MANAGEMENT DISCUSSION AND ANALYSIS REPORT

1. Global Economy

The global economic landscape in 2014 continued to portray a picture of cautious optimism, occasionally disturbed by bouts of uncertainty and conservatism. Growth did not pick up in a manner that justified the gradual and definite progress made by advanced economies in 2013 which was assumed to have provided a strong foundation for a pickup in the momentum of economic recovery globally. Legacies of both the financial and euro area crises are still a matter of substantial concern for many countries as they attempt to put in place a more robust and resilient economic framework with an eye on a sustainable and more brdictable growth outlook.

In 2014, in what is reflective of the emergence of further dissimilarities in the growth trajectories among the major economies, whereas the recovery pattern of the US looked stronger than expected the same in other major regions of the world was underwhelming for the most part with some having even flirted with a slip back into a recessionary spiral at times, such as Japan. As per the World Economic Outlook 2015, aging, together with a slowdown in total productivity, has played a part in dampening the prospects of a faster turnaround in the developed group of countries. Moreover, two other significant trends weighed in majorly on the global growth cycle: the spectacular decline of crude prices and large exchange rate movements. The slide in oil prices has been the net result of variety of forces: weaker-than-expected global activity; weaker demand for oil, given activity and, most importantly, greater supply. This development while weighing down heavily on oil-export dependent economies will prove to be immensely beneficial to large scale oil importers like India by easing inflationary brssures as well as reducing sovereign trade deficits. Moreover, it also provides some much needed fiscal space to rethink and rejig fiscal positions in economies with fuel subsidies. However, in an environment of low oil prices, it must be noted the attendant pickup in the demand cycle which is expected to boost the domestic growth cycle will be dependent on the degree of pass-through that respective governments allow to reach consumers.

The exchange rate volatility, on the other hand, to a large extent, reflects the changing broader sentiment in the market related to the growth prospects of individual economies. Here, the apbrciation of the US dollar over the last one year, particularly, relative to that of the currencies of other advanced economies reflect the strengthening confidence around the medium-term prospects of a stable growth pattern taking root in the US. Also, the strengthening of the US currency implies that most countries experienced a somewhat smaller decline in oil prices relative to the headline US dollar figure.

As for the emerging market and developing economies, the group, on the evidence of activities in 2014 and the early part of 2015, has moved into a period of marked deceleration as slower growth in its major countries exerted significant downward brssures on the buoyancy and expectations of markets, at least for the medium term. Powerhouse China, especially, following on its commitment to a more demand-led growth as opposed to their historical tendency for an investment-intense regime, has markedly scaled down their sizeable infrastructure programmes. Russia was hit by wild currency fluctuations and the imposition of economic sanctions by the western world. Brazil found itself in the grip of unusually weak economic activity. So, India's improved economic performance in 2014, largely a result of the reformist and market-oriented approach of its new government, was a much needed shot in the arm for the group of emerging economies engulfed as they mostly are by tell-tale signals of an overall slowdown.

Overall, in numbers, global growth in 2014 was a modest 3.4 per cent, reflecting a pickup in growth in advanced economies relative to the brvious year and a slowdown in emerging market and developing economies. The block clocked a below-par growth of 4.6 per cent, marking 2014 as the third consecutive year that the group had to settle for a sub-5 per cent growth. In comparison, the advanced economies grew at an annualised 1.8 per cent, a marked upswing from last year's performance (1.4 per cent in 2013). Despite the slowdown, due to the sheer volume of their trade and business, the emerging market and developing economies still accounted for three-fourths of global growth in 2014. Growth in the United States was stronger than expected, averaging about 4 per cent annualized in the last three quarters of 2014. Consumption—the main engine of growth - has benefitted from steady job creation and income growth, lower oil prices, and improved consumer confidence. The country continues to be the cornerstone of economic resurgence among the group of developed economies having sustained an imbrssive trend of positive growth over the last few years in the aftermath of the debilitating economic meltdown of 2008. For the world economy at large, the solidity and health of the US economy is, arguably, the best possible buffer in the face of any potential turmoil or volatility in the markets.

