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Performance Audit of Hydrocarbon
Exploration efforts by ONGC
Audit Case StudySession - I
Dr VISHAL DESAI IA & AS
Dy Director of Commercial Audit & ex-officio Member Audit Board-II, Mumbai
Presentation plan
I. Exploration of Hydrocarbons in India
II. Basis of selection of Performance Audit(PA)
III. Process of approval
IV. Audit Plan
V. Execution Process
VI. Report finalization
VII. Approval
VIII. Presentation to Parliament
2
3
I. Exploration of Hydrocarbons in India
Exploration activities are carried out in India in two
offshore basins and six onshore basins
Offshore• Western Offshore Basin
• Eastern Offshore Basin
Onshore• Western Onshore Basin
• Frontier Basin
• Assam & Assam Arakan Basin
• Mahanadi- Bengal- Andaman Basin
• Krishna Godavari Basin and
• Cauvery Basin
Exploration is carried out in blocks awarded onnomination basis to National Oil Companies and NELPblocks awarded to private / public sector on biddingbasis
4
Category-I:
Proved petroliferous basins with
commercial production
Category-II:
Basins with known occurrence of
hydrocarbons but from which no
commercial production has been yet
obtained
Category-III:
Basins with no significant
hydrocarbon shows but assumed
prospective on geological
considerations
Category-IV:
Frontier basins with uncertain
prospects. Deemed prospective on
analogy with similar basins
worldwideDeep Waters
I. Exploration of Hydrocarbons in India -Indian Sedimentary Basins
5
Exploration Activity Cycle
Seismic Data Acquisition (2D/3D)
Seismic Data Processing (2D/3D)
Data Interpretation & Integration
Generation of Prospects
Drilling
Reservoir Studies
Production
Well Logs
MHS
Reconnaissance/Gravity Magnetic
ONGC – the Auditee
• Oil and Natural Gas Corporation Limited (ONGC)-Indian multinational oil and gas company headquarteredin Delhi, India.
• One of the largest Asia-based oil and gas exploration andproduction companies, and produces around 72% ofIndia's crude oil (equivalent to around 30% of the country'stotal demand) and around 48% of its natural gas.
• One of the largest publicly traded companies by marketcapitalization in India.
• ONGC was founded on 14 August 1956 by the Indian state,which currently holds a 69.23% equity stake. It is involved inexploring for and exploiting hydrocarbons in 26 sedimentarybasins of India, and owns and operates over 11,000 kilometersof pipelines in the country. Its international subsidiary ONGCVidesh currently has projects in 15 countries
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I. Exploration of Hydrocarbons by –Oil and Natural Gas Corporation - E&P Activities
ONGC activities under exploration and productioninclude:
Exploration of hydrocarbon bearing zones byacquisition of sub surface data through survey,processing of the acquired data, interpretation of theprocessed data and drilling exploratory wells inprospective areas of various BASINS to establishreserves for further exploitation.
Production of oil & gas by drilling development wellsand installing production and transportation facilities(ASSETS) in proved fields.
Above activities are carried out in onshore as well asoffshore areas.
8
I. Exploration of Hydrocarbons in India
Petroleum Exploration Licence (PEL) NominationBlocks
• Government of India (GOI) on nomination basis grantedPEL to National Oil Companies viz. ONGC and OIL forexploration of the blocks
• Granted for a period of four years with a provision forextension for 5th year.
• In March 2002, GOI decided grant of extension of fifthyear subject to surrender of 25 per cent of the originalPEL area held by the Company.
• Grant of sixth and seventh year extension is for pursuingthe lead of hydrocarbon reserves with a condition thatmaximum area retained can not exceed 50 per cent ofthe original PEL area.
• No regrant would be available after completion ofcurrent grant cycle where neither leads have beenobtained nor discovery has been made.
9
I. Exploration of Hydrocarbons in India
New Exploration Licensing Policy (NELP) Blocks
• The GOI introduced NELP in 1998 whereby blocks areawarded on the basis of bidding by the parties.
• Salient Features of the Policy
– Production Sharing Contracts (PSCs) are entered into withGovernment of India
– The PSCs are for a period of seven years and normallydivided into three phases (3+2+2 years)
– Phase-wise Minimum Work Programme (MWP) is specifiedin the PSCs. Failure to adhere to phase-wise MWP attractssurrender of area and Liquidated Damages (LD)
– First extension of six months- without any LiquidatedDamages (LD),
Second extension of six months- payment of 10 per cent ofunfinished MWP and surrender of area as specified in thePSC and
Third extension of six months- payment of 30 per cent ofunfinished MWP
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PEL and NELP blocks with ONGC as
on 1 April 2007 and 31 March 2010
No. of
blocks as
on
1.4.07
Area
(Sq.Km)
No. of
blocks as
on
31.3.10
Area
retained
(Sq.Km)
PEL 108 128442 62 81997
NELP 39 302644 71 423093
Total 147 431086 133 505090
II. Basis of selection of PA
Financial Materiality and Criticality
Previous Audits on Exploration
PA on Deep Water Exploration of ONGC in 2008
PA on Onland Exploration of ONGC in 2009
PA on Shallow water Exploration of ONGC in 2010
PA on Hydrocarbon Production Sharing
Contracts of Ministry of Petroleum and Natural
Gas in 2011
Physical and Finance Performance of ONGC during
2000-01 to 2009-10
11
12
II. Basis of Selection of PA: Criticality & Materiality
The main objective of exploration is to accrete reserves such thatproduction of hydrocarbons of ONGC is sustained. Henceexploration, establishment and exploitation of reserves is critical tothe overall performance of ONGC.
Year wise expenditure incurred by ONGC on exploration activities
Rs. In crore
Year Seismic survey Exploratory drilling Total
2007-08 1656.29 2519.09 4715.38
2008-09 3071.83 4299.48 7371.31
2009-10 2158.72 7252.70 9411.42
2010-11 1656.74 8625.27 10282.01
Total 47748.34 22696.54 70444.88
II. Basis of Selection of PA - Previous audits
PAs on Deepwater, Onland and Shallow water Exploration• No firm reserve accretion target though ONGC in deep water exploration
since 1970
• ONGC’s 20 - year perspective plan envisaged (2003) four billion tons of
hydrocarbon reserve from deep water prospects - decided to pursue
aggressive exploration campaign in deep waters.
