Reality Views

Read Complete CAG Draft Report on Coal – Coal Scam 10.67 Lakh Crore

TOI reported that
The CAG-estimated loss figure of Rs 10.67 lakh crore at March 31, 2011 prices is six times that of its highest presumptive loss figure of Rs 1.76 lakh crore for the 2G scam. This, it says, is actually a conservative estimate, since it takes into account prices for the lowest grade of coal, not the median grade. CAG says even by the price levels prevailing at the time of allocations, the estimate of loss would be over Rs 6.31 lakh crore.

Now read the complete CAG draft report on Coal

Draft CAG Report

Reality views by sm –

Saturday, March 24, 2012

Tags – Coal Scam CAG draft Coal Allocation block report draft

09 September 2011

Last Part Complete CAG Report – Reliance, Cairn Energy Petroleum and Natural Gas for a special audit of PSC

Last Part Complete CAG Report – Reliance, Cairn Energy Petroleum and Natural Gas for a special audit of PSC

Conclusions and General Recommendations –

Private sector participation in hydrocarbon exploration and production in India is now
robustly established, with major crude oil and natural gas discoveries in different basins
nutting India firmly on the global FM) man The Prnthirtinn Sharing Cnntrart IPSC1 — the basis of the contract between the Gol and the (private) contractors — has undergone several mutations from those in respect of discovered fields to "pre-NELP" exploration blocks to the blocks under different rounds of the New Exploration Licensing Policy (NELP). However, our audit indicated that there is considerable scope for improvement in the management of hydrocarbon E&P with private sector participation in the light of experience gained by governmental agencies over the years.

Structure of PSC

The PSC, as it currently stands, is based on a scaled formula for profit sharing between the Gol and the private contractors. This is based on a critical parameter — Investment Multiple (IM) — which is essentially an index of the capital-intensive nature of the E&P project i.e. the amount of "capex" on exploration and development activities relative to income. The slabs for profit sharing are so designed that more the capital intensive the project (i.e. lower IM), the lower the Gol share of "profit petroleum" (which could be as low as 5 to 10 per cent). Contrarily, the higher the IM (i.e less capital intensive vis-a-vis income), the higher the Gol share of "profit petroleum" (which could be as high as 85 per cent).

In practice, however, the private contractors seem to have inadequate incentives to reduce
capital expenditure and substantial incentive to increase capital expenditure or "front-end" capital expenditure, so as to retain the IM in the lower slabs or to delay movement to the higher slabs.

The structure of the IM-based profit sharing formula (especially when there is a huge jump in Gol's profit share from 28 per cent to 85 per cent on an IM slab of 2.5 or more) is such that in certain scenarios, an increase in capital expenditure, upto a point, could conceivably result in an increase in the contractor's share of profit petroleum, despite a reduction in the total profit petroleum as well as Gol's share of profit petroleum. Further, "front-ending" of capital expenditure (i.e. skewed towards the initial phases) decreases the IM, and postpones the movement to higher IM slabs; this results in a reduction in Gol share on a discounted cash flow basis, since the slabs involving higher Gol share come later, rather than earlier. Operational control of E&P operations is largely with the private operators, and the Gol's oversight role is restricted essentially to its representation (through MoPNG and/ or DGH) in the Management Committee for the block, especially in approval of Annual Work Programmes and Budgets and Field Development Plans, as well as a few approval functions delineated in the PSC.

Ashok Chawla Committee Report

We are given to understand that the report of the Ashok Chawla Committee on allocation of natural resources also draws similar conclusions regarding the IM-based profit-sharing
formula. This committee had, inter alia, representatives from MoPNG and the Ministry of
Finance, so it can safely be presumed that its conclusions were well considered. However, the report is not currently available in the public domain.

According to media reports, the Committee has stated that the system "gives incentive (to
an operator) to increase his investment, or front-end his work plan in order to see that the
threshold where Government's profit take rises rapidly is not reached".

Citing the example of KG-DWN-98/3, the Committee has stated that "the relationship
between the pre-tax IM and the share of contractor profit petroleum changes dramatically
once the pre-tax IM crosses 2.5, with the government's share increasing from 28 per cent
to 85 per cent. It is useful to remember that this schedule is bid by the operator, and not
determined by the Government."

Further, according to the Committee, "a high share of some pre-tax IM will help to win the bid, depending on the financial mode of evaluation used, but it does raise concerns that such a radical change would provide very strong incentives for any operator to adopt all investment and strategies possible to ensure that the pre-tax IM stays within the 2.5
limit".

The report clearly points out the risks associated with the IM-based formula for sharing of profit petroleum, especially with a steep jump in profit sharing from one slab to another.

In our view, even the linearity introduced in the sliding scale for IM slabs from NELP-VII onwards does not fully address these risks.

The oversight/ control of Gol representatives on high value procurement decisions is also
very limited in scope (largely restricted to prior intimation of the list of pre-qualified
bidders). In fact, a comparison of the procurement procedure under PSCs in Bangladesh and India reveals that the clauses are similar, except that the Bangladesh PSCs require approval by the Management Committee for high value procurements (typically greater than US$ 500,000). This clause is, however, missing from the Indian PSCs in almost all its versions.

Our audit review also revealed that, by and large, the DGH and the Ministry through the
Management Committee were ill equipped to pay adequate attentiion to protecting - at
every stage of E&P, be it exploration, development or production - Gol's financial interests.

Adequate attention was not paid as to how every proposal/ decision would potentially
affect Gol's share of profit petroleum. In addition to their other inadequacies, the
constraints of adequately skilled resources with MoPNG/ DGH for monitoring several
hundred PSCs simultaneously cannot also be ignored. By contrast, it is inconceivable that
the private contractor would fail to protect his financial interests, and assess ever
investment/ operational proposal to see whether it would result in incremental revenues for it both in terms of cost recovery and contractor's share of profit petroleum.
Given the similar conclusions that two independent agencies viz. the Chawla Committee
and Audit have reached as regards the adverse impact of the profit sharing mechanism in
protecting Gol's share (linked to the IM), designed in the late 1990s, there does seem to be enough ground to revisit the formula. The PSC as drawn up then, was with the limited
expertise available with the Gol at that point of time. In view of the fact that, we have
now gained the knowledge , there is need to conclusively address this issue in respect of
future PSCs

MoPNG stated (July 2011) that they were prepared to look at alternative formulas with an
open mind and would consider the suggestion of the CAG and the Ashok Chawla Committee with an open mind and take a final view on merits.

Recommendations for Future PSCs

The stated strength of the profit sharing mechanism is the sharing of risks between the
contractor and the Government — if the profits are low or non-existent, both parties suffer equally.

For future PSCs, we recommend that the IM-linkage with the profit sharing formula (even with the linear sliding scale introduced from NELP-VII onwards) be removed by the Gol.

Instead, the biddable profit-sharing percentage should be a single percentage. This will
reduce the incentive for skewed volume and timing of capital expenditure resulting in very low Gol share of PP. Further, in order to ensure a modicum of control, very high value procurement decisions above a specified limit should be subject to approval by the MC, more specifically the approval of the Gol representatives. Such a mechanism already exists in PSCs operating in Bangladesh.

Bid Evaluation Criteria
The bid evaluation criteria currently give weightage to technical/ financial ability and two
biddable parameters - committed exploratory work and fiscal package (royalty + Gol share
of profit petroleum). As regards fiscal package, the current evaluation model generally
involves multiple scenarios of oil reserves and oil prices (typically high, medium and low) as
well as a projected profile.
The assumptions based on which calculations of fiscal packages of different bidders are
made are completely hypothetical. In the absence of high quality seismic data, let alone
drilling and discovery findings, estimates of oil/ gas reserves and production profiles, as also
projected capital and operating expenses and even crude oil and natural gas prices, is
completely speculative. Admittedly, the evaluation model is applied consistently across all bidders. However, when the current system allows multiple bidding points (viz. different Gol

Consequently, we recommend that the bidders should be allowed to only make a single
point bid, which can be compared straightaway without resorting to hypothetical
assumptions.

As regards the biddable exploratory work programme, we are generally in agreement with the bid evaluation process, except for the system of awarding points for well depth. As pointed out in Chapter 4 (relating to KG-DWN-98/3), it is unrealistic and impractical, without having accurate and reliable seismic data, to bid upfront how deep the well should be drilled, and then expect that, notwithstanding geological objectives, the well will be drilled to the committed depth even if it means a waste of money.

Consequently, in future, while considering the bid evaluation criteria, we recommend that
either no weightage be allocated for well depth, or alternatively, well depth commitments
be categorised into two groups — wells above and below a specified depth, e.g., 1500 or
2000 metres and points be awarded accordingly.

Management of existing PSCs

The vast majority of blocks with high prospects for hydrocarbon discovery have already
been awarded through various pre-NELP/ NELP rounds, and Gol has no option but to work within the constraints of the existing PSC structure and clauses to the fullest extent possible.

Development Plans and Annual Work Programmes and Budgets
It is inconceivable that a private operator/ contractor will make investments in absolute as
well as incremental terms, in petroleum operations under the PSC without assessing
whether such investments would result in increased revenues for him in terms of cost
recovery and contractor's share of profit petroleum. It is necessary for MoPNG and DGH to function in a similar manner, with regard to Gol's financial interests. Consequently we
recommend the following:

• Review and approval of development plans should be considered not just from a
"technical perspective" viz. how best can oil and gas be extracted from the reservoirs,
but also from a financial perspective — not only overall (i.e. what is the project NPV, Rate of Return etc.), but specifically from Gol's point of view viz. what are the projections of royalty and Gol share of profit petroleum? What are the risks to these revenues? How will increases/ decreases in capital expenditure, reserves, reservoir productivity, prices etc. affect Gol's financial take?

• While reviewing and approving development plans, Gol representatives on the MC as
well as DGH and MoPNG should ensure that detailed and appropriately validated
estimates of Gol take and contractor take are included as an integral part of these plans

at the approval stage. A suitable range for Gol take, say ± 15, 20 or 25 per cent, as
considered appropriate by MoPNG, could be stipulated.

• Approval by MoPNG of such development plans should be on the clear stipulation that
any changes in capital and operating expenditure, expenditure commitments,
production quantities and other tactors, which have the impact of reducing the
Investment Multiple and Gol share of profit petroleum beyond the stipulated range
must be submitted for prior approval by Gol representatives on the MC, with detailed
justification.

• Annual Work Programmes and Budgets should be strictly in line with the approved
development plans. Any deviations or changes vis-à-vis the development plan which
have the impact of reducing the IM and Gol share of profit petroleum beyond the
stipulated range must be submitted for prior approval of the MC. Similarly, any
significant variations from the approved Work Programme and Budgets with similar
impact beyond the stipulated range must also be subject to prior approval.