Globally, in terms of future outlook, global growth is projected to increase slightly from 3.4 per cent in 2014 to 3.5 per cent in 2015 and then to pick up further in 2016 to an annual rate of 3.8 per cent. The increase in growth in 2015 will be driven by a rebound in advanced economies, supported by the decline in oil prices, with the United States playing the most important role. The growth rate in the country is projected to nudge above 3 per cent in the current year as well as in 2016, with domestic demand supported by lower oil prices, more moderate fiscal adjustment, and continued support from an accommodative monetary policy stance.

In the Euro area, although lower oil prices, lower interest rates and euro debrciation are expected to provide a boost to its economic recovery, growth will continue to be moderated by the lingering effects of the block's financial crisis with few of the countries yet to emerge clearly out of the woods. Specifically, growth is expected to increase from 0.9 per cent in 2014 to 1.5 per cent this year and 1.6 per cent in 2016.

In emerging markets, in contrast, growth is projected to decline in 2015 - for the fifth year in a row. A variety of factors explain this decline: sharp downward revisions to growth for oil exporters, especially countries facing difficult initial conditions in addition to the oil price shock (for example, Russia and Venezuela); a slowdown in China that reflects, as identified earlier, a move toward a more sustainable pattern of growth that is less reliant on investment; and a continued weakening of the outlook for Latin America resulting from a softening of other commodity prices. For China, growth is expected to decline to 6.8 per cent this year and 6.3 per cent in 2016.

Indian Economy

Among the group of major emerging economies, the economic growth trajectory that India charted in 2014 provided ground for necessary cheer and optimism, in the regional as well as the global arena. In 2014, India's GDP grew at a rate of 7.2 per cent, a promising turnaround from the slackening economic fortunes of the brceding two years epitomised by a year-on-year dip in the country's growth numbers. This pickup in growth is largely attributable to recent policy reforms, a consequent pickup in investment, and lower oil prices. Particularly, the slide in global crude prices has had a positive impact on the country's inflationary tendencies. Consumer price inflation fell from 8.3% in March 2014 to 5.1% in January'2015. It is estimated to average 6.5% in fiscal 2015 - down from 9.5% for fiscal 2014 - before heading even lower to 5.8% in fiscal  2016.

In terms of trade, the numbers, though, still do not brsent an outright flattering picture. The country recorded US$310.5 billion worth of exports in FY15, down 1.2% from US$314.4 billion last year and 7.5% below the government's target of US$340 billion. Exports had grown by 4.7% in FY14. Despite debrciation in rupee from Rs. 60.5/$ in FY14 to Rs. 61.1/$ in FY15, exports suffered amidst weak global growth. However, the outlook for the Indian economy is one of sustained growth and that augurs well for the pickup in activity across all facets of the economy. As per the latest World Economic Outlook (April 2015), GDP growth in the country for 2015 and 2016 is projected to edge over 7.5 per cent on an annualised basis.

Global Energy Snapshot Primary Energy Consumption

Total primary energy consumption in 2014 has been 12,928 MMtoe; consumption increased by just 0.9% in 2014, a marked deceleration over 2013 (+2.0%) and well below the 10-yearaverage of 2.1%. Growth in 2014 slowed for every fuel other than renewable, which was also the only fuel to grow at an above-averagerate. Growth was significantly below the 10-yearaverage for Asia Pacific, Europe & Eurasia, and South & Central America. Consumption increased for all fuels, reaching record levels for every fuel type except nuclear power; production increased for all fuels except coal. For oil and natural gas, global consumption growth was weaker than production. Oil remained the world's leading fuel, with 32.6% of global energy consumption, but lost market share for the fifteenth consecutive year. Although emerging economies continued to dominate the growth in global energy consumption, growth in these countries (+2.4%) was well below its 10-year average of 4.2%.