• During 10th FYP, even after spending over Rs.5,769.12 crore in deep water
exploration, ONGC could add only 172.17 Million Metric tons of oil equivalent
(MMtoe) to Initially In Place (IIP) reserve out of which nearly 74 per cent was
from one block acquired by it from CEIL.
• Pre drilling EIA studies took very long time ranging from 21 to 56 months. In
some cases EIA studies were not completed even after completion of Phase-I
of Minimum Work Programme (MWP).
• Non completion of MWP targets led to slow progress in exploration,
relinquishment of blocks after paying liquidated damages (LD) towards
unfinished work in deepwater, onland and shallow water blocks
• Delay in finalisation of contracts both for hiring of rigs/survey impacted the
exploration progress in deepwater, onland and shallow water blocks.
13
II. Basis of Selection - Previous audits
PAs on Deepwater, Onland and Shallow water Exploration• ONGC had not fixed standards/norms for assessment of performance of
Geophysical Parties (GPs) resulting in wide variation in geophysical field
activities in different basins.
• ONGC took abnormally long time in finalising the shot hole drilling and data
acquisition service contracts resulting in idling of GPs for considerable periods
of time
• ONGC had to relinquish prospective areas of nomination blocks due to delays
in exploration and failure to pursue the leads. Exploratory efforts in the five
nomination blocks which were in the last two years of exploration cycle were
slow
• ONGC had identified 89 prospects and 33 prospective leads in 16 shallow
water NELP blocks. However, even after incurring an expenditure of Rs.1,632.48
crore, no hydrocarbon discovery was made in shallow water blocks
• The achievement of MWP committed in the Phase I was incomplete in 9 out of
16 NELP blocks and the entire Phase I was consumed mainly for API of seismic
data and the wells committed in respect of nine blocks were not completed.
Consequently, the Company surrendered/proposed to surrender 10 NELP
blocks after incurring expenditure of Rs.1,461.36 crore14
II. Basis of Selection - Previous audits
PA on Hydrocarbon Production Sharing Contracts–2011-12
• Government of India awarded 203 blocks under New Exploration
Licensing Policy (NELP) up to VII round.
• ONGC got majority of blocks i.e. 92 out of 203 blocks
• ONGC had only 13 discoveries which was much lower than the
overall average performance of all parties
HQrs reviewed (July 2011) the physical and financial performance of
ONGC and observed
• Performance in physical terms indicated that the quantity of major
petroleum products sold had been almost stagnant with a
downward trend over the years from 2000-01 to 2009-10
• Though there was a significant improvement in financial
performance this was attributable to upsurge in the international
price of crude oil and other petroleum products
Decision: To attempt the Performance Audit
15
III. Process of approval of PA
• Preparation of
– Issue Analysis
– Study Design Matrix
– Guidelines and plan of action
(Basis Performance Auditing Guidelines of
C&AG 2004)
• Presentation to Audit Board/Chairman Audit
Board
• Approval for taking up the PA
16
III.Process of Approval - Issue analysis,
Study design Matrix and Guidelines
• Issue Analysis, Study Design Matrix, Guidelines and
plan of action for the PA on Hydrocarbon
Exploration efforts of ONGC prepared in August
2011 covering ONGC’s efforts in exploration
activities during the four period from 2007-08 to
2010-11
• The main focus of audit was proposed to be on the
role played by the top Management in the
exploration efforts and the oversight role of MoPNG
and DGH in addition to the exploratory efforts put in
at the field level
17
III. Process of Approval-Objectives/ Issues/
Themes for the PA
18
To ascertain whether ONGC’s exploration efforts had been
taken up with proper planning and executed with efficiency
and effectiveness to achieve its own and the nation’s
envisioned hydrocarbon goalTheme 1 Theme 2 Theme 3 Theme 4 Theme 5
To examine the
role of ONGC
leadership by
Management in
exploration
efforts of
ONGC
To ascertain if
ONGC
exercised due
care in the
process of
exploration
To verify the
reasonablene
ss of costs of
exploration
To assess
ONGC’s
capacity
(technology,
equipment
and people)
for exploration
To enquire into
the results of
ONGC’s
exploration
efforts
Role played by MOPNG and DGH in the exploration efforts of ONGC
Give perspective to and validate our previous audit findings ( PAs
on onshore, shallow water and deepwater exploration)
Objectives of the PA
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III. Process of Approval-Audit Sample
Audit Sample
All the seven Basins in ONGC have been covered through sampling techniques
to select blocks, exploratory wells, contracts for good s and services.
20
Sl.
No.
Area Sample size percentage Population Sample
size
1 Block audit at
'Basin'.
25 per cent for onshore
and 50 per cent for
offshore blocks
200 94 (Random
selection)
2 Contracts for hiring
for goods and
services.
25 per cent 191 88(based on
materiality in
descending
order)
3 Exploratory wells 20 per cent 457 93 (Random
Selection)
III. Process of Approval - Presentation to
the Audit Board & Approval
Presentation to the Audit Board
• The audit scope, objectives, audit issues, audit
methodology were presented to Chairman, Audit
Board in August 2011
• Deliberations – PA topic was approved with
additional issues to be examined in the PA– Active participation of Board of ONGC in bidding for exploration
blocks
– Hiring of experts
– Judicious and effective utilization of resources by ONGC
– Attitude of DGH to ONGC and other private parties in regard to
grant of licences, sanction for extensions etc.,
21
IV. Audit Plan
Intimation to conduct of Performance Audit• Ministry of Petroleum and Natural Gas (MOPNG)
• Director General of Hydrocarbons (DGH)
• ONGC Management
Entry Conference with MOPNG, DGH and ONGC –held
in September 2011 at DG level with Management Presentation made on audit objectives, time line with
emphasis would be on governance
Records requirement
Coordination for timely completion of the PA
Presentation made Management on Corporate Planning,
Infrastructure, Human Resources, Exploration Process, Role of leadership and decision making in exploration process,
performance bench marking
22
V. Execution Process
• Deployment of manpower– Identification of teams
– Entrustment of themes
• Conduct of field audits
• Issue of Preliminary Observation Memos (POMs)
• Receipt of responses from
Management/Ministry/DGH
• Firming up of the issues
• Periodical review of progress by Group
Officer/Principal Director
• Submission of periodical progress reports
• Mid term review by Headquarters23
V. Execution Process- Deployment of Manpower
The PA was to cover entire exploration by ONGC including the MOPNG
and DGH. The distribution of work was made accordingly as given
below:
24
Team
No.
