Niobrara OPCOM Meeting - Oil India13 Aug ‐ 13 Sep ‐ 13 Oct ‐ 13 Nov ‐ 13 Dec ‐ 13 Jan ‐...

December 20, 2013

Niobrara OPCOM Meeting

Permitting

Operations and Production Review

Well Performance

Downspacing

Development Plan Update

Lease Operating Expense Overview

Other Discussion

2

Niobrara OPCOMTable of Contents

3

Niobrara OPCOM Northeast Colorado Activity Map

2013‐2014 Focus

Optimize drilling & completion techniquesClarify regulatory processRationalize acreage position

Current Operated85 gross wells drilled70 gross wells frac’d15 gross wells in inventory

Planned 2014 Operated ActivityDrill 26 gross / 13 net wellsFrac 37 gross / 20 net wellsConsolidate acreage positionTest downspacing

4


2013‐2014 Focus




Whiting to CRZO

CRZO to Whiting

AMI 3

5


2013‐2014 Focus




Whiting to CRZO

CRZO to Whiting

AMI 3

Non‐op acreage

Drilling with 2 rigs (X‐17 & X‐19) Scheduled to temporarily drop 1 drilling rig as a result of increasingly difficult permitting environment for both drilling and completion; need to build backlog of drill‐ready locationsNear term drill schedule ‒ State 16 pad (3 wells)‒ Gaffney 2‐29‐8‐61‒ Bringelson Ranch 20 (7 wells)

Completed the drilling and completion of the first 60ac downspaced padsNon‐Operated AFE activity continues to be high as other operators are active in the playNon‐op wells coming on‐line Unfraced well inventory continues to be low Near term Frac schedule ‒ Konig 2‐31‐11‐59 (flowing back)‒ Speaker 27 pad (3 wells)‒ O’Hare 1‐5‐10‐57‒ Castor 36 pad (3 wells)

6

Niobrara OPCOMDrilling and Frac Activity

7

Permitting

Niobrara OPCOMPermitting

8

SummaryDelays in spacing approvals− Caused delays permitting new drills− COGCC has approved “new” spacing, but BLM is protesting

Delays in permitting P&A’s − Caused delays in frac schedule− P&A’s taking longer than anticipated

Plans ForwardPossible field‐wide spacing rules, but will take at years

East Pawnee spacing agreed by all operators− Slow because Noble and Whiting do not agree on spacing− Noble and Whiting have enough contiguous acreage to develop and testContinue to space wells with…− 640, 960, and 1,280 DSUs− 16 wells per section− 300’ internal wellbore setbacks− 300’ section line setbacks with no – BLM offsets and 600’ setbacks when BLM offsets

Niobrara OPCOMPermitting Impact

9

Operations and Production Review

Niobrara OPCOMOperations and Production Review

TD as of Dec 19, 2013

• 2 Rig RunningXtreme 17Xtreme 19

• Average Depth = 10,642’• Average Days = 13.5 • 2013 Average Days = 12.3

10

WEP 4-28X 17 First Well

Niobrara OPCOMDrilling Performance

• Max Depth = 13,202’• Minimum Days = 9• Total Wells = 82

11

Niobrara OPCOMRig Move ‐ Hours

12

Halliburton Cost2012 Avg = $83,3452013 Avg = $88,705

Liberty Cost2013 Avg = $78,705Overall 2013 Average = $85,684

Liberty has pumped outperformed HESHES has recently matched Liberty PricingNabors awarded single Frac ‐ unsuccessful

2013

Liberty Pumping

Halliburton

Niobrara OPCOMFrac Cost Per Stage

13

Staff in Place

‒ Superintendent: Lee Nash

‒ Foreman: Russ Wilcox

‒ Field Tech: Justin Bates (Added)

‒ Construction Foreman: Justin Daume (Added)

‒ 3 pumpers

Added a P&A rig to address offset wells that need to be P&A’s as a result of the DJBHO policy enacted by the COGCC

‒ Have P&A’d 4 out of 18 wells for the current schedule

Workovers are being prioritized based highest production impact for the JV

Continually seeking out improvements to the well design

‒ Testing new packerless downhole gas separator

‒ Duraseal coating treatment (ionic bonding)

‒ Electrification to fully utilize POC’s

Niobrara OPCOMOperational Performance Summary

0

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10,000

Dec‐10

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Jan‐14

bopd

& M

cf/d

Niobrara Total Production Plot Daily production based on flowback and tank gauge data

Gas Oil # wells online

14Note: Assumptions are estimates and subject to change. Daily production figures based on flowback and tank gauge data.