OECD consumption experienced a larger than average decline (-0.9%). Energy consumption in the EU (1,611.4 MMtoe) fell to its lowest level since 1985.A second consecutive year of robust US growth (+1.2%) was more than offset by declines in energy consumption in the EU (-3.9%) and Japan (-3.0%). The fall in EU energy consumption was the second-largest percentage decline on record (exceeded only in the aftermath of the financial crisis in 2009).Non-OECD economies (+2.4%) contributed to the growth in energy consumption as OECD economies consumption fell by 0.9%, which was a larger fall than the recent historical average. China (+2.6%) and India (+7.1%) recorded the largest national increments to global energy consumption. Chinese growth (+2.6%) was the slowest since 1998, yet China still recorded the world's largest increment (74 MMtoe) in primary energy consumption for the fourteenth consecutive year. Chinese growth slowed (+2.6%); below 10 year average of 4.2%. India's energy demand grew at robust 7.1%. US consumption increased (+1.2%) for the second straight year

Crude oil: Demand & Supply

Global demand for liquids, around 91-92 million barrels per day, was stable enough not to invite any concern. The North American unconventional revolution that saw crude supplies in the once heavily-import dependent US skyrocket from around 4.5 million barrels per day (mbpd) in 2008 to over 9 mbpd by the end of 2014 was anything but new. Geopolitical tensions, as in earlier years, continued to simmer in the landscape (Syria, Yemen, South Sudan) with occasional heightening of intensity (IS in Iraq, the Ukraine crisis). And the world was nowhere close to slipping back into recessionary times as the advanced economies, particularly the US, seemed to be doing a good job of stripping away the strains from the difficult post-2008 period.

And yet with everything remaining largely static on the surface the picture has undergone such a radical shift. It was just the fundamentals at work at the end of the day with a 'little' help from the OPEC. Global supply growth had, for the past few years, consistently outrun demand growth, by almost 550,000 bpd. With high oil prices the outlook for supply growth was unmistakably buoyant, at least in the mid-term, with even more players staking their resources, man and capital, into tapping more and more oil, be it on land unconventional or deepwater reserves. The threat from geopolitics, because of its ever-existent nature, was more a routine than abrupt and so the market response, too, to it was calibrated as per past experiences. It, thus, was unlikely to cause a sustained systemic upheaval unless something dramatic happened

Most importantly the slackening demand in China will tell on the overall global demand grow th; demand for oil in China is projected to grow at just over 300,000 bpd, a substantial drop from a demand of close to 1 mbpd in 2010.

The steady rise in prices that followed the much fevered speculation of ‘Peak Oil’ in the mid-2000s and which was accompanied, all along, by enthusiastic declarations in the industry embracing “$100 as the new normal” endured a spectacular reversal in fortunes in 2014. At its worst, the prices plunge by almost 60 per cent from their mid-June highs of 2014.

However, before the dramatic rout of crude oil, which brtty much was the story of the year in global energy circles, oil prices had hovered comfortably over and around the $100 per barrel mark over the last two brceding years. In the process, it had brought into the energy markets a semblance of stability, a much desired but mostly elusive condition for energy operators worldwide. The stable high-price environment, which now, in hindsight, almost looks like a myth that had to be eventually ruptured, incentivized risk-taking and allowed for more ambition in the oil and gas setup, particularly in the upstream space where operators placed their bets on more aggressive exploratory efforts and challenging development projects.

But stability is a rare currency in the industry where companies are continuously engaged in risk-reward roulette, and the steep fall in prices is not entirely exceptional in an industry which has experienced quite a few volatile price cycles before this recent disruptive event. That being said, the fall is significant not just for its extremity but also for the fact that it signals and, essentially, reinforces the deeply complex nature of energy markets worldwide and how a wide variety of forces influence the fundamentals on the ground. The anemic rise in demand for energy was the first catalyst for the current episode of drop in global crude oil prices. And then was the decision of OPEC. In their November 2014 meeting OPEC decided not to cut down their supplies even as prices began to slide. This, effectively, served as the decisive move that signaled the free fall of prices with no immediate cutbacks in production in sight. Although prices have recovered somewhat from their worrying lows of January 2015, the fundamentals are still weak (high global crude inventories; no significant drop in US output; global economy far from picking up speed; the possibility of Iran returning to the markets in the event of a successful negotiation over its nuclear program with the group of western countries) and chances of further softening cannot yet be ruled out. Here, the potential return of Iran to the table is of importance considering the country with the resultant impact of further aggravating the supply glut and bearing down on crude prices.