Composition Area of audit
I 2 Sr.AOs& 2 AAOs
Corporate planning, Performance Bench Marking, Parliamentary Cell,
Costing Cell and Exploration, Development (E&D) Directorate and
MOPNG/DGH
II 2 Sr.AOs& 2 AAOs
Corporate Exploration Cell, Director (Exploration), Company Secretariat,
Corporate Budget Cell, Corporate Administration,
III 1 AO & 3 AAOs Mumbai Basin and Drilling Services(offshore)
IV 1 AO & 3 AAOs Mumbai Basin and Geophysical Services (Offshore)
V 1 Sr.AO & 2 AAOs E&D Directorate, Exploration Contract Monitoring Cell, Frontier Basin
VI 1 Sr.AO & 2 AAOs Assam-Arakan Basin, Mahanadi-Bengal-Andaman Basin, Drilling Services
and Corporate Geophysical Services
VII 2 Sr.AOs& 1 AAO Institute of Petroleum Exploration, Geo-data processing and Interpretation
Centre, Western Onshore Basin, and Onland Drilling services,
VIII 1 Sr.AO& 2 AAOs Krishna Godavari Basin and Cauvery Basin
V. Execution Process
Field Audit conducted from Mid September 2011
to Mid January 2012
Data and evidences collected and POMs issued
during the above period
Issues firmed up after considering the responses
25
VI. Report Finalization
26
Draft Report finalized and issued to
MOPNG/ONGC Management in
February 2012 with a copy to HQrs
Responses for the Draft Report from
ONGC in March 2012
Exit conference
held in March 2012
Final Report incorporating
ONGC’s replies sent to HQrs.
April 2012
VI. Approval
Scrutiny of report at Hqrs
Visit of DG for discussion – June
2012
Document/ Evidences
verification June 2012
Second round of discussion with
Chairman Audit Board in July 2012
Report approved by Chairman and C&AG in August
2012
27
Laying of report
Laying of Report in both the Houses of
Parliament in August 2012
28
End of Session I
Thank you
29
Performance Audit of Hydrocarbon
Exploration efforts by ONGC
Audit Case StudySession - II
Dr VISHAL DESAI IA & AS
Dy Director of Commercial Audit & ex-officio Member Audit Board-II, Mumbai
Hydrocarbon Exploration Efforts of
Oil and Natural Gas Corporation Ltd -What does the C&AG Report say – An insight
Rationale for the PA
• A key focus area of ONGC is HYDROCARBON
EXPLORATION
The Vision & Mission Document of the Company specifies “Focus
on domestic and international oil and gas exploration and production business opportunities” as a key activity of the entity.
• Govt. has set high expectations on ONGC’s
exploration efforts through Hydrocarbon Vision
2020.
• Audit Objective: to ascertain whether ONGC’s
exploration efforts had the drive and zeal to
achieve these ambitious targets.
32
The Audit Questions
Were results of exploration satisfactory?
Does capacity for exploration
exist?
Was governance framework robust?
Wasexplorationprocessefficientand costeffective?
33
Results of Exploration
34
Reserve Accretion
• Actual reserve accretion
only 29% of target.• 80.99 MMT as against 276.48
MMT
• 4 of 7 Basins consistently fell
way behind targets over 2007-
11
• Only 2 Basins (W.Offshore and
W.Onshore) achieved target in
2010-11• One (Frontier Basin) had no
targets
Reserve Accretion
Monetization
Reserve Replacement
Ratio
Discoveries
Finding Cost
Results of Exploration
35
Finding Cost
Finding Costs are
much higher than the
MOU targets (129 –
648%)
Reserve Accretion
Monetization
Reserve Replacement
RatioDiscoveries
Finding Cost
Results of Exploration
36
Discoveries
• Though ONGC made 99 discoveries
in NELP and Nomination blocks over
2007-2011, they accreted a reserve of
only 80.98 MMT.
•A comparison of discoveries in the
NELP regime (upto Feb 2011) shows
that despite its large acreage and
rich experience in E&P sector, ONGC
made lesser discoveries than new
entrants
Reserve Accretion
Monetization
Reserve Replacement
RatioDiscoveries
Finding Cost
Company Oil Gas
ONGC 5 13
GSPC 11 8
RIL 11 15
Results of Exploration
37
Monetisation
• Monetised only 73 out of its 158
discoveries made during 2002
to 2011
• The Company succeeded inmonetizing only 2 out of the 56
offshore discoveries
• Non-monetised offshore
discoveries contain major
reserve accreted
• Success in monetizing marginal
fields is also limited. Only 53 outof 165 marginal fields have sofar been monetized.
Reserve Accretion
Monetization
Reserve Replacement
RatioDiscoveries
Finding Cost
Results of Exploration
38
Reserve Replacement Ratio
• ONGC’s RRR is above 1
• RRR has steadily increased
from 1.32 in 2007-08 to 1.80 in
2010-11
• RRR has been healthy
because:
- Reserves are mainly accreted
through reinterpretation and
development drilling rather than
exploration
- Production has remained
steady/ dipped somewhat
Reserve Accretion
Monetization
Reserve Replacemen
t Ratio
Discoveries
Finding Cost
What is RRR?
– RRR = Now Ultimate Reserve accreted during a year
Total production of hydrocarbon during a year
– It is the significant parameter to indicate sustainability.