69 Wells

Niobrara OPCOMProduction Review

New Production High = 7,320 bopd

15

Niobrara OPCOMProduction Review (cont’d)

23.0%

25.2%41.5%

10.3%

2013 NIOBRARA DEFERRED PRODUCTION

SURFACE MECHANICAL

DOWNHOLE

SCHEDULED

WEATHER

Scheduled downtime includes:1. drilling rig2. jet pump install3. rod pump install4. electrification5. workover rig on pad

16

0

5

10

15

20

25

30

Jan‐13 Feb‐13 Mar‐13 Apr‐13 May‐13 Jun‐13 Jul‐13 Aug‐13 Sep‐13 Oct‐13 Nov‐13 Dec‐13

BBLS/D

AY / COMPE

LTED

WELL

2013 NIOBRARA MONTHLY DEFERRED PRODUCTION COMPOSITIONSURFACE MECHANICAL DOWNHOLE SCHEDULED WEATHER


17

Scheduled = The drilling rig returning to pad sites with producing wells to add a down space wells in 2013 was a significant source of deferred production. This factor is expected to be much lower in 2014 due to drilling primarily taking place on new pads

‒ Artificial lift installation delays caused by equipment shortages have been alleviated by adding additional equipment and procuring orders in advance for 2014 activity

Surface/Mechanical = Jet pump/Rod pump engine or equipment related deferred production should be reduced by the addition of a Field Tech to help the foreman troubleshoot and keep equipment in top performing condition

Downhole = Scale, corrosion, and other downhole contributors to deferred production are being addressed at each stage of the well life

‒ Fine tuning bactericide treatments using kill studies

‒ Chemical treatments utilizing ideal downhole BHA

Weather = Blizzards, floods, and freezing all had and effect on production. Although this is a smaller piece of the deferred production we have strategies now in place to mitigate the deferred production from weather

‒ Utilize commercial heaters

‒ Use temporary additional man power during anticipated severe weather events


18

Well Performance

Niobrara OPCOMWell Performance

19

11 operated wells brought on production since August OpCom:‒ Schneider (2 wells)‒ Speaker 2‐27‒ Nelson Ranches (3 wells)‒ Castor (2 wells)‒ Bob White (3 wells)

Continuing review of production data strengthens correlation between rock quality and performance

Underscores importance of high‐grading concept; updated plan should be ready early in Q1 2014

Whiting trade consistent with this approach

Beginning to get data from Noble and Whiting pilots

Niobrara OPCOMWell Performance

20


21

Niobrara OPCOMRecent Well Performance

22

Downspacing

Niobrara OPCOMDownspacing

23

Current

Planned Wells

Wells Per Section 4 8 8 11 16

Between Well Spacing 1,327 565 668 468 312

Section Spacing, ac 160 80 80 58 40

Maximum spacing now 80 acres

Testing 60 acre and 40 acres spacing

Still working on regulatory offset distances to maximize reservoir development (660 feet down to 300 feet)

Niobrara OPCOMDownspacing Efficiency Improvement

8 Wells

11 Wells

24

80 Acre Pads− 4 Wells ‐ Nelson x17‐9‐60 Pad− 3 Wells ‐ Bringelson x‐34‐9‐58 Pad w/ 1 existing well − 2 Wells ‐ Bringelson x‐33‐9‐58 w/ 1 existing well− 4 Wells ‐ Shull x‐25‐9‐60

60 Acre Pads− 3 Wells ‐ Bobwhite x‐36‐8‐62− 3 Wells ‐ Bailey x‐26‐8‐60− 3 Wells ‐ State x‐36‐9‐61

40 Acre Pads − 3 Wells ‐ Castor x‐36‐9‐59− 3 Wells ‐ Speaker x‐27‐11‐8‐61− 3 Wells ‐ State x‐16‐9‐60

Upcoming 40 Acre “B/B/B” and “B/A/B” Test− “B” Existing Bringelson 2‐20‐11‐9‐58− “B” Bringelson 12‐20‐11‐9‐58− “B” Bringelson 11‐20‐11‐9‐58− “B” Bringelson 10‐20‐11‐9‐58− “B” Bringelson 9‐20‐11‐9‐58− “A” Bringelson 8‐20‐11‐9‐58− “B” Bringelson 7‐20‐11‐9‐58− “A” Bringelson 6‐20‐11‐9‐58− “B” Bringelson 5‐20‐11‐9‐58

Niobrara OPCOMDownspacing Test Summary

25

Niobrara OPCOMDownspacing Summary

26

Cemented

Nelson 2-17-9-60: Completed as a cemented plug and perf well

Directly offsetting 3 open hole completions

Production from the cemented lateral is 12.3% lower than the composite production volume from the offset open hole completed laterals.