• Incurring of any costs which vary from the Development Plans and Annual Work
Programmes & Budgets on an overall basis, as well as in terms of significant line items
with significant adverse impact on IM and Gol share of profit petroleum — beyond the
stipulated range - without prior approval of Gol representatives on MC should
automatically be ineligible for cost recovery.

While some of these recommendations could be misconstrued as hampering operational
flexibility in petroleum operations by the contractor, the importance of the overall
objective of protecting Gol's revenue interests cannot be ignored under any circumstances.

Procurement Activities

The provisions relating to procurement procedures in the PSCs do not provide for adequate oversight / control by Gol representatives on procurement processes. However, given the existing provisions, we recommend the following measures for protecting Gol's financial interest.

• The objective of effective procurement is to ensure optimum, not necessarily lowest,
prices through effective competition. As long as adequate number of 'responsive'
financial bids, typically three or more, from reputed vendors, who are pre-qualified after
following due process, are received and duly considered (i.e., not withdrawn,
disqualified on technical or other grounds, deviations/ non-responsiveness or otherwise
not considered), generate adequate competitive tension, the probability of effective
procurement at optimum costs remains high.

• However, when high value contracts are awarded on the basis of single 'responsive'
financial bids, in our opinion, these are awarded without competition, effectively on
nomination basis. In all such cases, prior approval of the MC should be necessary for
such awards. Post facto approval, with appropriate justification, for emergent
procurement decisions may also be considered. Similar provisions would also apply to all
procurement decisions involving post-priced bid opening changes to scope, quantities,
work, prices, conditions etc.

• Also, the practice of repeated extensions, subsequent substantial variations in scope etc.
of existing contracts is also not in line with the existing PSC procurement provisions,
which incidentally makes no mention of extensions. Extensions or scope variations for
high value contracts, beyond the contractually stipulated extensions, should also be
subject to prior MC approval, with provisions for post facto approval in emergent cases.

Relinquishment of area, and delineation of discovery and development
areas As pointed out in earlier chapters, the entire PSC process is designed to ensure that the private contractors fully explore the contract area within designated timelines, relinquish areas where hydrocarbon prospects appear poor in a phased manner, and retain only those areas where hydrocarbon discoveries are made, relinquishing the remaining area for re-allocation - through a competitive bidding process - to other potential bidders, whose hopes/ views in terms of hydrocarbon prospectivity differ (either on account of technical and other capabilities or in terms of their risk appetite) from the contract holders who have relinquished such area. We, therefore, recommend the following:

The stipulated timelines and processes in the PSC for relinquishment of contract area
should, under no circumstances, be relaxed, and compliance with these provisions should
be invariably ensured.

Further, the discovery and development areas should be rigorously delineated, keeping
strictly to the discoveries made through exploratory and appraisal well drilling and proper
delineation of reservoir boundaries. Attempts by contractors for delineation of excessively wide discovery/ development areas through elastic (and incorrect) interpretation of hydrocarbon discovery should be strongly rebutted.

Compliance with other PSC provisions

The PSC is a contractual document, and compliance with every contractual clause is of
utmost importance. It would be inappropriate to distinguish between "major" and "minor"
clauses, and neglect monitoring of compliance with so-called "minor" PSC clauses.
We recommend that DGH, and where necessary, MoPNG should put into place adequate
and effective measures to ensure that compliance with all provisions of the PSC are fully
monitored on a timely basis and appropriately documented, and action taken against
operators on a timely and consistent basis, for non-compliance with PSC provisions. For such purposes, strengthening of the resource basis of DGH in terms of adequate quantity of skilled resources may be necessary.

I did not cover chapter 3 to chapter 7
Chapter –III - Audit Approach
Chapter –IV - Findings relating to - KG-DWN-98/3 block
Chapter -V Findings relating to RJ-ON-90/1 block
Chapter -VI Findings in respect of Panna-Mukta and Mid & South Tapti Fields
Chapter -VII Compliance and Control Issues

Reality views by sm –
Friday, September 09, 2011

Tags- Complete CAG Report Reliance RIL KG BASIN 6 CAIRN ENERGY

Part 3 Complete CAG Report – Reliance, Cairn Energy Petroleum and Natural Gas for a special audit of PSC

Part 3 Complete CAG Report – Reliance, Cairn Energy Petroleum and Natural Gas for a special audit of PSC

Petroleum Exploration and Production (E&P) –

Petroleum covers hydrocarbons in liquid form (viz. crude oil) as well as in gaseous form (viz. natural gas). While hydrocarbon fields primarily contain either crude oil or natural gas, they also include associated natural gas (natural gas produced in association with crude oil), as well as condensate (liquid hydrocarbons segregated from natural gas).
Petroleum Exploration and Production (E&P) operations, also referred to as upstream
operations1, can be broadly grouped into three categories
1. Exploration Operations
2. Development Operations
3. Production Operations

The first phase in the process for extraction of petroleum is exploration — the search for oil and gas deposits beneath the earth's surface. Such deposits could either be onshore or
Offshore. Exploration consists of several sub-phases:

Downstream operations include refining of crude oil, and marketing of petroleum and gas products. Midstream operations (which are often included under downstream operations) include storage, transportation and related operations.

Areas thought to contain hydrocarbons are subjected to aerial, geological, geochemical, topographical and other surveys to detect large scale features of sub-surface geology.

After narrowing down the list of potential areas, detailed seismic surveys are carried out to identify formations with high probability of being petroleum reservoirs. These work on the principle of the time it takes for reflected sound waves to travel through matter (rock) of varying densities and using the process of depth conversion to create a profile of the substructure.

• Typically, the seismic survey involves Acquisition of seismic data, computer-based Processing of the data (including reprocessing of existing data), and its Interpretation by geologists to identify formations with high probability of being reservoirs (the API process).

There are different types of seismic surveys—
two dimensional (2D), three dimensional (3D) standard/ high resolution, 4D/ 4C
etc

When a prospect has been identified and evaluated, and passes the oil
companies selection criteria, an exploration well is drilled to conclusively
determine the presence or absence of oil or gas.

• The well could turn out to be "dry". Alternatively, hydrocarbons (oil and/or gas)
could be "discovered", and a discovery area is delineated.

Once a 'discovery' is made and is considered to be of potential commercial
importance, 'appraisal' wells are drilled around the discovery in order to
determine the contours of the reservoir (in terms of thickness and lateral
extent) and its characteristics, and come up with a relatively accurate estimate
of the recoverable oil /gas reserves.

Once a 'discovery' is made and is considered to be of potential commercial
importance, 'appraisal' wells are drilled around the discovery in order to
determine the contours of the reservoir (in terms of thickness and lateral
extent) and its characteristics, and come up with a relatively accurate estimate
of the recoverable oil /gas reserves.

Development Operations

The next phase in the extraction of potential is the development of field, where a
commercial discovery of hydrocarbons has been made. This will first involve the drawing up of a field development plan to ensure the most efficient, beneficial and timely extraction of petroleum, keeping in view engineering, economic, satety and environmental considerations.

Development will then include the following aspects, among others:

• Drilling of production wells (for producing crude oil and gas);

• Drilling of injection wells (for injecting water or gas, in order to sustain or accelerate the production of hydrocarbons);

• Installation of offshore platforms and installations, for handling offshore production of
oil and gas; and

• Laying of gathering lines, and installation of separators, tankages, pumps, artificial lift
facilities, which are required to produce, process, store, and transport petroleum.

Production Operations

Production operations involve operations after the commencement of production from a
developed field. This would typically involve, among others:

• operation and maintenance of existing facilities;
• workovers;
• plugging and abandonment of wells;
• improved oil recovery; and
• site restoration (after cessation of petroleum operations) etc.

Private Sector Participation in Petroleum E&P in India

Efforts to involve foreign and domestic private sector companies in the business of
Exploration and Production (E&P) of oil and gas in India began as early as 1973, followed by three rounds of bidding between 1980 and 1986, which did not yield any concrete results.

In 1991, the Government of India decided to invite foreign and domestic private sector
companies to participate in the development of discovered oil and gas fields, and in some
cases, fields partially developed by the National Oil Companies (NOCs) — Oil and Natural Gas Corporation Limited (ONGC) and Oil India Limited (OIL). In 1993, the Government introduced a policy of round-the-year bidding for exploratory blocks. In all, a total of nine rounds were held:

• One round for medium-sized discovered/ producing fields (1992);

Two rounds for small-sized discovered fields (1991 and 1993); and

• Six rounds for pre-NELP exploratory blocks (1993 to 1995)

New Exploration Licensing Policy (NELP)

In 1997, the Government announced the New Exploration Licensing Policy (NELP), under which NOCs would compete with Private Sector Companies for obtaining E&P licenses through a bidding process, instead of getting them on nomination basis. The main features of NELP, which was notified in 1999, are summarised below:

The NOCs were required to compete with the private sector for
obtaining Petroleum Exploration Licenses, instead of getting them on
nomination basis. There was no mandatory State participation through
the NOCs, nor any "carried interest of the State.

No special privileges for National Oil Companies (NOCs)

There would be open availability of exploration acreages, to be demarcated on a grid system, to provide a continuous window of opportunities to all companies

Open availability of exploration area

Government's share would be based on pre-tax sharing of profit petroleum based on investment multiple achieved. Contractors would be allowed full cost recovery.

Contractors were free to market the crude oil and gas in the domestic market.

Royalty rates were fixed at 12.5 per cent of the wellhead value of
crude oil in onshore areas and 10 per cent for offshore areas, while the rate was fixed at 10 per cent for natural gas. In addition, to encourage exploration in deep water and frontier areas, royalty was reduced by 50 per cent for offshore deep water areas for the first 7 years after commencement of commercial production.

Further, there would be no payment of signature, discovery or production bonuses, nor would any cess be levied on crude production.

There would be a seven year tax holiday after commencement of commercial production, and exemption from import duty for goods imported for petroleum operations.

An Empowered Committee of Secretaries, consisting of Secretary, MoPNG, Finance Secretary and Law Secretary would consider bid evaluation criteria, conduct negotiations with the bidders, wherever necessary, and make recommendations to the Cabinet Committee on Economic Affairs (CCEA) on award of blocks.

The Oilfields (Regulation and Development) Act, 1948 provides for regulation of oilfields and development of mineral oil — petroleum and natural gas — resources. The Petroleum and Natural Gas Rules, 1959 (PNG Rules), which are drawn up under Sections 5 and 6 of the Oilfields (Regulation and Development) Act, regulate the grant of exploration licenses and mining leases in respect of petroleum and natural gas. Under these Rules, Gol has the power to grant exploration licenses/ mining leases for offshore areas, while the State Governments are empowered to do so for onland areas.