An RRR>1 implies that the company is able to
replenish its reserves from which it produces oil and
gas
– One of the main objectives of the Hydrocarbon Policy
under India Hydrocarbon Vision is to achieve anRRR>1
39
Efficiency of the exploration process & reasonableness of costs of exploration
Was ONGC efficient in
conducting surveys?
Was exploratory drilling
adequate and
efficient?
Was performance satisfactory in
nomination blocks?
Was performanc
e satisfactory
in NELP
blocks?
40
Acquisition, Processing and Interpretation-API (Survey)
• Non fixation of norms for API cycle
• Delay in hiring of offshore survey
vessels leads to shortfall in data
acquisition ( 18/20 contracts)
• Delay in acquisition of offshore survey
vessel
• Delay in award of service contracts for
onland survey
• Deployment of GPs for onland survey
were less than norms
Time taken for API cycle ranges from 4
to 56 months.
41
Delay in hiring
vessels
• ONGC takes upto 178 days to finalisecontracts for hire of survey vessel as against the norm of
120 to 135 days
Deployment does not match
field season
• While field season for offshore survey starts from Oct to May , actual deployment starts from Nov to
January
Shortfall in
acquisition
• Loss of field season
• Shortfall in Acquisition
of Data
Exploratory Drilling
• Planning was deficient – The availability of rigs was incorrectly assessed leading to a
shortfall of 30.25 rig months.
– The time taken to re-hire rigs was incorrectly estimatedleading to a shortfall of 40 rig months.
– Delay in mobilization as award of contract overlappedwith monsoon.
• Implementation was inefficient– Delay in hiring of offshore rigs
• Time taken 203 to 520 days/normal of 180 days
– Delay in acquisition of rigs• 10 onland rigs proposed for induction between 2003-2006 are yet
to be ordered• 4 offshore jack up rigs proposed for purchase in 2002/2006 is yet
to materialize
– Delay in refurbishing of onland rigs
42
Exploratory Drilling
• NPT
– Average non productive time of rigs was
19 % against 10% planned by ONGC
during 2008-2011.
– International norm is 5 %.
• Drilling efficiency of own rigs was
lower than that of hired rigs
– Age of own rigs more than 17/18 years
– Dated technology & equipment
– Acute shortage of drilling personnel
• Variance analysis of well costs not
done by basins
43
Performance Comparison with PeersArea Drilled
Depth
range
(in meters)
Average m/day (well depth/total drilling
days)
ONGC Private/JV operators
Ahmedabad 1000-2000 61.9 GSPCL 65.37
SELAN 63.00
2000-3000 54.43 GSPCL 56.45
Mehsana 2000-3000 35.4 JOGPL 62.17
Cambay 1000-2000 48.58 NIKO 40.20
SELAN 66.65
EOL 49.50
Jodhpur 2000-3000 27.27 PEL 42.58
KG (off.) 2000-3000 47.36 HEPI 40.48
GAZPRO 16.44
Assam-Arakan 3000-6000 14.84(Sivasagar) OIL 56.42
Canoco 28.37
Assam-Arakan 3000-6000 32.35(Jorhat) OIL 28.68
Canoco 31.1344
Performance in NELP
• ONGC lost 69 blocks due to lack of aggression in
the NELP bids (lower work commitment). In 17 of
these, others made 67 discoveries.
• ONGC paid liquidated damages of Rs 133.03 crores
for non-completion of MWP in respect of 13 blocks.
• Poor performance in deepwater blocks (37% of
ONGC’s blocks are deepwater blocks) eventhough these have high prospectivity.
45
Performance in Nomination Blocks
• ONGC relinquished nomination blocks
without fully exploring prospectivity even
after holding them for over 12-14 years.
• Progress of exploration was slow. Exploration
is yet to be completed in six blocks that
were with ONGC for 13-25 years (as againstthe NELP norm of 7-8 years).
46
Capacity for exploration
Human resources
Financial resources
Technology
47
People for exploration
• Shortfall at cutting edge
– Shortfall in drilling services
– Shortfall in rigman, topman cadres
– Q3 executives employed for Q1 and Q2 positions
• High rate of attrition at middle levels
• Lack of succession planning at top management level
• Transparent system of hiring consultants is not adhered to.
– ~50% consultants hired were ex-ONGC employees
48
Financial Resources
• Sufficient financial resources for exploration. Alloted budget
not spent as high as Rs.1324 crore (12.2 per cent) in 2009-10 .
• Shortfall in budget utilisation to be viewed in context of under-performance on targets of survey (upto 60 per cent) as well as
exploratory drilling (upto 29 per cent).
49
Technology
• ONGC unable to provide assurance on
status of technology to Planning Commission
• Independent assessment by third party not
done.
50
Governance framework and leadership role
Was vision of Government and
ONGC emphasis in exploration aligned?
Was the reporting against these
targets correct?
Performance measurement
systems in ONGC
Whether the MOU targets
were fixed properly?
51
Planned targets do not ‘stretch’
Hydrocarbon Vision
ONGC’s Exploration & Production Strategy
Doubling of in place volume ofhydrocarbons (IIH) from 6 Billion Tonnes (BT)to 12 BT by 2020. This doubling is to be donein three phases – 1.2 BT by 2007, 2.2 BT by
2014 and 2.6 BT by 2020.ONGC’s XI five year plan target
While ONGC’s strategy objectiveenvisaged 2.2 BT by 2014, ONGC’s XI fiveyear plan 2007-2012 planned for only 1.001BT IIH. This leaves 1.2 BT IIH to be achievedin the remaining two years if the strategicobjective is to be met. Achievement of IIHof 1BT in two years is remote consideringthe achievement during the four years(2007-11) which was only 0.95BT (averaging
0.239BT per year).52
Differing criteria for target setting & reporting
53
Target Setting
for MOU
Reporting on
MOU Targets
Ultimate Reserve Accretion
Year Target Reported
Achievement
Achievement
through
Exploration Efforts
2007-08 55 63.82 22.22
2008-09 64.5 68.9 8.67
2009-10 72.65 82.98 18.34
2010-11 76.9 83.56 31.77
MMToe
Reserve Accretion through exploration is only
13% to 38 % of the reported ultimate reserve
accretion
Issues in Performance Measurement
Internal
• Basins get full marks on some KPIs where targets are not fixed– Eg, no activity on 2D seismic acquisition of data happened in W offshore.