Fall in crude oil prices and the industry

The fall in crude prices, over the last one year, has had far reaching ramifications within the oil and gas industr y globally, especially in the upstream space. And the foremost concern in this respect is how are low prices going to exert brakes, if any, on global liquids output. However, as yet, there are no reported tangible output cuts in any major producing area that can be directly linked to this fall in prices and most of the recent recovery in prices is actually tied to higher refinery runs, maintenance-linked outages, spikes in geopolitical tensions and the occasional reaction to declining rig counts.

The US shale industry was expected to be the hardest hit in this downturn due to the cost-intensive nature of its operations. And any negative impact in shale output would immediately reflect in US numbers. But US crude production increased by 1.2 mbpd to 8.7 mbpd in 2014, the largest volume rise since 1900, the date the US Energy Information Administration started keeping records. Even going forward, output in the country is projected to grow healthily through 2015 and 2016 and breach the 9 mbpd mark. Although there will be some deceleration in the momentum as producers idle some rigs and cap less profitable or the 'marginal' wells, there will be gains made from increased drilling efficiency, cost-cutting measures and greater productivity through targeting the 'sweet spots'. In fact, as per research from energy consultancy ood Mackenzie, even at $50 per barrel of Brent, only 190,000 b/d of oil production is cash negative, rebrsenting a mere 0.2% of global supply.

Talking about US unconventional sector, there has been a widesbrad view that at around US$85 or US$90 a barrel, extracting "tight" oil from shale would no longer be economical. But an IHS analysis based on individual well data finds that 80% of new tight-oil production in 2015 would be economic between $50 and $69 a barrel. And companies will continue to improve technology and drive down costs.

Although there is no immediate danger to major current production streams, the viability of future projects has been seriously dented by this slump in crude prices. Global oil and gas exploration projects worth more than US$150 billion are likely to be put on hold in 2015 as plunging oil prices render them uneconomic, data shows, potentially curbing supplies by the end of the decade. It is worth bearing in mind that even with oil at US$120 a barrel, the economics of some projects around the world were in doubt as development costs soared in recent years. Some of the projects that are likely to face the axe or deferral are Canadian oil sands, high capex LNG projects such as Shell's project in British Columbia, Statoil's Johan Castberg field in the Barents Sea and Chevron's North Sea Rosebank project. In the deepwater arena, the volume at risk of cancellation/delay at a Brent crude price <$60/bbl varies among IOCs depending on the geographic distribution of a company's deepwater portfolio dominance of high-cost, high government-take projects in Norway.

The international players, particularly the majors, have long prided in their ability to generate healthy returns; however, even in a high oil price environment of the brceding years, increasing costs of upstream field services and project development had severely eroded the profitability of most of these industry behemoths (from a high of over 30 per cent in 2008 to just over 10 per cent in 2013) resulting in a strong backlash from the community of investors who demanded stronger returns from companies with a shift in focus to 'value' over 'volume' growth. This trend which already was a talking point of the industry in 2013 and forced some of the leading companies to trim their expenditure plans for 2014 assumed even greater salience in the face of the onslaught to global crude oil prices. The returns of global majors in 2014 were, inevitably, worse than that in the brvious year. And the response from companies to this was brdictable: budget cuts.

Exxon Mobil slashed its capital budget by $4.5 billion; BP is set on trimming its spends by as much as $2 billion; Royal Dutch Shell has committed to slash investment by $15bn (£9.9bn) over the next three years.