Rule 5(2) of the PNG Rules specifically empower the Gol to include "additional terms,
covenants and conditions as may be provided in the agreement between the Central
Government and the licensee or the lessee", after consulting the State Governments (where onland areas are involved). The Production Sharing Contracts (PSCs) between the Gol and the contractor (s) are signed under the provisions of this rule.

Organisational Structure

The Ministry of Petroleum and Natural Gas (MoPNG) is inter alia responsible for the
exploration and production of petroleum and natural gas, including the administration of
the Oilfields (Regulation and Development) Act, 1948. MoPNG is assisted by the Directorate General of Hydrocarbons (DGH), which was established in April 1993 with the objective of promoting sound management of Indian petroleum and natural gas resources having a balanced regard for the environment, safety, technological and economic aspects of petroleum activities.

Award of Production Sharing Contracts (pre-NELP/ NELP)

The position of PSCs awarded/ signed under different fiscal regimes was as follows:

• Discovered/ Producing fields rounds— 29;
• Pre-NELP Exploration Rounds — 28; and
• NELP Rounds (I to VIII) — 235

The process of award of contracts under the NELP rounds is broadly as follows:
Under 9th NELP round (launched in October 2010), Government of India has offered 34 exploratory blocks (19 onland, 8 deep water and 7 shallow water). The NELP Round, for which submission of bids closed on 28 March 2011, attracted a total of 74 bids for 33 out of the 34 blocks on offer.

Preparation of data packageb and basin information docket',

• Road shows for publicizing the NELP round;

• Publishing of bid document (which includes the Notice Inviting Offer (N10), the bid
format, the Model Production Sharing Contract (MPSC), the petroleum tax guide, the
Site Restoration Fund scheme, and price list for information docket, data package etc.);

• Purchase of bid document and data package/ basin information docket by contractors;

• Submission of bids, evaluation thereof, and award of blocks; and

• Signing of Production Sharing Contracts (PSCs).

Evaluation of bids is carried out, on weightages based on technical and financial capability, proposed exploratory work programme, and the fiscal package offered

Data package contains seismic data, navigation data, relevant maps and well log data for the individual block.

• Basin information docket is for the basin as a whole, and less detailed than the data package. It contains information on regional and local geology, status of exploration activities, hydrocarbon potential and a brief write-up on the blocks.

Contractor's share of Profit Petroleum at various levels of pre-tax
multiples of investment reached.

• (Royalty receivable is also considered for calculation of Government
NPV)

The qualifying criteria included non-zero score under technical capability8; confirmation to Minimum Work Programme Commitment; and Certificate from a Chartered Accountant that net worth was equal to or more than the MWP for Exploration Phase I.
As regards the fiscal package, nine scenarios were envisaged with low, medium and high
reserve sizes and oil/ gas prices. The ratio of Government NPV (Net Present Value) to
Project NPV was calculated, using a discount rate of 10 per cent, in each of the nine
scenarios, and a weighted average was calculated to arrive at the final value offered by the bidder. The bidder offering the highest Government NPV was given the maximum points, with other bidders receiving proportionate points.

As can be seen, substantial weightage is given to exploration work as part of the bidding
criteria, so as to incentivise an aggressive exploration programme with better prospects
for discovery of new national oil and gas resources.
The exploration programme, which includes both seismic surveys as well as drilling of
exploration wells, is to be carried out in a phased manner within clearly defined
timeframes and similarly phased relinquishment of portions of the contract area. At the
end of the exploration period, the entire area (except for areas where oil and gas has been
discovered, or is being developed) is to be returned to the Government, which can then
re-offer it through a bidding process to other parties. Evidently, the idea is to prevent
hoarding/ accumulation of exploration acreage.

Suggested Reading –
Complete CAG Report – Reliance Petroleum and Natural Gas for a special audit of PSC Part One
http://realityviews.blogspot.com/2011/09/complete-cag-report-reliance-petroleum.html

P- 2 Complete CAG Report – Reliance, Cairn Energy Petroleum and Natural Gas for a special audit of PSC
http://realityviews.blogspot.com/2011/09/p-2-complete-cag-report-reliance-cairn.html

Reality views by sm –
Friday, September 09, 2011

Tags- Complete CAG Report Reliance RIL KG BASIN 6 CAIRN ENERGY

P- 2 Complete CAG Report – Reliance, Cairn Energy Petroleum and Natural Gas for a special audit of PSC

P- 2 Complete CAG Report – Reliance, Cairn Energy Petroleum and Natural Gas for a special audit of PSC

RJ-ON-90/1 block (Operator: Cairn Energy)

This onland block (mainly in Rajasthan) was awarded in 1995 under the pre-HELP exploratory rounds, and is currently operated by Cairn Energy. It now has India's largest onland oil discoveries, and also has significant gas discoveries. The high "pour point" of the crude oil has necessitated a 660 km oil pipeline with insulation and heating facilities to the Gujarat coast. Our main findings and recommendations with regard to the RJ-ON-90/1 block are as follows:

• 13 fresh discoveries were made during/ between the appraisal phase and in the
development phase in areas already delineated as development areas. Consequently, in
our opinion, the declaration of fresh discoveries during the appraisal/development phases
within delineated discovery/development areas amounted to irregular extension of
exploration activities, which is not in consonance with the terms of the PSC. This also
indicates that the discovery/development areas were not strictly delineated, and included
excess area.

There were instances of non-compliance with regard to the PSC provisions for notification of potential commercial interest, appraisal programme, submission of Field Development Plans etc.

Panna-Mukta and Mid & South Tapti Fields

The Panna-Mukta and Mid & South Tapti fields are offshore shallow water fields in the offshore Bombay basin, which were initially discovered and operated by ONGC. Subsequently, these were awarded in 1994 to a consortium of private operators under a IV arrangement with ONGC.

As already pointed out, our scrutiny of records of the PMT JV and findings arising thereon are incomplete, due to non-production of records. Based on the limited records made available to us, our main findings are as follows:

Gol incurred a substantial loss (on account of royalty) by failing to finalise the norms for
post-well head costs of gas, and consequentially, gas wellhead prices. Even the norms for
post well-head costs notified in August 2007 had significant deficiencies.

MoPNG has accepted all our detailed findings relating to calculation of wellhead value of
natural gas, and has agreed to take necessary action thereon.

MoPNG and its nominee for gas purchase (GAIL) failed to comply with the terms of the PSC during 2005-08 with regard to the pre-determined gas pricing formula. Not honouring the PSC formula severely affertc the sanctity of the contract !which is to he maintained by all parties), which is highly undesirable from the long-term perspective of all contracting parties.

The PMTJV had not completed key work commitments in respect of the Mukta Field, which remained undeveloped (with very low volumes of oil and gas production). The committed work programme in respect of the Mid & South Tapti fields was also incomplete.

Compliance and Control Issues

We also found numerous deficiencies in compliance and control vis-a-vis the PSC provisions by MoPNG/ DGH, notably with regard to:

• Irregular declaration of entire contract area of KG-OSN-2001/2 as discovery area;

• Non-compliance to PSC provisions regarding notification of discovery and submission of test reports;

• Delay in submission/ review of appraisal programme;

• Numerous deficiencies in functioning of the Management Committees for individual
blocks; and

• Deficiencies in timely submission of stipulated periodical reports.

Conclusions and General Recommendations

Our audit indicated that there is considerable scope for improvement in the management of hydrocarbon E&P with private sector participation. Structure of PSC The PSC, as it currently stands, is based on a scaled formula for profit sharing between the Gol
and the private contractors. This is based on a critical parameter — Investment Multiple (IM) -which is essentially an index of the capital-intensive nature of the E&P project i.e. the amount of "capex" on exploration and development activities relative to income. The slabs for profit sharing are so designed that more the capital intensive the project (i.e. lower IM), the lower the Gol share of "profit petroleum" (which could be as low as 5 to 10 per cent). Contrarily, the higher the IM (i.e. less capital intensive vis-a-vis income), the higher the Gol share of "profit petroleum" (which could be as high as 85 percent).

In practice, however, the private contractors have inadequate incentives to reduce capital
expenditure - and substantial incentive to increase capital expenditure or "front-end" capital expenditure, so as to retain the IM in the lower slabs or to delay movement to the higher slabs.

The structure of the IM-based profit sharing formula (especially when there is a huge jump in Gol's profit share from 28 per cent to 85 per cent on an IM slab of 2.5 or more) is such that in certain scenarios, an increase in capital expenditure, upto a point, could conceivably result in an increase in the contractor's share of profit petroleum, despite a reduction in the total profit petroleum as well as Gol's share of profit petroleum. Further, "front-ending" of capital expenditure (i.e. skewed towards the initial phases) decreases the IM, and postpones the movement to higher IM slabs; this results in a reduction in Gol share on a discounted cash flow basis, since the slabs involving higher Gol share come later, rather than earlier.

Operational control of E&P operations is largely with the private operators, and the Gol's
oversight role is restricted essentially to its representation (through MoPNG and/ or DGH) in the Management Committee for the block, especially in approval of Annual Work Programmes and Budgets and Field Development Plans, as well as a few approval functions delineated in the PSC.

Ashok Chawla Committee Report

We are given to understand that the report of the Ashok Chawla Committee on allocation of natural resources also draws similar conclusions regarding the IM-based profit-sharing
formula. This committee had, inter alia, representatives from MoPNG and the Ministry of
Finance, so it can safely be presumed that its conclusions were well considered. However, the report is not currently available in the public domain.

According to media reports, the Committee has stated that the system "gives incentive (to an operator) to increase his investment, or front-end his work plan in order to see that the
threshold where Government's profit take rises rapidly is not reached". Citing the example of KG-DWN-98/3, the Committee has stated that "the relationship between the pre-tax IM and the share of contractor profit petroleum changes dramatically once the pre-tax IM crosses 2.5, with the government's share increasing from 28 per cent to 85 per cent.
It is useful to remember that this schedule is bid by the operator, and not determined by the Government." Further, according to the Committee, "a high share of some pre-tax IM will help to win the bid, depending on the financial mode of evaluation used, but it does raise concerns that such a radical change would provide very strong incentives for any operator to adopt all investment and strategies possible to ensure that the pre-tax IM stays within the 2.5 limit". The report clearly points out the risks associated with the IM-based formula for sharing of profit petroleum, especially with a steep jump in profit sharing from one slab to another. In our view, even the linearity introduced in the sliding scale for IM slabs from NELP-VII onwards does not fully address these risks.

The oversight/ control of Gol representatives on high value procurement decisions is also very limited in scope (largely restricted to prior intimation of the list of pre-qualified bidders). In fact, a comparison of the procurement procedure under PSCs in Bangladesh and India reveals that the clauses are similar, except that the Bangladesh PSCs require approval by the Management Committee for high value procurements (typically greater than US$ 500,000). This clause is, however, strangely missing from the Indian PSCs in almost all its versions.
Our audit review also revealed that, by and large, the MoPNG as also DGH, both through the Management Committee and otherwise, did not pay adequate attention to protecting - at every stage of E&P, be it exploration, development or production - Gol's financial interests.