Hence there could be no targets. However, full marks given for
performance against this parameter.
• Uniform target of 33 percent exploratory wells success ratio for
all seven basins
• Basin targets for finding costs are based only on previous
year’s performance, rather than current years’ projections.
External
• Absence of performance benchmarking of E&P activities vis-
à-vis international norms despite EC directions.
54
Conclusion
• ONGC’s current exploration efforts are not
adequate to achieve envisaged strategic goals.
The current MOU performance indicators do not
highlight this inadequacy of exploration efforts
leading to a false sense of accomplishment.
• ONGC mainly operates in its producing fields to
meet both, reserve accretion and production
targets. Lack of adequate efforts and results in new
fields, coupled with the ageing of producing fields,
is a matter of concern for future sustainability.
55
Conclusion
56
Producing Fields
Ageing Fields from where Reserve Accretion ( reiniterpretation &
development drilling) and Production ( IOR/EOR) mainly
takes place
New Fields
Shortfall in exploration efforts, low reserve
accretion, few discoveries, diminishing find size and
delay in monetization
Recommendations
• Strengthen the performance accountability framework for exploration
– Setting MoU targets and measuring them accurately
– Suitability of RRR as a KPI
• Introduce a MOU parameter for monetisation of discoveries
• Benchmark Exploration Performance
– Internal and peer benchmarking suitably
• Improve efficiency of Exploration Process
– Systemic lacunae in tendering and award of contracts
– Setting appropriate targets
– Overcoming delay in acquisition/ hiring
• Independent assurance on Technology
57
Thank You
58
Audit of Hydrocarbon Production Sharing
Contracts
C&AG’s Audit Reports
No 19 of 2011-12 and No 24 of 2014
Background First report was presented to the Parliament on 08th September 2011
and the second report was presented on 28th November, 2014,
First audit was done as per MoPNG’s request (received in November2007):
Audit was a performance audit of Implementation of HydrocarbonPSCs at MoPNG and DGH covering the period 2003-04 to 2007-08
Supplementary scrutiny of records of the operators of four blocksviz. KG-DWN-98/3, Panna-Mukta, Mid and South Tapti and RJ-ON-90/1 for the years 2006-2008,
Total 7 PAC meetings have been held on the report,
Second audit was done as per MoPNG’s request (received in April2010); and period covered was 2008-2012,
Audit was a performance audit of Implementation of HydrocarbonPSCs at MoPNG and DGH
Financial and Propriety audit vis-à-vis PSC provisions of Operators ofBlocks viz. KG-DWN-98/3, Panna-Mukta, Tapti and RJ-ON-90/1.
2
Audit Objectives
A. Performance Audit was conducted to obtain an assurance that:
the systems / procedures of MoPNG / DGH were adequate andeffective in monitoring and ensure compliance with PSC terms;and
the revenue interests of the Government (including royalty andGoI share of profit petroleum) were properly protected, andadequate and effective mechanisms were in position for thispurpose,
B. Audit of the Operators’ books and records was conducted:
To verify whether the Government’s revenue in the form of profitpetroleum and royalty was correctly calculated and
To obtain an assurance that the expenditure incurred was incompliance with PSC provisions, accurately and reliably reflected,and these amounts were supported by adequate documentation
3
Audit criteria
The criteria adopted was drawn from the following sources:
Relevant Production Sharing Contract,
Joint Operating Agreement,
Oil Field (Regulation and Development) Act, 1948,
Petroleum and Natural Gas Rules, 1959,
NELP and subsidiary instructions of MoPNG,
Directives/Notifications issues by MoPNG/DGH,
Policies framed by GoI for petroleum operations,
Generally Accepted Accounting Practices/AccountingStandards.
4
Block - KG-DWN-98/3 Operator - RIL
JV Partners – RIL (60%), BP (30%), Niko (10%)
5
Introduction
The KG-DWN-98/3 (also referred to as KG-D6) block, with acontract area of 7645 square km (sq. km.), is an offshore block inthe Krishna-Godavari (KG) basin in the Bay of Bengal,
The Block is classified as a “deepwater block”, with water depthranging from 400 metres (m) in the north-west to 2700 m in thesouth-east,
In April 2000, GoI awarded the block to a consortium led byReliance Industries Limited (RIL) under the NELP – I:
Till August 2011, the only other member of the consortium wasa Canadian company, namely Niko Resources Limited (NIKO).
In 2011, RIL assigned its 30 per cent PI to BP Exploration(Alpha) Limited (BP)
RIL, however, continued to remain the ‘Operator’ of the Block.
6
7
Report no 19 of 2011-12
Non-relinquishment of area
PSC stipulated relinquishment of 25% each of total contract
area at end of Exploration Phases I and II,
Contractor entered Phases II & III without relinquishment
treating entire area as Discovery Area,
In May 2004, DGH did not agree to operator’s proposal. A
year later, DGH ‘waived’ its earlier objection and advised
operator to complete 3D seismic survey in entire block
(instead of drilling wells in all parts of the contract area)
In July 2006, DGH completed its about turn, and agreed to
the operator’s proposal,
Subsequently, in February 2009, GoI approved treating
entire contract area (7645 sq km) as ‘Discovery Area’
Post contract concession of non relinquishment of area was
given to RIL (comparison). 8
Development activities
MC approved the Initial Development Plan (IDP) in November 2004.
However, immediate action for procurement of major equipment/
materials/services was not initiated, and progress in field
development work was not as per IDP,
Operator submitted Addendum to IDP (AIDP) in October 2006:
Activities in respect of AIDP were initiated even before submission/
approval of AIDP.