Still early time data, 4.6 months of production

Niobrara OPCOMCemented vs. Open Hole Completion – Nelson

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1,000

10,000

100,000

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90 95 100

105

110

115

120

125

130

135

140

BBLS OIL

days

Nelson: Cemented vs. Open Hole Comparison

NELSON AVERAGE NELSON 2‐17 CMT

27

JV participating in “A” bench and “C” bench tests with Whiting and Noble

Wells have been drilled; expecting initial production results in Q1 2014

“A” and “C” benches are more variable, but prospective across JV acreage position

Current plan is to evaluate Noble/Whiting results and test “A” bench at Bringelson20 pad

Could significantly impact future drilling inventory

Niobrara OPCOMVertical Expansion

28

Niobrara OPCOMNoble Rohn Unit

29

Development Plan Update

Niobrara OPCOMDevelopment Plan Update

Currently executing an operated 2‐rig drilling program; dropping to 1‐rig program in 1Q 2014

Selectively participating in 3rd party operated wells‒ Challenging to predict non‐op activity‒ Increase in recent non‐op activity compensates for rig release

Frac activity temporarily sporadic due to permitting challenges; expecting resolution in 1Q 2014

30Note: Assumptions are estimates and subject to change

Niobrara OPCOMDevelopment Plan Highlights

Rig and frac crew schedules

− Drilling with one operated rig (Xtreme 19)

− 26 gross wells (13 net wells)

− Completion activities to utilize one part‐time crew

− 37 gross wells (20 net wells)

− Average 2014 JV working interest estimates: Operated = ~49%

Well information

− Average well cost: Drilling = ~$1.75 million and Completion = ~$2.25 million

− Assumes 20% average royalty burden

Type curve assumptions

− 224 Gross MBOE EUR = 178 MB Oil, 18 MB of NGLS and 169 MMcf gas


Niobrara OPCOM2014 Development Plan Model Assumptions


Niobrara OPCOM2013 Plan Comparison

August 2013 Plan (OLD) Q4 2013 Plan (NEW) ∆ %New less Old New less Old

2013E 2013EQ1 Q2 Q3 Q4 2013E Q1 Q2 Q3 Q4 2013E

Operating Summary (excludes non‐op) Operating Summary (excludes non‐op)Gross Wells Drilled 11.3 14.0 12.7 11.5 49.5 Gross Wells Drilled 11.3 13.9 14.0 14.8 54.0 4.5 9.1%Gross Wells Frac'd 9.8 11.3 12.0 17.8 50.8 Gross Wells Frac'd 10.3 10.7 12.0 9.0 42.0 ‐8.8 ‐17.2%Net Wells Drilled 7.0 8.0 9.3 7.0 31.3 Net Wells Drilled 7.0 7.9 10.1 9.2 34.1 2.8 9.1%Net Wells Frac'd 6.4 6.3 6.9 11.1 30.8 Net Wells Frac'd 6.8 6.0 6.9 7.3 26.9 ‐3.9 ‐12.5%Total Gross Wells Online 41.8 53.0 65.0 82.8 82.8 Total Gross Wells Online 42.3 53.0 65.0 74.0 74.0 ‐8.8 ‐10.6%

Avg. JV Operated WI 61.8% 57.0% 73.2% 61.1% 63.2% Avg. JV Operated WI 61.8% 56.6% 72.4% 61.7% 63.2% 0.0% 0.0%

JV Capital Summary ($MM) JV Capital Summary ($MM)