Adequate attention was not paid to specifically how every proposal/ decision would potentially affect Gol's share of profit petroleum. In addition to their failings, the constraints of adequately skilled resources with MoPNG/ DGH for monitoring several hundred PSCs simultaneously cannot also be ignored. By contrast, it is inconceivable that the private contractor would fail to protect his financial interests, and assess every investment/ operational proposal to see whether it would result in incremental revenues for him both in terms of cost recovery and contractor's share of profit petroleum.

Given the similar conclusions that two independent agencies have reached as regards the
adverse impact of the profit sharing mechanism in protecting Gol's share (linked to the IM), designed in the late 1990s, there does seem to be enough ground to revisit the formula. The PSC as drawn up then, was with the limited expertise available with the Gol at that point of time. In view of the fact, albeit by hindsight, that we have gained the knowledge now, there is need to conclusively address this issue in respect of future PSCs.

Recommendations for Future PSCs

The stated strength of the profit sharing mechanism is the sharing of risks between the
contractor and the Government— if the profits are low or non-existent, both parties suffer.

For future PSCs, we recommend that the IM-linkage with the profit sharing formula (even with the linear sliding scale introduced from NELP-VII onwards) be removed by the Gol. Instead, the biddable profit-sharing percentage should be a single percentage. This will reduce the incentive for skewed volume and timing of capital expenditure resulting in very low Gol share of PP. Further, in order to ensure a modicum of control, very high value procurement decisions above a specified limit should be subject to approval by the MC, more specifically the approval of the Gol representatives. Such a mechanism already exists in PSCs operating in Bangladesh.

Bid Evaluation Criteria

The Bid Evaluation Criteria (BEC) currently give weightage to technical/financial ability and two biddable parameters - committed exploratory work and fiscal package (royalty + Gol share of profit petroleum). As regards fiscal package, the current evaluation model generally involves multiple scenarios of oil reserves and oil prices (typically high, medium and low) as well as a projected profile.

The assumptions based on which calculations of fiscal packages of different bidders are made are completely hypothetical. In the absence of high quality seismic data, let alone drilling and discovery findings, estimates of oil/ gas reserves and production profiles, as also projected capital and operating expenses and even crude oil and natural gas prices, are completely speculative. Admittedly, the evaluation model is applied consistently across all bidders.

However, when the current system allows multiple bidding points (viz. different Gol shares of PP for different IM slabs), these hypothetical assumptions can not only make a significant difference as to who comes out as the winning bidder, but can also convey extremely unrealistic assumptions about what Gol's share of PP will be (e.g. when will Gol's share of PP reach the highest IM slab?).

Consequently, we recommend that the bidders should be allowed to make only a single point bid, which can be compared straightaway without resorting to hypothetical assumptions.

As regards the biddable exploratory work programme, we are generally in agreement with the bid evaluation process, except for the system of awarding points for well depth. As pointed out in Chapter 4 (relating to KG-DWN-98/3), it is unrealistic and impractical, without having accurate and reliable seismic data, to bid upfront how deep the well should be drilled, and then expect that, notwithstanding geological objectives, the well will be drilled to the committed depth even if it means a waste of money.

Consequently, in future, while considering the bid evaluation criteria, we recommend that
either no weightage be allocated for well depth, or alternatively, well commitments be
categorised into two groups — wells above and below a specified depth, e.g., 1500 or 2000 metres, and points be awarded accordingly.

MoPNG stated (July 2011) that they are prepared to look at alternative formulas and would consider the suggestion of the CAG and the Ashok Chawla Committee with an open mind and take a final view on merits.

Management of existing PSCs

The vast majority of blocks with high prospects for hydrocarbon discovery have already been awarded through various pre-NELP/ NELP rounds, and Gol has no option but to work within the constraints of the existing PSC structure and clauses to the fullest extent possible.

Development Plans and Annual Work Programmes and Budgets

It is inconceivable that a private operator/contractor will make investments in absolute as well as incremental terms, in petroleum operations under the PSC without assessing whether such investments would result in increased revenues for him in terms of cost recovery and contractor's share of profit petroleum.

It is necessary for MoPNG and DGH to function in a similar manner, with regard to Gol's financial interests. Consequently we recommend the following:
• Review and approval of development plans should be considered not just from a "technical perspective" viz. how best can oil and gas be extracted from the reservoirs, but also from a financial perspective— not only overall (i.e. what is the project NPV, Rate of Return etc.), but specifically from Gol's point of view (what are the projections of royalty and Gol share of profit petroleum? What are the risks to these revenues? How will increases/ decreases in capital expenditure, reserves, reservoir productivity, prices etc. affect Gol's financial take?).

• While reviewing and approving development plans, Gol representatives on the MC as well as DGH and MoPNG should ensure that detailed and appropriately validated estimates of Gol take and contractor take are included as an integral part of these plans at the approval stage. A suitable range for Gol take, say 15, 20 or 25 per cent, as considered appropriate by MoPNG could be stipulated.

• Approval by MoPNG of such development plans should be on the clear stipulation that any changes in capital and operating expenditure, expenditure commitments, production
quantities and other factors, which have the impact of reducing the Investment Multiple
and Gol share of profit petroleum beyond the stipulated range must be submitted for prior
approval by Gol representatives on the MC, with detailed justification.

• Annual Work Programmes and Budgets should be strictly in line with the approved
development plans. Any deviations or changes vis-à-vis the development plan which have the impact of reducing the IM and Gol share of profit petroleum beyond the stipulated range must be submitted for prior approval of the MC. Similarly, any significant variations from the approved Work Programme and Budgets with similar impact beyond the stipulated range must also be subject to prior approval.

• Incurring of any costs which vary from the Development Plans and Annual Work
Programmes & Budgets on an overall basis, as well as in terms of significant line items with significant adverse impact on IM and Gol share of profit petroleum — beyond the stipulated range - without prior approval of Gol representatives on MC should automatically be ineligible for cost recovery.

While some of these recommendations could be misconstrued as hampering operational
flexibility in petroleum operations by the contractor, the importance of the overall
objective of protecting Gol's revenue interests cannot be ignored

Procurement Activities

The provisions relating to procurement procedures in the PSCs do not provide for adequate oversight / control by Gol representatives on procurement processes. However, given the existing provisions, we recommend the following measures for protecting Gol's financial interest:

The objective of effective procurement is to ensure optimum, not necessarily lowest, prices through effective competition. As long as adequate number of 'responsive' financial bids, typically three or more, from reputed vendors, who are pre-qualified after following due process, are received and duly considered (i.e., not withdrawn, disqualified on technical or other grounds, deviations/ non-responsiveness or otherwise not considered), generate adequate competitive tension, the probability of effective procurement at optimum costs remains high.

• However, when high value contracts are awarded on the basis of single 'responsive'
financial bids, in our opinion, these are awarded without competition, effectively on
nomination basis. In all such cases, prior approval of the MC should be necessary for such awards. Post facto approval, with appropriate justification, for emergent procurement decisions may also be considered. Similar provisions would also apply to all procurement decisions involving post-priced bid opening changes to scope, quantities, work, prices, conditions etc.

• Also, the practice of repeated extensions, subsequent substantial variations in scope etc. of existing contracts is also not in line with the existing PSC procurement provisions, which incidentally makes no mention of extensions. Extensions or scope variations for high value contracts, beyond the contractually stipulated extensions, should also be subject to prior MC approval, with provisions for post facto approval in emergent cases.

Relinquishment of area, and delineation of discovery and development areas
The entire PSC process is designed to ensure that the private contractors fully explore the
contract area within designated timelines, relinquish areas where hydrocarbon prospects
appear poor in a phased manner, and retain only those areas where hydrocarbon discoveries are made, relinquishing the remaining area for re-allocation — through a competitive bidding process - to other potential bidders, whose hopes/views in terms of hydrocarbon prospectivity differ (either on account of technical and other capabilities or in terms of their risk appetite) from the contract holders who have relinquished such area. We, therefore, recommend the following:

The stipulated timelines and processes in the PSC for relinquishment of contract area
should, under no circumstances, be relaxed, and compliance with these provisions should
be invariably ensured.

Further, the discovery and development areas should be rigorously delineated, keeping
strictly to the discoveries made through exploratory and appraisal well drilling and proper
delineation of reservoir boundaries. Attempts by contractors for delineation of excessively wide discovery/ development areas through elastic (and incorrect interpretation) of hydrocarbon discovery should be strongly rebutted.

Compliance with other PSC provisions
The PSC is a contractual document, and compliance with every contractual clause is of utmost
importance. It would be inappropriate to distinguish between "major" and "minor" clauses,
and neglect monitoring of compliance with so-called "minor" PSC clauses.
We recommend that DGH, and where necessary, MoPNG should put into place adequate and effective measures to ensure that rnmnlianre with all nrnvisinns of the PSC are fully mnnitnred on a timely basis and appropriately documented, and action taken against operators on a timely and consistent basis, for non-compliance with PSC provisions. For such purposes, strengthening of the resource basis of DGH in terms of adequate quantity of skilled resources may be necessary.

DGH should also consider developing a comprehensive PSC monitoring system, which will not only provide details of compliance with PSC provisions for any block/ contract at a glance, but will also enable operators to "file" returns/ documents/ information electronically through the web and/or e-mail. The cost of developing (and maintaining) such an IT system will be miniscule, compared to the total Gol Profit Petroleum revenues as well as the potential (although not exactly quantifiable) gains from more effective and timely monitoring of compliance.

Role of DGH

In our view, the roles and functions of DGH encompass two sets of functions with potential conflict of interest — an upstream regulatory function, and a function of rendering technical advice to Gol. While in 1993 (when DGH was set up), there was lack of adequate clarity on the role and position of regulators in various economic sectors, the need for clear autonomy of sectoral regulators (from the Executive) is now well recognised.

Consequently, we recommend that the functions currently discharged by the DGH be clearly demarcated. The technical advisory and related functions should be discharged by a body completely subordinate in all respects to MoPNG (either a cell/ attached office/ subordinate office within the MoPNG or a separate entity under MoPNG). Functions of a regulatory nature (review of hydrocarbon reserves and reservoir management, laying down of norms for declaration of discoveries, laying down safety and related norms and conducting safety inspections/ audits etc.) should be discharged by an autonomous body, with an arm's length relationship with Gol.