The scale of revision of IDP through the addendum in such a short
time span cast doubts on the robustness of the data and
assumptions underlying the development plans
9
Particulars IDP – 2004 AIDP - 2006
Estimated Capex $ 2.4 billion $ 8.8 billion
Gas Production Rate 40 mmscmd 80 mmscmd
First Gas Production August 2006 Mid-2008
Profit Sharing Formula
The PSC is based on a scaled formula for profit sharing between GoI
and the private contractors:
This is based on a critical parameter – the Investment Multiple
(IM)– which is essentially an index of the capital-intensive nature
of the project i.e. IM = Cumulative Net Cash Income/ Cumulative
Exploration & Development Costs,
The more capital intensive the project, the lower the IM and GoI
share of profit petroleum (as low as 10%) and Higher the IM,
higher the GoI share (as high as 85%),
Private contractors have inadequate incentive to reduce capital
expenditure, and substantial incentive to increase/ ‘front-end’ capital
expenditure
So as to retain the IM in lower slabs or to delay movement to
higher slabs.
10
Procurement activities
Audit could not derive assurance as to reasonableness of costs,
primarily due to lack of adequate competition:
Award on single financial bids - There were instances where
multiple vendors were pre-qualified. However, when technical
bids were received, all vendors (except one) were rejected,
and the contract was finally awarded on a single financial bid,
Major revisions in scope/ quantities/ specifications post-price
bid opening, substantial variation orders,
Any commercially prudent private acquisition would attempt to
generate competition. Such concern for cost-effective acquisition
was not perceptible in these cases with consequential adverse
implications for cost recovery and GoI’s financial take.
11
12
Report no 24 of 2014
Audit constraints
Incomplete list of Purchase Order
Audit uses sampling techniques for selection of cases fordetailed examination. In response to audit requests, theOperator provided several lists of POs but none of the lists wascomplete,
Due to this there could be some POs which may have fallenoutside the ‘population’ and, therefore, were not picked up fordetailed scrutiny in Audit,
Restricted access to SAP
The Operator, inspite of having information on audit schedule,gave restricted access to SAP and provided fragmentedinformation
13
Exploration, appraisal and relinquishment
In this audit, C&AG observed that Ministry’s decision treating
entire contract area as ‘discovery area’ as per PSC
provisions meant that the Operator cannot do any further
exploration activity except appraisal activities relating to the
discoveries made till July 2006 in the ‘discovery area’,
14
Exploration Discovery AppraisalDeclaration of Commerciality
Exploration, appraisal and relinquishment
However, the Operator was improperly allowed to do further
exploration activities in the ‘discovery area’ at an
expenditure of US$ 427.03 million to be recovered from the
revenue of the commercial discoveries already made in the
block,
C&AG has recommended disallowance of US$ 118.99
million already effected by the Operator on four exploration
wells that did not result in commercial discovery.
15
Declaration of Commerciality (DoC)
As per the PSC, the review of proposal for DoC in respect of
three discoveries (viz. D29, D30 and D31) was to be completed
by Management Committee by August 2010,
DGH rejected the proposal in October 2010 due to non-
production of sustainable production data by Contractor. In
August 2013, Secretary, MoPNG agreed with DGH,
However, later, in October 2013, MoPNG allowed the Contractor
to retain 298 sq. km. contract area for these three discoveries
under a tentative Petroleum Exploration License. Accordingly,
Operator proposed an expenditure of $100 mn in the budget,
Despite technical advice by DGH, the issue was reopened after
around 3 years and the issue had not been finalized even after
four years.
16
Disallowed appraisal wells
Expenditure of US$160.81 million incurred on account ofthree appraisal wells was not eligible for cost recovery astwo wells were drilled post submission of DoC proposal andone well was drilled outside the MC reviewed appraisal area.This had been disallowed by MoPNG
Audit observed that even after the MoPNG communicatedits decision, the Operator continued to claim the costrecovery, as seen in the final accounts for the year ended2013,
As of June 2014, the MoPNG had been unable to enforce itsdecision.
17
Estimation of D1-D3 gas fields
MoPNG and DGH are responsible for scrutinizing developmentplans prior to their approval,
It was noticed that there was uncertainty in the recoverablegas reserves estimates and substantial changes were made toit after the approval of the development plan,
This raises questions on the process of examination,consideration and acceptance of gas estimates by the DGH
The DGH went along with the estimates of the Operator evenwhen its own consultants had expressed reservations againstit.
Plan Month/Year Recoverable Reserve
IDP May 2004 3.81 tcf
AIDP October 2006 10.03 tcf
RFDP August 2012 2.90 tcf
18
Decline in Gas production
The Operator was required to drill, connect and put on stream 22 wells asper approved Phase I of AIDP, however, the Operator had drilled,completed and connected only 18 wells,
Production from the D1-D3 field commenced in April 2009 and starteddeclining in August 2010. While production level achieved in 2010-11 was90 per cent of approved production profile, this decreased to 57 per centin 2011-12 and 26 per cent in 2012-13,
C&AG noticed that that, as of March 2012, out of 18 wells connected,only 12 wells were producing gas and six wells had ceased to flow due towater and sand ingress,
Due to non-drilling of wells and decline in production of gas, the facilitiescreated by the Operator remained underutilized / unutilized.
The Operator’s decision to not drill and connect the committed producerwells as per the approved AIDP even after repeated reminders by theDGH is a matter to be seriously considered and resolved by the MoPNG toensure the energy security of the country 19
Work Programme and Budget (WP&B)
Approval of the WP&B is a key function of the MC,
In none of the four years the WP&B was approved beforestart of the financial year,
In 2008-09 (BE), 2010-11 (BE) and 2011-12 (BE / RE), due todelays, the Operator incurred expenditure before MCapproval
For 2008-09 and 2009-10, the revised estimates wereapproved after end of the respective years.
20
Contract for EPIC of offshore facilities – EURO 200 mn.,
Contract for chartering FPSO – US$ 77.36 mn.,
Unjustified compensation on free-issue material inconstruction of OT - INR 1110.09 mn.,
Start-up and Production bonuses of US$12.48 million,
Payment of bonus for rig movement of US$ 2.83 million,
Uptime bonus for providing contractual obligations of US$13.37 million,
Improper allocation of expenditure on risk advisory servicesUS$ 1.17 million.