Net Drilling Capex $12.1 $13.6 $16.2 $12.2 $54.0 Net Drilling Capex $12.1 $13.3 $17.7 $15.5 $58.6 $4.6 8.5%Net Frac Capex $14.2 $14.3 $15.5 $25.1 69.1 Net Frac Capex $15.1 $13.4 $15.5 $16.8 60.9 ‐$8.2 ‐11.9%Total Net Capex $26.3 $27.8 $31.8 $37.3 $123.1 Total Net Capex $27.1 $26.7 $33.3 $32.3 $119.5 ‐$3.7 ‐3.0%

Avg. Drilling Capex / Well $1.7 $1.7 $1.7 $1.7 $1.7 Avg. Drilling Capex / Well $1.7 $1.7 $1.7 $1.7 $1.7 $0.0 ‐0.5%Avg. Frac Capex / Well $2.2 $2.3 $2.2 $2.3 $2.2 Avg. Frac Capex / Well $2.2 $2.3 $2.2 $2.3 $2.3 $0.0 0.7%Avg. Total Well Cost $4.0 $3.9 $4.0 $4.0 $4.0 Avg. Total Well Cost $4.0 $3.9 $4.0 $4.0 $4.0 $0.0 0.2%

JV NRI Production: JV NRI Production:Dry Gas (Mmcf) 76.7 89.0 200.3 280.7 646.6 Dry Gas (Mmcf) 76.7 89.0 221.8 233.7 621.2 ‐25.4 ‐3.9%NGLs (Mbbls) 10.0 11.7 22.2 30.5 74.3 NGLs (Mbbls) 10.0 11.7 24.4 25.5 71.6 ‐2.7 ‐3.6%Oil (Mbbls) 106.8 196.0 242.0 304.1 848.9 Oil (Mbbls) 106.8 196.0 264.7 254.5 822.1 ‐26.9 ‐3.2%JV NRI Production (Mboe) 129.6 222.5 297.6 381.4 1,031.0 JV NRI Production (Mboe) 129.6 222.5 326.1 319.0 997.2 ‐33.8 ‐3.3%JV NRI Daily Production (Mboe/d) 1.4 2.4 3.3 4.2 2.8 JV NRI Daily Production (Mboe/d) 1.4 2.4 3.6 3.5 2.7 ‐0.1 ‐3.3%


Niobrara OPCOMEstimated 2014 Development Plan

Expected completion of frac backlog

2014EQ1 Q2 Q3 Q4 2014E

Operating Summary (excludes non‐op)Gross Wells Drilled 8.1 6.0 6.2 6.2 26.4Gross Wells Frac'd 18.0 3.0 6.0 10.0 37.0Net Wells Drilled 3.9 3.0 3.1 3.1 13.0Net Wells Frac'd 10.1 1.5 3.0 5.0 19.6Total Gross Wells Online 92.0 95.0 101.0 111.0 111.0

Avg. JV Operated WI 48.1% 50.0% 50.0% 50.0% 49.4%

JV Capital Summary ($MM)Net Drilling Capex $6.3 $5.3 $5.4 $5.4 $22.3Net Frac Capex $22.1 $3.4 $6.8 $11.3 43.5Total Net Capex $28.3 $8.6 $12.1 $16.6 $65.7

Production SummaryJV NRI Production:Dry Gas (Mmcf) 334.0 286.7 253.6 241.7 1,116.0NGLs (Mbbls) 36.0 30.9 27.4 26.1 120.4Oil (Mbbls) 356.0 304.3 268.5 255.3 1,184.1JV NRI Production (Mboe) 447.7 383.0 338.1 321.7 1,490.5JV NRI Daily Production (Mboe/d) 4.9 4.2 3.7 3.5 4.1


Niobrara OPCOMEstimated Operations, Capex, and Production

3.9 3.0 3.1 3.1

13.0

10.1

1.53.0

5.0

19.6

0

5

10

15

20

25

Q1 2014 Q2 2014 Q3 2014 Q4 2014 2014E

# of W

ells

JV Net Wells Drilled JV Net Wells Frac'd

$6.3 $5.3 $5.4 $5.4

$22.3 $22.1

$3.4 $6.8 $11.3

$43.5

$0

$10

$20

$30

$40

$50

$60

$70

Q1 2014 Q2 2014 Q3 2014 Q4 2014 2014E

$ in m

illions

JV Net Drilling Capex JV Net Frac Capex

3.93.3

2.9 2.83.2

0.4

0.30.3 0.3

0.3

0.6

0.5

0.5 0.4

0.5

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

Q1 2014 Q2 2014 Q3 2014 Q4 2014 2014E

JV NRI Daily Produ

ction (M

BOED

)