Suggested Reading –
Complete CAG Report – Reliance Petroleum and Natural Gas for a special audit of PSC Part One
http://realityviews.blogspot.com/2011/09/complete-cag-report-reliance-petroleum.html

Reality views by sm –
Friday, September 09, 2011

Tags- Complete CAG Report Reliance RIL KG BASIN 6

Complete CAG Report – Reliance Petroleum and Natural Gas for a special audit of PSC Part One

Complete CAG Report – Reliance Petroleum and Natural Gas for a special audit of PSC Part One

Complete CAG Report – Reliance Petroleum and Natural Gas for a special audit of PSC Part One

Government of India formulated the new exploration licensing policy that is NELP in 1997 and notified this policy in 1999.

In order to ensure balanced and effective partnerships with global E&P Companies, the Production Sharing Contracts (PSCs) between the Government and the private players were revised. These contracts were structured in such a fashion that the exploration risk viz. the cost incurred in searching for oil and natural gas, without certainty of discovery, was to be borne by the private contractors. The private contractors incur capital expenditure towards discoveries, irrespective of the fact whether oil or gas is discovered or not. It is only when hydrocarbons are discovered and assessed to be commercially viable, that the contractor has the first rights on the revenue streams accruing from sales of oil and gas till his costs are recovered.

The balance revenue, termed as "Profit Petroleum", is shared between the Government and the contractors, with the contractors generally getting a higher share in the initial stages since he has to recover contract costs.

The Government share of revenues becomes significant only when the production reaches substantial levels and the contractor has recovered his accumulated capital cost. Further, under NELP, Government companies and private players are treated at par.
The principle underlying the PSC model, under the NELP, as it currently stands, involves a scale for profit sharing between the Government of India and the contractor, based on a critical parameter—the Investment Multiple (IM).

This is essentially an index of the accumulated net cash flow to the contractor relative to the accumulated expenditure on exploration and development activities.

The objective underlying the PSC is that ideally the operator would attempt to maximize simultaneously both the government revenues and his own profit by minimizing contract costs for any level of production.

In order to ensure that the expenditure proposed to be incurred as well as actually incurred by the operator does not adversely affect the Government's revenue interests, the PSC contemplates the Management Committee (MC), chaired by a Gol representative, as responsible for approving field development plans as well as annual work programmes and budgets for development and production operations. However, operational control of E&P activities would vest with the Operating Committee, consisting of representatives of the contractors.

This audit was conducted in response to a request from the Ministry of Petroleum and Natural Gas for a special audit of PSCs in the context of large Government stake in the form of profit petroleum and concerns about the capital expenditure being incurred by some contractors in development of blocks awarded under NELP.
We scrutinized records of the Ministry of Petroleum and Natural Gas and the Directorate General of Hydrocarbons (DGH) in respect of a sample of 20 PSCs covering the period from 2003¬04 to 2007-08. In addition we also conducted supplementary scrutiny of records of operators of 4 blocks/ fields (KG-DWN-98/3, RJ-ON-90/1, Panna-Mukta and Mid & South Tapti), covering the two year period 2006-07 and 2007-08. Our audit was interrupted due to difficulties in obtaining access to the records of operators for supplementary scrutiny, which were later resolved with assistance and cooperation of Ministry of Petroleum and Natural Gas.

This report of the Comptroller & Auditor General of India for the year ended March 2011 containing the results of Performance Audit of Hydrocarbons Production Sharing Contracts has been prepared for submission to the President of India under Article 151 of the Constitution of India.

Private sector participation in hydrocarbon Exploration and Production (E&P) in India dates back to the Government of India (Gol) decision of 1991 to invite foreign and domestic private sector companies to participate in the development of oil and gas fields already discovered or partly developed by the National Oil Companies such as ONGC.

The basis for the contractual relationship between the Gol and the private contractors is the Production Sharing Contract (PSC). The PSC lays out the roles and responsibilities of all parties, stipulates the detailed procedures to be followed at different stages of exploration, development and production, and also indicates the fiscal regime (cost recovery, profit sharing etc.).

In November 2007, the Secretary, Ministry of Petroleum and Natural Gas (MoPNG) requested the CAG to conduct a special audit of PSCs for eight blocks for which regular audit had already been carried upto 2003-04/ 2004-05. MoPNG's request was made in the context of large stakes of the Government in the form of royalty and profit petroleum, and concerns voiced in some quarters about the capital expenditure being incurred by some contractors in the development projects awarded under NELP.

We agreed to the MoPNG's request for audit, indicating that we would be covering, in the first instance, five blocks — Panna-Mukta, Tapti, KG-DWN-98/3, Hazira, and PY-3 - out of the eight blocks for which special audit was requested by MoPNG.

We also subsumed a Performance Audit of Hydrocarbon PSCs, covering a sample of discovered/ pre-NELP Production Sharing Contracts and NELP PSCs.

The main objectives of the performance audit of hydrocarbon PSCs were to verify whether:
• The systems and procedures of MoPNG and Directorate General of Hydrocarbons (DGH) to monitor and ensure compliance by the operators and contractors of the blocks with the terms of the PSCs were adequate and effective; and

• The revenue interests of the Government (including royalty and Gol share of profit
netrnleum) were nrnneriv nrnterted and adenuate and effective mprhanicmc were in
position for this purpose.

Our audit scope covered a twin approach:
• Scrutiny of records at MoPNG and DGH in respect of a sample of 20 PSCs so selected as to provide a balanced coverage of (a) onshore and offshore (shallow and deepwater) blocks

(b) a cross section of operators (c) fields with oil discoveries and gas discoveries (d) pre-NELP and NELP and (e) blocks at different stages of E&P — under exploration, relinquished, discovery, production etc.; this covered the period
from 2003-04 to 2007-08.

• Supplementary scrutiny of records of operators of four blocks/ fields (KG-DWN-98/3,
Panna-Mukta, Mid & South Tapti and RJ-ON-90/1) covering the two year
period 2006-07 and 2007-08.

Our audit was, however, interrupted due to difficulties in obtaining access to the records of operators for supplementary scrutiny, which were later resolved

Despite our repeated efforts, the Panna Mukta Tapti Joint Venture (PMT JV — joint operators BGEPIL, RIL, and ONGC) did not provide important and relevant records on the ground that scrutiny of these records did not fall within our audit scope, which was limited to accounting records in terms of the PSC provisions.

The PMTJV also did not respond to the majority of our preliminary observation memoranda, on the ground that the issues raised therein were outside the scope of audit rights envisaged in the PSC.

We do not agree with the views expressed by the PMTJV. In our opinion, the records sought by our audit teams (in particular the procurement-related records) were fully covered by the PSC, and access to such records was essential for the purpose of our scrutiny. Consequently, our scrutiny of records of the Panna-Mukta and Tapti fields was incomplete, as also the findings arising therefrom. After the issue was raised yet again in June and July 2011, the PMT JV furnished part of the relevant records in July 2011, and assured that they would furnish the relevant records shortly.

The records furnished recently by them as well as the records, in respect of which assurances have been received, will be covered subsequently, and findings arising therefrom included in subsequent audit reports.

Comments on Audit Scope by Operator

The operator of KG-DWN-98/3 block challenged the scope, extent and coverage of our audit at various points of time, indicating that the CAG had conducted a "performance audit", which was not permitted under the PSCs. It was stated that nothing in the PSC permitted an audit of the operational, commercial and technical decisions of the operator. Further, an exercise, whereby the auditor would step into the shoes of the operator and attempt to evaluate whether the decisions by the operator—taken within his authorized area of operation—were in accordance with some undefined norms or the processes adhered to by bureaucratized decision making processes and that too without having the advantage of access to technical expertise or having the accountability for implementing such projects, was clearly beyond the provisions of the PSC.

We do not agree with the operator's views. In our opinion, our scrutiny was entirely consistent with the provisions of the PSC. Further, verification of charges and credits relating to the contractor's activities and other documents considered necessary to audit and verify the charges and credits, is not merely limited to an arithmetical totaling of charges and credits or tracing of charges/ expenses from the accounting statements to the contracts/ expense vouchers.

Such an exercise would extend to verifying whether the costs being depicted in the PSC accounts by the contractor, which would critically affect the determination of profit petroleum and Gol's share therein, are correctly determined, and in particular, costs incurred for procurement of goods and services are determined through a competitive process, so as to minimize costs (and ultimately maximize the Gol share of profit petroleum).

Such verification does NOT amount to the auditor stepping into the shoes of the operator and evaluating such decisions in accordance with "bureaucratized" decision making processes as stated by RIL.

Our objective remains restricted to verifying whether Gol's revenue interests (including impact on current/future Gol share of profit petroleum) are properly protected.

As stated earlier, we did not intend to, nor have we conducted a performance audit of the activities of the operators. Audit also wishes to firmly emphasise that all our enquiries and findings emerge from, and are limited to the PSC.

We do not profess to go into any procedure or policy related aspects leading to the conclusion of the PSC. Taking the PSC as given, we have merely examined the contractual obligations of the signatories to the contract, viz., the Government and the private contractors. Our findings are totally guided by the "written word" of the contract.

In its response, MoPNG (July 2011) has agreed that the scope of audit conducted by the
CAG is within the common audit parameters, and that financial/accounting audit also
envisages review of activities and resources contributing to financial events and the
controls thereon.

Main Findin s

KG-DWN-98/3 (Operator: RIL)
The KG-DWN-98/3 block, which is operated by RIL, was awarded in the first NELP round in the year 2000. It has India's largest gas discoveries (Dhirubai-1 and Dhirubai-3 gas fields) and also has a large oilfield discovery (MA oilfield). Our main findings and recommendations relating to the KG-DWN-98/3 block are as follows:

Non-relinquishment of area and declaration of entire contract area as discovery area
We found that the contractor was allowed to enter the second and third exploration phases without relinquishing 25 per cent each of the total contract area at the end of Phase-I and Phase-II as against Articles 4.1 & 4.2 of PSC. Subsequently, in February 2009, Gol also conveyed approval to treat the entire contract area of 7645 sq.km. as 'Discovery Area', thus enabling the operator to completely avoid relinquishment of area.
'Discovery Area' is defined in Article 1.39 of the PSC as "that part of the contract area about which, based on discovery' and results obtained from a well or wells drilled in such part, the contractor is of the opinion that petroleum exists and is likely to be produced in commercial quantities". The delineation of 'discovery area' is inextricably linked to results obtained from wells drilled and finding of petroleum deposits recoverable at the surface (which can be discovered only through drilling of successful wells). At the end of the Exploration Phased, the operator had drilled all wells - in the north-west part of the block only.

The sequence of events between April 2004 and February 2009 clearly demonstrates that: • Originally DGH did not agree (May 2004) to RIL's proposal (while preparing to proceed from Exploratory Phase-I to Phase-II) for not relinquishing any part of the contract area (at the end of Exploration Phase-I) and reiterated the PSC contractual provisions for relinquishment of 25 per cent at the end of Phase-I (even identifying "least priority" areas 'Discovery' is defined in Article 1.38 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'. for consideration for relinquishment). DGH, further, stated that none of the existing discoveries extended beyond 'priority area-I', and no well had been drilled in 'priority area-II', and hence it was not possible to consider the total block area as the discovery area.