22
Disallowances : Expenditure issues
DISALLOWANCES : REVENUE ISSUES
Marketing Margin on gas produced and sold
The Operator is charging the gas price @ US$ 4.340 mmbtu (whichalso includes 0.135 US$/mmbtu towards marketing margin) from itsconsumers. However, while computing the Profit Petroleum andRoyalty, the Operator is considering the price of US$ 4.205 insteadof the actual price of US$ 4.340 being charged,
It had collected an amount of US$ 261.33 million towards theMarketing Margin, which has not been accounted for in the Booksof JV,
Consequently, cost recovery of US$ 235.20 million (90 per cent) hadnot been adjusted in the recovered cost up to 2012-13 and therewas a short remittance of Government share of Profit Petroleumand Royalty by US$ 2.61 million and US$ 13.11 million respectivelyfor the years 2009-10 to 2012-13.
23
DISALLOWANCES : Accounting ISSUES
The Operator had been charging Parent Company Overhead (PCO)since 2002-03 to 2007-08. MC disallowed (November 2008) theexpenditure of US$ 40 million upto 2007-08 on the ground that theOperator had no Parent Company. The Operator, during 2008-09accounts, reversed the disallowed cost upto 2007-08 and booked itunder Corporate Office Support in the year 2008-09 by reclassifyingthe said disallowed cost and upto 2011-12, has charged US$ 101.41million. Further, this expenditure couldn’t be vouched by audit inabsence of documentary evidence.
The Operator had not accounted for the value of closing stock ofCrude and Condensate valuing to US$ 14.22 million,
Consequently, cost recovery of US$ 12.80 million towards the valueof closing stock had not been adjusted and there was a shortremittance of US$ 0.14 million.
24
Conclusion
Despite the Government of India being signatory to the PSC,
a regulator in the E&P field and also trustee of sovereign
natural resources, the PSC provides few intermediate
measures to protect its interests,
MoPNG/ DGH have been unable to take effective and result
oriented punitive measures against the Contractor in such
cases,
Therefore, we are of a view that the future PSCs need to be
strengthened by incorporating sufficient mechanism for
overseeing activities and imposing punitive measures, where
the occasion so demands.
25
Thank you
26
Discovery area
Discovery Area (as per PSC)
“.. That part of the contract area about which,
based on discovery and results obtained from a
well or wells drilled in such part, the contractors is
of the opinion that petroleum exists and is likely to
be produced in commercial quantities”
Discovery is defined as “ the finding, during
petroleum operations, of a deposit of petroleum not
previously known to have existed, which can be
recovered at the surface in a flow measurable by
conventional petroleum industry testing methods”27
Comparison of blocks operated by ONGC and RIL
•Note: reference to ONGC block (KG-DWN-98/2) drawn by MoPNG in its reply.
•Exploratory wells were drilled in the entire contract area of the ONGC operated block
(left). In fact, ONGC had relinquished a part of the contract area as required under the
PSC.
•In the RIL operated KG-DWN-98/3 (right), exploratory wells were drilled in the north
western part only. Post contract concession of non relinquishment of area was given to
RIL whereas this was not the case in respect of ONGC block.28
Interpretation of discovery area
Implementation of this interpretation (which is incorrect, in
our opinion) required cessation of exploration activities,
commencement of appraisal from July 2006 and completion
thereof by July 2009.
After this point of time, the contractor’s only course of action
was to prepare development plans on the basis of appraisal,
identify development areas for development, and relinquish
the balance area forthwith within the PSC-stipulated
timelines. This was also not done.
DGH and MoPNG chose to go along with differing
interpretations of the operator concurrently – to continue
with exploration activities, side by side with declaration of the
entire contract area as discovery area.
Profit Sharing Formula
30
Investment Multiple (IM) Government Share
Contractors’ Share
Less than 1.5 10 % 90%
1.5 to less than 2.0 16 % 84 %
2.0 to less than 2.5 28 % 72 %
2.5 and above 85 % 15 %
IM = Cumulative Net Cash Income/ Cumulative Exploration & DevelopmentCosts
The more capital intensive the project, the lower the IM and GoI share ofprofit petroleum as low as 10% and Higher the IM, higher the GoI share ashigh as 85%.
Contract for EPIC of offshore facilities
Operator awarded a contract relating to Engineering,Procurement, Installation and Construction (EPIC) of offshorefacilities to a vendor on a lump sum contract, signed afterdetailed pre-bid meetings,
Vendor defaulted on milestones,
The Operator gave concessions of Euro 200 million(approximately) to the vendor which were not allowable for costrecovery, being not in line with:
EPIC contract; and,
Section 3.2 (ix) of Appendix C to the Accounting Procedure toPSC.
31
Contract for chartering FPSO
The Operator signed chartering of a Floating Production, Storage andOffloading (FPSO),
o Despite the fact that FPSO was chartered for 10 years only, theoperator extended the dry docking life of the FPSO from 10 to 15years for a one-time compensation of US$ 17.36 million,
o FPSO vendor committed the date of first production of oil for 27 April2008. Vendor was to be paid lease rental from DFPO date only. So itwas in vendor's interest to achieve DFPO. Despite MC approval ofDFPO for June 2009 Operator paid unnecessary compensation of US$45 million for DFPO at September 2008.
o Avoidable refurbishment of existing living quarters despite nonexercise of purchase option resulting in expenditure of US$ 15million.
o Recommendation : The cost recovery of US$ 77.36 million may bedisallowed
32
Additional expenditure on hiring of rig
The Operator did not consider long-term hiring ofdrilling rigs and availing the firm rate advantage of long-term hiring
Despite having adequate drilling prospects and themarket having scarcity of deep-water drilling rigs
This resulted in additional expenditure of approximatelyUS$ 88.77 million
33
Unjustified compensation
The Operator awarded four contracts relating to constructionof Onshore Terminal (OT) on cost-plus basis,
Payment of compensation was to be made to the vendorsonly on the ‘cost’ incurred by vendor plus a mark-up on suchcosts,
The Operator, however, also paid the vendor Rs.1110.90million as mark-up compensation on the value of ‘free-issuematerial’ such as cement, steel, etc supplied by the Operator.
