Interpretive Software Products

Barree & Associates

Silixia