• However, by April/ May 2005, DGH capitulated. While noting that there were "no two
different interpretations possible as far as the definition of discovery provided in the PSC",

DGH felt it would be "prudent to acquire and interpret the 3D seismic data in the remaining part of the block on a fast track basis". Subsequently, "the relinquishment area could also be worked out in a proper manner". In the meanwhile, RIL had already moved from Phase-I to Phase-II without any area relinquishment, and was notifying its intent to move from Phase-II to Phase-Ill, again without any relinquishment.

In August 2006, DGH informed MoPNG that the Management Committee (MC) (chaired by DGH representative) had, in July 2006, permitted the contractor to enter the next phase without relinquishing any area, since data showed "continuity of discovery" in the block area (on the basis of RIL's presentation based on the results of seismic data acquired).

• Thereafter, there was extensive correspondence between MoPNG and DGH from August 2006. MoPNG raised pertinent questions as to whether the coverage of wells was over the entire block for DGH to reach the conclusion of discovery extension, but failed to pursue this aspect further.

• By April 2007, MoPNG felt that the proposal might be considered on getting a certification from DGH that the whole area had been covered by a reasonable number of wells/ 3D seismic to substantiate continuity of channels and the extent of discovery area. DGH gave a certificate in May 2007 to MoPNG.

• Even in May 2007, internal notes of MoPNG indicated their awareness that the whole of the block had been provided as a discovery area on the basis of 3D seismic and not on drilling of wells, which were mainly confined to the NW part of the block. However, MoPNG now proposed that on the basis of the proposed discovery area, the operator should be asked to appraise the area as per appraisal-related PSC provisions.

After concerns expressed by the then Minister, PNG as to whether the decision sought to be ratified was consistent with the PSC provisions, the case was referred to a committee under the chairmanship of Additional Secretary, MoPNG. The Committee accepted the contractor's claim (February 2008) and decided (April 2008) that the timeline for appraisal of discoveries would commence from 11 July 2006 (viz. MC's acceptance of the contractor's claim).

This was finally approved by the Minister in July 2008, but communicated to DGH only in February 2009. RIL's views at different points of time (that the contractor was "of the opinion that petroleum was likely to exist", "the contract area was having hydrocarbon potential", "ultimately additional exploratory wells needed to be drilled to establish the additional hydrocarbon potential in the deeper water area of the block for which they were making efforts to hire ultra-deepwater rigs" clearly attempted to confuse potential/ prospectivity with actual discovery of hydrocarbons. Their difficulties in hiring ultra-deepwater rigs for the deep water area of the block (essentially the SW part, where no discoveries had been made) had no linkage with the contractual provisions for discovery area and relinquishment.

Thus, RIL's proposal of April 2004 to not relinquish any area and retain the whole contract area as 'discovery area' was submerged in a sea of correspondence between RIL and DGH, without relinquishment action being taken in terms of the PSC provisions, while RIL was allowed to proceed from phase to phase. By April/ May 2005, DGH had "waived" its earlier objections, and now advised/ directed the operator to complete 3D seismic data. By July 2006, DGH completed its about-turn and agreed (through the MC) to the contractor's proposal. MoPNG was aware of the flaws in the MC's decision for retention of the entire area, but, instead of reversing the same (in line with PSC provisions), it chose to accept DGH's certification for such retention.
MoPNG gave a detailed reply (July 2011) regarding acceptance of operator's opinion by DGH and MoPNG. We, however, do not agree with the reply as allowing the contractor to retain entire block area as discovery area was not in compliance with PSC provisions. The reply of MoPNG and our rebuttal thereof are given in detail in Chapter 4.

We recommend that MoPNG should review the determination of the entire contract area
as 'discovery area' strictly in terms of the PSC provisions. Further, it should delineate the
stipulated 25 per cent relinquishment area at the time of the conclusion of the 1'` and 2nd
exploratory phases, and then correctly delineate the 'discovery area' strictly based on the
PSC definition, linked to well or wells drilled in that part, without considering any
subsequent discoveries (which would be invalid on account of non-compliance with PSC
provisions).

Discovery related issue

In violation of PSC provisions, in the case of 13 out of 19 discoveries between October 2002 and July 2008, the operator had, without first furnishing the initial particulars of the discoveries in writing to the MC and Government, directly given written notifications regarding potential commerciality of the discoveries.

MoPNG replied (July 2011) that in the beginning, systems and processes were not fully
established, however, over a period of time, the procedures had now been strengthened, and were being strictly followed for subsequent discoveries as per PSC requirement.

D1-D3 gas discovery

The operator submitted an "Initial" Development Plan (IDP) in May 2004 (with estimated
capital expenditure (capex) of US$ 2.4 billion). The IDP was followed up with an Addendum to the IDP (AIDP) in October 2006 (estimated capex of US$ 5.2 billion for Phase-I and US$ 3.6 billion for Phase-II).

We found that:

• Most procurement activities were undertaken late in line with the schedules of the IDP of May 2004. By contrast, activities in respect of items in the AIDP were initiated even before the submission/approval of the AIDP. Clearly, the development activities of the operator were guided by AIDP, rather than IDP.

• As indicated by the operator, advance action was taken to tie up vendors for timely
development of D1/D3 fields in anticipation of the MC approval of the AIDP. While a view could, perhaps, be taken that such pre-approval action is at the risk and cost of the
contractor, in reality, this increases the probability of such approvals becoming a fait
accompli. Since approval of estimates does not constitute acceptance of the cost projections of the operator, validating the cost incurred by him can be done only after audit of the actual cost through proper norms. Part of the expenditure in respect of individual items under AIDP incurred during 2006-07 and 2007-08 has been audited. Remaining expenditure incurred from 2008-09 onwards will be covered in future audits.

Procurement-related activities
We found that payments during 2006-07 and 2007-08 revealed instances of huge procurement contracts where we could not derive assurance as to the reasonableness of costs incurred, primarily due to lack of adequate competition — award on single financial bids; major revisions in scope/ quantities/ specifications; post-price bid opening; substantial variation orders - with consequential adverse implications for cost recovery and Gol's financial take.

In particular, regarding the MA oilfield, we found that well before submission, let alone
approval, of the Field Development Plan (FDP) and Mining Lease (ML) application, the operator had placed orders for various critical items required for development activities/ production facilities from 2006 itself. We also found serious deficiencies in the award, on a single financial bid, of a 10 year hiring contract for US$ 1.1 billion for a Floating Production, Storage and Offloading (FPSO) vessel from Aker Floating Production (AFP).

During our scrutiny of the operator's records, we have come across 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. In our opinion, such disqualification of vendors on technical grounds, after a pre-qualification process and bidders' meetings for technical clarifications, limits the competitiveness which is not in accordance with the spirit of the procurement procedure given in the PSC. In many cases, it resulted in no competing financial bids, and the contract was awarded on the basis of a single financial bid. In such a situation, the letter and spirit of the MC's role at the pre-qualification stage is vitiated. Consequently, in our opinion, in cases of procurement (under procedure 'C' — high value contracts), where pre-qualified bidders are subsequently disqualified/ declared non-responsive on various technical and other grounds and there is only one financial bid being considered, the Operator should either go back to the pre-qualification process, and ensure
that more vendors/ parties are pre-qualified. Alternatively, if the operator wishes
consideration of only a single financial bid, the matter has to be necessarily referred back to the MC (including Gol representatives)/ Gol for ex ante relaxation from PSC stipulated
procurement procedures. Post facto approval of the MC may be provided for in emergent
cases, with adequate justification.

Likewise, extension of contracts (beyond the extension periods already stipulated in the
contract) is not in consonance with PSC provisions. If the operator wishes to extend such
contracts, the matter has to be necessarily referred back to the MC for necessary relaxation.

We, therefore, recommend that in the case of the KG-DWN-98/3, MoPNG carefully review in depth the award of 10 specific contracts (of which 8 were awarded to Aker Group companies) on the basis of a single financial bid. In this recommendation we are not even remotely suggesting that the operator should follow government procurement
procedures, yet any commercially prudent private acquisition would also attempt to
generate competition and thereby obtain the most competitive price. Such concern for a
cost effective acquisition is not perceptible in the aforementioned process.

Reality views by sm –
Friday, September 09, 2011

Tags- Complete CAG Report Reliance RIL KG BASIN 6

08 September 2011

Last Part Complete CAG Report - AIR India the Ministry of Civil Aviation (MoCA) and the Bilateral Agreements –

Last Part Complete CAG Report - AIR India the Ministry of Civil Aviation (MoCA) and the Bilateral Agreements –

Chronology of events leading to change in aircraft requirements of AIL

Date Brief Details of Event
30 October/ 3 November 2003
Letter from 43 member delegation of US Congress regarding AIL’s proposed aircraft acquisition forwarded by PMO to MoCA

27 January 2004 PMO forwarded two letters from Boeing (a letter of 17 November
2003 to Secretary, MoCA and a letter of 2 January 2004 to PMO) to MoCA, wherein Boeing indicated that the economics of the acquisition project were strongly dependent on the number of aircraft chosen, and that the technical evaluation could be easily influenced with the change in assumptions on number of aircraft.

19 February 2004
In response to contentions made by Boeing in these letters, AIL intimated MoCA that:
Equal opportunity had been given to both suppliers, and the number of long range aircraft had been reduced from 17 to 10 as it was not economically viable;

The evaluation was undertaken in conformity with AIL’s requirements. The question of giving Boeing a revenue benefit of 7 additional seats (reduced by them to provide the mid cabin galley) did not arise; also, estimation of residual value after 17 years life of aircraft was fraught with risk and the percentage discount offered by Boeing for 10 aircraft was lower than that offered by Airbus;

3 March 2004
Director (S), MoCA intimated PMO that the in-house TENC had evaluated different aircraft types on the basis of identical ground rules, providing fair opportunity to all bidders.
In addition to highlighting the issues raised by AIL to MoCA, he also stated that AIL had invited offers for 10 firm and 7 optional long range aircraft. Boeing had the opportunity for bringing in scale economics into their offer. After due consideration of economics, the AIL Board had recommended acquisition of only 10 A340-300 aircraft as it felt
that acquisition of 17 long range aircraft would not be economically viable.

29 June 2004
Director (S), MoCA recorded on file that there had been some “important developments” as submitted by Secretary, MoCA to the Principal Secretary to PMO that many international carriers were planning direct operations to USA/Canada and the A340-300 aircraft was going out of production in near future. Therefore, AIL needed to
review its proposal and consider suitable long range aircraft for its fleet. Further, it was understood that “Minister, Civil Aviation (CA) also impressed upon AIL in a meeting at Mumbai to examine the feasibility of direct India-US/ Canada flights”.