Oil NGLs Dry Gas

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Lease Operating Expense Overview

Niobrara OPCOMLease Operating Expenses Overview

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Niobrara OPCOMLOE for 2013

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

$10.00

Jan‐13 Feb‐13 Mar‐13 Apr‐13 May‐13 Jun‐13 Jul‐13 Aug‐13 Sep‐13

NIOBRARA LOE TREND 2013TOTAL LOE $/BOE

Spring blizzards prevented WO activity, resulting in June LOE

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11.7% -0.3%

6.2%

2.1%

0.9%2.0%

0.4%1.6%

3.6%

0.0%5.2%

5.7%

19.0%

5.1%

29.5%

4.3%

0.8% 2.2%

2013 Niobrara LOE Composition

Workover

Ad Valorem Taxes

Compression Rental, Oil, Coolant

Contract Pumping Services

Contract Supervision

Electrical Power, Fuel

Insurance

Metering Exps, Calibration, Integra

Miscellaneous

P/L Tarrifs, Compr., Dehyd., & Tran

Producing Overhead

Production Chem & Treating Expenses

Repairs & Maintenance

Salaries & Wages

Salt Water Disposal

Supplies

Transportation, Boats, Helicopters

net equipment rental

Niobrara OPCOMLOE for 2013 (cont’d)

SWD

Repairs & Maintenance

Workover

38

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

40.0%

45.0%


Salt Water Disposal ‐ % of Total LOE


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0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%


Repairs & Maintenance ‐ % of Total LOE


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0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%


Workover ‐ % of Total LOE


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Other Discussion

Niobrara OPCOMOther Discussion

42Note: Assumptions are estimates and subject to change. If no spud date provided, assumes 30 day period spud to frac.

Niobrara OPCOMNon‐Op Well Activity Overview

1 1

2

6

22

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4

6 6

2

19

11

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4

6

8

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12

14

16

18

20

2Q2011 3Q2011 4Q2011 1Q2012 2Q2012 3Q2012 4Q2012 1Q2013 2Q2013 3Q2013 4Q2013

Gross W

ells Spu

d Per Q

uarter

Non‐Op Spud ActivityWhiting Noble


Niobrara OPCOMNon‐Op Well Election OverviewWell Name Operator Letter Date Election Choice

Razor 26K‐2305A Whiting 12/5/13Razor 26K‐2306B Whiting 12/5/13Razor 26K‐2307A Whiting 12/5/13Razor 26K‐2308B Whiting 12/5/13Razor 26K‐3508B Whiting 12/5/13Razor 26K‐3507A Whiting 12/5/13Razor 26K‐3505A Whiting 12/5/13Razor 27I‐2213A Whiting 9/20/13Razor 27I‐2214B Whiting 9/20/13Razor 27I‐2215A Whiting 9/20/13Razor 27I‐2216B Whiting 9/20/13Razor 27I‐3413A Whiting 9/16/13 YesRazor 27I‐3414B Whiting 9/16/13 YesRazor 27I‐3415A Whiting 9/16/13 YesRazor 27I‐3416B Whiting 9/16/13 YesRazor 21C‐2808B Whiting 9/16/13 NoRazor 21C‐2807A Whiting 9/14/13 NoRazor 21C‐2806B Whiting 9/13/13 NoRazor 21C‐2805A Whiting 9/12/13 NoRazor 27L‐3401B Whiting 9/3/13 YesRazor 27L‐3403B Whiting 9/3/13 YesRazor 27L‐3404B Whiting 9/3/13 YesRazor 21B‐2812B Whiting 9/3/13 NoRazor 21B‐2811A Whiting 9/3/13 NoRazor 21B‐2810B Whiting 9/3/13 NoRazor 21B‐2809A Whiting 9/3/13 NoRazor 21A‐2816B Whiting 8/26/13Razor 21A‐2815A Whiting 8/26/13Razor 21A‐2814B Whiting 8/26/13Razor 21A‐2813A Whiting 8/26/13Razor 27K‐3405A Whiting 7/25/13 YesRazor 27K‐3406B Whiting 7/25/13 YesRazor 27K‐3407A Whiting 7/25/13 YesRazor 27K‐3408B Whiting 7/25/13 YesRazor 27J‐3409A Whiting 7/22/13 YesRazor 27J‐3410B Whiting 7/22/13 YesRazor 27J‐3411A Whiting 7/22/13 YesRazor 27J‐3412B Whiting 7/22/13 YesHorsetail 07‐0611H Whiting 6/1/13 YesWildhorse 05‐0514H Whiting 5/28/13 NoWildhorse 06‐0614H Whiting 5/7/13 NoRazor 21‐2832H Whiting 4/10/13 YesRazor 33‐2813H Whiting 4/8/13 YesRazor 22‐2712H Whiting 1/7/13