Recommendation: The cost recovery of amount of INR 1110.90 million may be disallowed.
34
Case Study As a part of its Redevelopment Plan, M/s Sea Oil Company invited international competitive bids (ICB) in September 2002 for installation of platforms and laying of pipeline segments in its Offshore Field. The likely date of issue of Notification of Award (NOA) was 31 January 2003 with the completion of the project scheduled by 30 April 2004. Offers from ten bidders were received.
Technical bids were opened on 3 January 2003 after one month of the scheduled date.
Only two bidders viz., M/s Aqua and M/s Beta were found technically qualified. Tender Committee (TC) revised the date of NOA to 14 March 2003 and recommended (January 2003) opening of price bids of M/s Aqua and M/s Beta. The bidders were asked to confirm unconditional compliance with the original project completion schedule i.e. 30 April 2004, despite revision in the date of NOA. As M/s Aqua did not agree, its offer was rejected. M/s Beta confirmed (4 March 2003) compliance with the project completion schedule with revised NOA with a request for a grace period of 15 days before levy of liquidated damages (LD).
On evaluation, TC recommended (13 March 2003) the award of work to M/s Beta with grace period of 15 days. In view of likely delay in the award of contract, the Apex Purchase Committee (APC) of M/s Sea Oil Company asked (31 March 2003) M/s Beta to re-confirm project completion schedule of 30 April 2004 with NOA by 15 April 2003 along with the negotiations for price reduction. During negotiations M/s Beta did not offer any price reduction but confirmed (3 and 4 April 2003) compliance with the completion schedule subject to issue of NOA by 7 April 2003 with grace period of 15 days. TC recommended (4 April 2003) placing of order on M/s Beta for $100 million stating that re-tendering would delay the project by one year and would involve loss of oil production of 0.13 MMT1.
The APC, however, approved the award of contract to M/s Beta on 9 April 2003 without grace period. Accordingly, M/s Beta was asked (9 April 2003) by the TC to confirm unconditional compliance with the original completion schedule without grace period. As this was not in conformity with their offer, M/s Beta refused the offer. Subsequently the offer (12 April 2003) by the TC with a grace period of 15 days was also rejected by M/s Beta.
M/s Sea Oil Company re-invited (May 2003) fresh tenders and awarded Contract (January 2004) to M/s Beta at a price of $147 million for installation of the same facilities viz., platforms, laying of pipelines in Offshore Field. Questions 1. How do you assess approach of M/s Beta in the above case?
2. Your comments on issue of NOA by M/s Sea Oil Company on 09 April 2009.
1 Million Metric Tonne
3. In your opinion, what were the financial implications for M/s Sea Oil Company in the above case?
4. Do you think APC was right in its wisdom in non-allowing the grace period of 15 days to the bidder for completion of the said contract?
5. Do you have any suggestions for M/s Sea Oil Company as a way forward in such cases in future?
Session 4 –Audit Evidence in Financial Audit
Pag
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Objective: Detail the Audit Evidence and the type of evidence for sustaining the objections.
Estimated time required:
Discussion in sub-group: 15 minutes
Discussion in plenary: 15 minutes
Instructions: Read the described scenario carefully and discuss your response to the six
objections posted at the end of the scenario. Try to arrive at a consensus at your table and
detail the evidences you may have to produce for sustaining the objections. Also specify the
type of audit evidence.
Background:
The Ministry of Housing and Urban Poverty Alleviation, with a view to provide affordable housing to all,
started a project Viz: Integrated Housing and Slum Development (project IHSD) at a total estimate of Rs.
25 crore. The project which started in May 2006 is still under progress.
During the course of the audit of financial year 2010-11 following audit conclusions were derived:
1. As part of the project plan, a sub-way was to be built in one of the slum area. For this
purpose, an expenditure of Rs. 31.86 lakh was incurred. The components of the above
expenditure include equipment costing Rs.9.83 lakh imported and stored at the Customs
bonded warehouse and other related expenditure of 22.03 lakh. The title to the equipment
has already been relinquished by the Company (4/2009) and the work has also been
abandoned due to other administrative reasons. Hence the cost of the asset and the
expenditure has to be written off. This has not been done which resulted in over statement
of miscellaneous expenditure and profit to that extent.
2. For the above project ADB has sanctioned a loan amount of Rs.12.90 crore. On verification
of the Balance Sheet, it was found that unsecured loans do not include interest amounting
to Rs. 1.15 crore payable on the project loan of Rs. 12.90 crore for the period from 1.04.10
to 28.03.11. Non – provision has resulted in understatement of unsecured loans and
overstatement of profit to that extent.
3. The Development Reserve Fund includes a sum of Rs.4.22 lakh being the maintenance
expenses, which are of revenue nature (such as electricity charges) etc and to be charged to
Profit and Loss account under “Prior period expenses”. Consequently, profit is overstated
to the same extent.
4. For the purpose of development of housing, the Company has acquired land from owners
by paying the cost of the land at guideline value. However, the private land owners did not
accept the rate offered by the Company and have approached the court and won the case.
As per the Accounts the Free hold land is shown at Rs. 6430328/-
This does not include a sum of Rs. 54,88,756 being the difference in land cost between cost
already accounted for and higher rate of compensation payable along with interest as per
Session 4 –Audit Evidence in Financial Audit
Pag
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the Government Order. This has resulted in understatement of current liabilities and fixed
assets to that extent.
5. Capital Work in progress Rs. 36.50 lakh : This represents expenditure incurred on
construction of bore well during 2007-08 which has been abandoned due to dry well. Since
the company has not made use of this, it should have been written off. Non writing off has
resulted in overstatement of Capital Work in Progress and over statement of profit to that
extent.
6. Gross Block – Rs.2,39,65,454/-
a) This does not include Rs. 19,06,695/- being the value of work completed during the
year at stage 1 of the project. This resulted in understatement of Fixed Assets.
Further depreciation and loss for the year is also understated by Rs. 59,523 while
Capital WIP stands overstated to the same extent.
b) The establishment cost of the officers in construction wing of the company had not
been apportioned to the respective capital works completed. The fact has also not
been suitably disclosed.