5 July 2004
AS&FA (Additional Secretary and Financial Advisor), MoCA expressed
ignorance about the purported note of Secretary, MoCA and stated
that:

“I am not aware of the A-340-300 going out of production in the near future, thus calling for a re-look at the choice. The fact that Air India chose to invite offers for this type of aircraft and the Company decided to quote for the same less than a year ago, leads one to think whether Air India chose the right type of aircraft while inviting offers. If the assumption that the aircraft is going out of production is true, Air India is guilty of not having done their homework and the Airbus Company is guilty of unethical business
practice in offering an aircraft that is being phased out. …But it would be worthwhile to get clarifications on these aspects from both Air India and Airbus Company”.

“Minister (CA) in a meeting at Mumbai impressed upon the need for Air India to examine the possibility of non-stop India-US operations. But he never suggested that the present fleet acquisition plan should be dropped and only that option should be examined. Hence, it would not be correct to presume that the new option that would be examined would be ‘in lieu of’ the existing plan. It could be ‘in addition’ as well. Of course, if Air India decides to go in for the option of non-stop India-America operations, this would call for a re-look at the present fleet acquisition proposal.”

Consequently, AS&FA suggested that a meeting (like the one Minister, CA took in respect of IAL) would be in order, wherein the points of view of both AIL and MoCA could be considered, and a consensus arrived at on the future course of action.

August 2004

In a meeting on 2 August 2004 taken by the then Minister, Civil Aviation with Secretary, MoCA and CMD, AIL, it was decided that:

Air India should revisit the proposal for purchase of aircraft and submit a fresh project proposal to the Government at the earliest, which could include the revised requirements.
AI could examine whether the proposal for purchase of short range aircraft for the low cost airline is justified on a stand-alone basis and could be de-linked from the purchase of other types of medium range and long range aircraft for AI. While doing so, AI
should examine whether economics of the proposal for acquisition would be favourable, keeping in view the low-cost and low fare operations envisaged through a separate company. If the proposal is found to be justified and viable, Air India should revert
to the Government at the earliest.

At this meeting of 2 August 2004, the Chairman and Managing Director (CMD), AIL was of the view that although the present proposal did not fully cater to the requirement of AIL’s fleet, the additional requirement of aircraft could be projected separately
through a supplementary proposal after due evaluation. However, it was felt that it may not be advisable or prudent to go through the pre-PIB and PIB exercise in two separate stages with two different sets of proposals for such capital intensive projects. It
would be desirable to take a total and comprehensive view on the fleet of AIL, keeping in mind its plan and growth for the next fifteen years or so.

MoCA communicated the above mentioned decisions on 5 August
2004 to AIL and directed them to revisit the acquisition proposal and
submit a fresh proposal, which would include revised requirements in
view of:

New dimension in the competition on the India/USA route with the introduction of non-stop flights through ultra long range aircraft by competing airlines in South East Asia and the Gulf Region. Unless AIL was able to match this product and connectivity by adding suitable aircraft to its fleet (which was not a part of the present proposal), AIL’s competitiveness, load factors and revenues were likely to be severely affected.

AIL had decided (May 2004) to launch a ‘no frill’ airline called ‘Air India Express’ through a separate company (Air India Charters Limited) to destinations in South East Asia and the Gulf, which would offer lower fare to passengers. Therefore, the current
project proposal may not have taken into account the economics of these types of aircraft if operated on low cost basis and with fares that would be 25 per cent lower than existing fares.

October 2004
CMD, AIL indicated to MoCA that during the AIL Board meeting of 13 September 2004, some Board members indicated that in view of MoCA’s advice, the fleet acquisition programme needed to be revisited in its entirety (including examination of other aircraft types, apart from B737-800, for small capacity short range aircraft). CMD, however, felt that the B737-800 project should be delinked and studied separately and was to be submitted under the banner of AICL. CMD sought MoCA’s clarification in this regard.
MoCA sought clarification from CMD, AIL as to whether the B737-800 aircraft was selected after carrying out the required comparative evaluation on stand-alone basis. AIL confirmed the selection of B737-800 aircraft after comparative evaluation on stand-alone basis

Director (S) noted that “strictly speaking, it is for the AI Board to take a view in the matter. As far as Ministry’s advice... is concerned, there is a suggestion... that AI needs to take a total comprehensive view on its fleet, keeping in mind its plans and growth for the next 15 years or so”.Consequently, a clarification was issued along these lines, with the
approval of Minister, Civil Aviation, to AIL.

24 November 2004
AIL Board considered and approved a revised long term fleet plan for 50 aircraft (two thirds on firm basis and one-third on option basis), apart from 18 aircraft for its subsidiary, AICL. This process of revision took only four months!
he above sequence of events clearly demonstrates that the erstwhile Air India was
advised to revisit its proposal by MoCA into expanding its requirement of aircraft. Whilst their earlier proposal for 28 aircraft had taken two years (from January 2002 to January 2004) to prepare and submit, the revised long-term fleet for 50 aircraft6
plan was completed in four months (from August to November 2004)

The Ministry did not agree (August 2011). It stated that it never suggested to AIL to drop
the present acquisition plan and to pursue a particular option. It was the Air India Board
which resolved to acquire 35 aircraft, with 15 on optional basis. This position was reiterated by the Ministry during the exit conference (August 2011).

The Ministry’s position is not tenable. The sequence of events brought out in Table 3.2 –
“Chronology of events leading to change in aircraft requirements of AIL” clearly brings out the role played by the Ministry in the erstwhile AIL’s proposal being revised from 10 long range aircraft to 50 long range aircraft.

A comparison of the underlying assumptions for the original and revised proposals reveals the following position:

I am not here posting the chart.

Clearly, there was a massive inflation of aircraft requirement (frequency, destinations, and types of aircraft) between January 2004 and August 2004, which is inexplicable
(considering that such a dramatic shift in market requirements/ conditions could not
reasonably have occurred in such a short period of time).

Flawed Assumptions underlying revised project report (50 long range aircraft)
In our opinion, many of the key assumptions underlying the revised project report for
acquisition of 50 long range aircraft (as against 10 long range aircraft envisaged earlier)
were flawed or unduly optimistic:

As depicted in the preceding table, a massive increase in frequencies, ASKM and
destinations were projected, without adequate justification for the increase in such a
short period of time (between January and November 2004). Out of the 50 aircraft being
acquired, 27 were intended as replacement and 23 as incremental. The logic being that
expanding capacity faster than the market / competitors would enable AIL to grow and
increase market share, since the market to/ from India was booming. The assumption
that increase in capacity share would automatically lead to an increase in AIL’s market
share (projected increase from 19% to 30% by 2012-13) was not adequately validated

This leads Audit to agree with the observation thus made by the Department of
Expenditure that ‘a purely supply side response would run into huge demand side risks’
(Table 3.5). Department of Expenditure obviously had reservations and felt the PIB
proposal was ‘supply driven’.

Revenue estimates were made on the basis of one-time yield increase, at constant costs,
of 5 per cent on all classes7

. Further, the core feature of the revised project report was acquisition of 8 Ultra Long Range (ULR) aircraft for providing non-stop services to Chicago/ New York; a further one-time yield increase of 10 per cent (at constant cost) for non-stop services to New York and Chicago was assumed, which, in our opinion, was unduly optimistic. In reality, even prior to this acquisition, the India-USA sector was historically a loss-making sector, and this trend of commercial unviability continued even with the introduction of non-stop India-USA flights.

As per the original proposal (for 28 aircraft), the AIL Board reduced the requirement of
long range aircraft from 17 to 10, as the NPV for 17 long range aircraft on stand-alone
basis was negative. By contrast, the revised TENC Report (April 2005) for 50 aircraft had
a negative NPV for the 15 B777-300ER aircraft. By the stage of the revised project report
(May 2005), this became a positive NPV of Rs. 98 crore (mainly due to inclusion of
“commonality benefit” – through fleet acquisition of different variants of Boeing
aircraft).

Long term traffic growth rate of 7 to 8 per cent was assumed (although the average
growth rate during 1998-2004 was only 6.5 per cent); this was also unduly optimistic.

Whatever chances AI had of increasing market share through increased capacity share
were severely hampered by the MoCA’s decision to liberalise bilateral entitlements from
2005 onwards, benefiting airlines/ countries with huge proportion of 6th freedom traffic
and giving inadequate lead time for AI (after delivery of the aircraft) for gearing itself up
for competition. This is brought out subsequently in the Report

The Ministry in their reply (August 2011) stated that market share was not a complete index of an airline’s performance. In 2004-05, Air India was in no position, with its existing complement of aircraft, to even hold on to its market size, leave alone market share.

The Ministry’s reply, however, did not offer adequate explanations as to the flawed
assumptions underlying the acquisition proposal, as pointed out by us.

I am not writing next pages as its full of just information what happened.

Chapter 4 – again what happened.

Chapter 5 and Chapter 6 what happened

The CAG audit star rating out of Ten
I will give just one star for this air India CAG Report

Suggested Reading –

P – 3 Complete CAG Report - AIR India the Ministry of Civil Aviation (MoCA) and the Bilateral Agreements –
http://realityviews.blogspot.com/2011/09/p-3-complete-cag-report-air-india.html

P -2 Complete CAG Report - AIR India the Ministry of Civil Aviation (MoCA) and the Bilateral Agreements –
http://realityviews.blogspot.com/2011/09/p-2-complete-cag-report-air-india.html

Complete CAG Report - AIR India the Ministry of Civil Aviation (MoCA) and the Bilateral Agreements – Part One
http://realityviews.blogspot.com/2011/09/complete-cag-report-air-india-ministry.html

Reality views by sm –
Thursday, September 08, 2011

Tags- News FULL CAG REPORT AIR INDIA

P – 3 Complete CAG Report - AIR India the Ministry of Civil Aviation (MoCA) and the Bilateral Agreements –

P – 3 Complete CAG Report - AIR India the Ministry of Civil Aviation (MoCA) and the Bilateral Agreements –

Scheduled air services in India began in October 1932 under the Aviation Department of
Tata Sons Ltd, which was succeeded by Tata Airlines. This was subsequently renamed in July 1946 as Air India Ltd., and incorporated as Air India International Ltd. in March 1948.

In 1953, the Air Corporations Act was passed. Air India International Ltd. was nationalized, and two corporations came into existence – Indian Airlines Corporation (as the national domestic carrier) and Air India (as the international carrier). In 1994, the Air Corporations Act was repealed, and Air India Ltd. (AIL) and Indian Airlines Ltd. (IAL) were incorporated under the Companies Act, 1956.