Well Name Operator Letter Date Election Choice

Timbro State LD 16‐65HN Noble 9/1/13 YesTimbro State LD 16‐66‐1HN Noble 8/31/13 YesTimbro State LD 16‐66HN Noble 8/30/13 YesTimbro State LD 16‐68‐1HN Noble 8/29/13 YesTimbro State LD 16‐67HN Noble 8/29/13 YesTimbro State LD 16‐67‐1HN Noble 8/29/13 YesRohn State LD09‐69‐1HN Noble 7/10/13 YesRohn State LD09‐68HN Noble 7/10/13 YesRohn State LD09‐68‐1HN Noble 7/10/13 YesRohn State LD09‐63HN Noble 7/10/13 YesRohn State LD09‐65HN Noble 7/10/13 YesRohn State LD09‐65‐1HN Noble 7/10/13 YesRohn State LD09‐64HN Noble 7/10/13 YesRohn State LD09‐64‐1HN Noble 7/10/13 YesCastor LC35‐62HN Noble 7/9/13 YesRohn State LD04‐63‐1HN Noble 7/8/13 YesRohn State LD04‐62HN Noble 7/8/13 YesRohn State LD04‐62‐1HN Noble 7/8/13 YesRohn State LD09‐69HN Noble 7/8/13 YesRohn State LD09‐67HN Noble 7/8/13 YesRohn State LD09‐67‐1HN Noble 7/8/13 YesRohn State LD09‐66HN Noble 7/8/13 YesRohn State LD09‐66‐1HN Noble 7/8/13 YesHunt LF18‐62HN Noble 7/5/13 YesRohn State LD04‐65‐1HN Noble 6/26/13 YesRohn State LD04‐64HN Noble 6/26/13 YesRohn State LD04‐64‐1HN Noble 6/26/13 YesRohn State LD04‐63HN Noble 6/26/13 YesRohn State LD04‐68HN Noble 6/26/13 YesRohn State LD04‐68‐1HN Noble 6/26/13 YesRohn State LD04‐67HN Noble 6/26/13 YesRohn State LD04‐65HN Noble 6/13/13 YesRohn State LD04‐66HN Noble 6/13/13 YesRohn State LD04‐66‐1HN Noble 6/13/13 YesRohn State LD04‐67‐1HN Noble 6/12/13 YesKeota PC LB26‐62HN Noble 5/23/13 YesTimbro LC10‐72HN Noble 5/16/13 YesTimbro LD06‐64HN Noble 5/16/13 YesTimbro LC12‐78HN Noble 5/9/13 Yes

44Note: Assumptions are estimates and subject to change.

Niobrara OPCOMNon‐Op Revenue / JIB Overview

OperatorNon-Op JIBs

ReceivedNon-Op JIBs

Paid

Non-Op Revenue Received

Carrizo Operated Revenues

Paid Comments

Noble Energy, Inc. Yes No Yes Yes

Over the past few months Carrizo has been working with Noble to resolve various issues outstanding. The teams have made significant progress resolving division order and title issues and obtaining signed JOAs from Noble. As a result, Carrizo is currently releasing approximately $9 million of revenue to Noble. Carrizo not currently paying Noble JIBs as the land departments of each company are currently working through certain working interest issues. Noble has paid Carrizo on three wells and other wells remain in suspense due to working interest issues being resolved.

Whiting Oil & Gas Yes Yes Yes Yes

Carrizo has been in negative revenue suspense since September 2012 as prior revenues were paid at a higher working interest and companies are working to get appropriate interests in order. Carrizo is still waiting on Whiting to correct certain deck issues.

Niobrara OPCOM Meeting - Oil India13 Aug ‐ 13 Sep ‐ 13 Oct ‐ 13 Nov ‐ 13 Dec ‐ 13 Jan ‐...

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