Government-owned airlines dominated the Indian aviation industry till the mid-1990,
When, as part of the open sky policy, the Government of India (Gobi) ended the monopoly of AIL and IAL in air transport services, and allowed private operators to provide air transport services.

In March 2007, National Aviation Company of India Ltd. (NACIL) was incorporated. The scheme of amalgamation of Air India Ltd. and Indian Airlines Ltd. into NACIL was approved in August 2007, with the “appointed” date of the merger being set as 1 April 2007.

Subsequently, in November 2010, NACIL was renamed as Air India Ltd. (AI). The
Administrative Ministry for these Government airline(s) is the Ministry of Civil Aviation
(MoCA).

Audit Objectives and Scope –

The objectives of the performance audit were to ascertain:
Whether the acquisition of aircraft by the erstwhile Air India Ltd. (AIL) and Indian Airlines Ltd. (IAL) was appropriately planned and effectively implemented, with due regard to economy and efficiency and accepted norms of financial propriety;

Whether the merger of AIL and IAL into NACIL was properly planned and effectively
Implemented, and the effectiveness of merged operations of the two entities;

The impact of the liberalized policy of the GoI from 2004-05 onwards on grant of air
traffic rights to other countries through Air Services Agreements (ASAs)/ “bilateral”
agreements and permitting Indian private carriers to fly on international routes;

The main reasons for the poor financial and operational performance of the pre-merger
airlines and the merged entity; and

Whether the MoCA exercised its oversight role adequately and effectively.
Audit Criteria

The audit criteria adopted for the performance audit included:
The reliability of the data used, reasonableness of assumptions adopted, and robustness
and competitiveness of the tendering, evaluation, negotiating and contracting
processes/ procedures for the acquisition of aircraft;

The reliability of data and robustness of assumptions underlying the decision for merger
of the airlines as well as the planning of the merger;

Adequacy of the facts and information put forth to evaluating/ approving agencies for
the acquisition of aircraft, approval of liberalized policy on “bilaterals”, and approval of
merger of AIL and IAL; and

Performance parameters achieved by competing national and international airlines.

Audit Methodology -

Our performance audit (conducted between September 2009 and June 2011) involved
scrutiny of records of MoCA and AI. The first draft of the performance audit report was
issued to the MoCA on 15 November 2010; the replies of MoCA and AI received in February 2011 have been considered and duly incorporated in this report. A revised draft of the performance audit report was issued to MoCA on 11 March 2011, to which no response was received.

A further revised draft of the performance audit report (including findings arising out of
additional scrutiny of records of MoCA and AI) was issued to MoCA on 6 July 2011, reply to which has been received on 3rd August 2011. Further, an exit conference to discuss the main audit findings was also held with MoCA on 3rd August 2011.

Acquisition of aircraft by erstwhile Air India (AIL) –

On 30 December 2005, the erstwhile Air India Ltd. (AIL) signed purchase agreements with Boeing and General Electric (GE) for supply of 50 Boeing aircraft (with GE engines) at an estimated project cost of Rs. 33,197 crore:

8 B777-200LR ultra long range aircraft (ULR) with a seating capacity of 266;

15 B777-300 ER medium capacity long range aircraft (MCLR-A) with a seating capacity of 380; and

27 B787-8 (popularly known as “dreamliner”) medium capacity long range (MCLR-B)
aircraft with a seating capacity of 258.

In addition, Air India Charters Ltd. (AICL) 1 also signed purchase agreements with Boeing and CFM for supply of 18 short range B737 aircraft with CFM engines at an estimated project cost of Rs. 4,952 crore

The last fleet acquisition by the erstwhile AIL involved induction of two B747-400 aircraft in 1996.

A brief chronology of events related to the current acquisition of aircraft by the erstwhile AIL is indicated below:

December 1996
AIL’s proposal for acquisition of 3 A310-300 aircraft was not cleared by MoCA due to reasons like availability of excess A-320 type of aircraft with the erstwhile IAL.

January 2002
Expert committee was constituted by AIL to identify aircraft requirement and prepare fleet plan for 5 year timeframe.

November 2002

Techno Economic and Negotiation Committee (TENC) was constituted
by MD, AIL for finalization of requirement of aircraft.

April/ July 2003

TENC submitted separate reports for acquisition of: 17 (10 on firm basis + 7 on option basis) medium capacity long range aircraft (A340-300 / B777-200 ER);

and 18 short range aircraft (A320-200 / B737-800).

November 2003
After review, TENC submitted a revised report for 18 short range and
10 or 17 long range aircraft on the basis of revised pattern of operations, making NPV positive. AIL Board approved proposal for acquisition of 10 medium capacity
long range aircraft (A340-300) and 18 small capacity short range aircraft (B737-800).
January 2004 AIL submitted project report for acquisition of 28 aircraft to MoCA. 02 August 2004 In a meeting chaired by the then Minister, Civil Aviation it was
decided that Air India should revisit the proposal for purchase of aircraft and submit a fresh project proposal to the Government at the earliest which could include the revised requirement.

13 September 2004
Based on the decision taken in the meeting of 2nd August, 2004, as communicated in the Ministry’s letter dated 5th August, 2004, the Board of Directors of Air India in its 101st
meeting decided that the fleet plan could be revisited in its entirety.

24 November 2004
AIL Board approved a revised plan for acquisition of 50 aircraft for AIL,
apart from 18 aircraft for its subsidiary AICL.

03 December 2004
Bids were invited from Boeing and Airbus.

24 December 2004 Technical bids were opened.

26 April 2005
TENC evaluated bids and submitted its report.

On the same day, AIL Board approved the acquisition of 50 aircraft (35
firm + 15 on option) from Boeing with GE engines.

14 May 2005
Project Report for GoI approval for acquisition of aircraft was
submitted to MoCA.

16 June 2005
Price Negotiation Committee was constituted by AIL, with ‘in
principle’ approval of MoCA.

30 June 2005
Presentation was made by AIL to MoCA on aircraft acquisition.

18 August 2005
‘Overseeing Committee’ was constituted by MoCA to oversee the process of price negotiations with Boeing and GE for acquisition of aircraft; negotiations were held by Overseeing Committee between August 2005 and November 2005

31 August 2005
Pre- PIB (Public Investment Board) meeting was held.

13 October 2005
PIB cleared the aircraft acquisition at a cost not exceeding Rs. 33, 1974 crore, indicating:

that MoCA may evaluate AIL’s cost structure and productivity and fix benchmarks for achieving reduction in cost and enhancing productivity;

purchase of 35 on firm basis, and 15 on optional basis, with the decision for exercising the option to be taken by AIL Board, depending on the market situation.

15 December 2005
CCEA (Cabinet Committee on Economic Affairs) approved constitution of EGoM (Empowered Group of Ministers) for final round of negotiation with lowest bidder.
20 December 2005
Cabinet Secretariat communicated constitution of EGoM.

24 December 2005
EGoM held discussions with the representatives of Boeing and GE.

30 December 2005
PMO (Prime Minister’s Office) forwarded a copy of the note of the Chairman, EGoM to the PM on the action taken by the EGoM; where it approved acquisition of 50 aircraft by AIL on firm basis, in addition to acquisition of 18 aircraft by AICL;

30 December 2005
PMO returned the note indicating that the “Prime Minister has seen the note and directed that the Ministry of Civil Aviation may inform CCEA about the finalized transaction”.
30 December 2005 MoCA conveyed GoI’s approval to AIL.

30 December 2005
On the same day, AIL also signed purchase agreements.

12 January 2006
CCEA noted the contents of the MoCA note apprising them of the EGoM decision on acquisition.

July 2010
20 aircraft (8 B777-200LR + 12 B777-300ER) received; receipt of 3 B777-300ER aircraft deferred at AIL’s instance.

Our main audit findings in respect of this aircraft acquisition are summarized below.

Undue time taken for acquisition

There is no doubt that the erstwhile AIL desperately needed to acquire new aircraft. Due to lack of timely acquisition, AIL had to induct 13 additional aircraft on dry lease by January 2004. AIL’s proposal of December 1996 for aircraft acquisition was not cleared, and a fresh process for acquisition was initiated only in January 2002. Thus, it took nearly eight years (December 1996 to January 2004) when AIL finally came before Government with a firm acquisition proposal. Such an unduly delayed acquisition process is deleterious for the financial health of a commercial airline.

Interestingly, although the original proposal for acquisition of 18 + 10 aircraft took its own time for processing, the revised proposal for acquisition of 18 + 50 aircraft was processed considerably faster, with many activities (e.g. price negotiations) taking place concurrently with (or in anticipation/ advance of) approvals.

The Ministry explained (August 2011) that the delay referred to above, was due to the then prevailing circumstances, viz. shrunk market because of global events (9/11, SARS) and proposed disinvestment of the airline and later on the acquisition was done on priority to arrest the rapid decline of the airlines and the fact that other carriers were increasing capacity. The Ministry further stated that at no point was any activity required in the procurement process constituted in haste or in anticipation of any approval.
We do not agree with the Ministry’s reply. While the acquisition took nearly eight years
from the first proposal, the revised proposal for acquisition of 18 + 50 aircraft was
processed faster. Further, the Ministry’s contention regarding lack of haste in the procurement proposal for 50 + 18 aircraft is not borne out by facts since, as brought out in the chronology of events above. From the approval for the constitution of EGoM by the CCEA, for final round of negotiation with lowest bidder, to the signing of purchase agreement, it took just 16 days.

Increase in requirements from 10 + 18 aircraft to 50 + 18 aircraft in 2004

Change in number of aircraft to purchase –

The erstwhile AIL’s project report of January 2004 proposed acquisition of 10 medium
capacity long range aircraft (A340-300) and 18 small capacity short range aircraft (B737-800). This, itself, had taken two years to mature.

However, by November 2004, the AIL Board changed their fleet acquisition plan and
submitted a revised proposal for acquisition of 50 medium capacity long range/ ultra long
range aircraft, in addition to 18 small capacity short range aircraft for its subsidiary, Air India Charters Ltd. (AICL). This analysis to enhance AIL’s requirements took just four months (from August to November 2004), after MoCA advised them to “revisit” their proposal.

Suggested Reading –
P -2 Complete CAG Report - AIR India the Ministry of Civil Aviation (MoCA) and the Bilateral Agreements –
http://realityviews.blogspot.com/2011/09/p-2-complete-cag-report-air-india.html

Complete CAG Report - AIR India the Ministry of Civil Aviation (MoCA) and the Bilateral Agreements – Part One
http://realityviews.blogspot.com/2011/09/complete-cag-report-air-india-ministry.html

Reality views by sm –
Thursday, September 08, 2011

Tags- News FULL CAG REPORT AIR INDIA

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