The price drop in combination with the budget cuts announced by the major oil and gas companies will bear down heavily on worldwide exploration spending. Globally, exploration spending is projected to fall from a 2014 peak of close to US$100 billion to around the US$70 billion mark in 2015. Regardless of the level of cuts, budgets are likely to be revisited constantly through the year. But until crude prices rise sufficiently to occasion any upward revision to budgets, companies are likely to defer high cost drilling in frontier and emerging basins in favour of lower-cost, lower-risk options. The slackening of activity will also force down capital costs in the industry; upstream capital costs are expected to decline globally by approximately 12% on average between 2014 and 2016 offshore and 7% onshore. The role of E&P companies and how they approach the low-price environment be it through capex adjustments, reallocation of resources, and strategy will be critical in determining what the global oil market could look like in the next two years.

Although the primary events that played out in the oil and gas industry in 2014 and the first few months of 2015 can be interbrted as a matter of triumph of market fundamentals over geopolitical influences in determining market trends, it is hard to imagine global oil markets bereft of any geopolitical undertones given the inherently strategic moorings of the industry and how deeply 'oil and gas' affects the economic fortunes of a fair share of countries on the global map.

Gas Business: Production & Consumption

Globally, natural gas accounted for 23.7% (same as in 2013)of primary energy consumption. World natural gas consumption grew by just0.4%, well below the 10-year average of 2.4%.Growth was below average in both the OECD and emerging economies, with consumption in the EU (-11.6%) experiencing its largest volumetric and percentage declines. The Europe & Eurasia region (-4.8%) had the five largest volumetric declines in the world in Germany (-14.9%),

Italy (-11.6%), the Ukraine (-15.7%), France (-16.3%) and the UK (-9.2%).The US (+2.9%), China (+8.6%), Saudi Arabia (8.2%) and Iran (+6.8%) recorded the largest growth increments. India recorded gas consumption decline of 1.5%.

Global natural gas production grew by 1.6%, below its 10-year average of 2.5%. Growth was below average in all regions except North America (6.1%), Middle East (3.5%) and Asia Pacific (3.7%). EU production fell sharply (-9.8%) to its lowest level since 1971. The US (+6.1%) recorded the world's largest increase, accounting for 77% of net global growth. The largest volumetric declines were seen in Russia (-4.3%) and the Netherlands (-18.7%). India registered production decline of 5.9%.

(Reference: BP Statistical Review of orld Energy 2015)

Global natural gas trade registered a rare contraction in 2014, falling by 3.4%. Pipeline shipments declined by 6.2%, the largest decline on record, driven by falls in net pipeline exports from Russia (-11.6%) and the Netherlands(-14.1%). The UK (-28.2%), Germany (-10.1%) and the Ukraine (-29.9%) all reduced their net pipeline imports markedly

Coming to Russia, the country's continuing tensions with Ukraine related to the disputed gas contract between Russia's Gazprom and Ukraine's Naftogaz Ukrainy, in the aftermath of Crimean crisis, has its effect on pipeline gas trade from Russia. This has potential to disrupt Russian gas supplies to continental Europe. A major break in supplies, in the event of Ukraine's refusal to allow transit of Russian gas through its mainland, will not only have damaging repercussions in an energy-deficient Europe but it also carries serious implications for the sovereign revenues of a heavily-export dependent Russia. However, the chances of that happening are remote considering strategic nature of the Russian pipeline supplies, and the involvement of European mediators in the discussions between Russia and Ukraine is a testament to that. The episode, however, did raise some uncomfortable questions regarding the worrying degree of inter-dependence between Europe and Russia in an environment of geopolitical volatility and tensions arising out of Western sanctions on Russia.

Next, Russia's historic gas deal with China was another reason that the country remained in the churn of global energy news. After years of negotiations, Russia and China finalized huge multi-billion dollar long-term gas  supply deals, which when implemented, will see Russia transport record amounts of gas to Chinese markets each year. Both the deals together are valued at close to $800 billion over a 30 year period. The deals come close on the heels of mounting tensions between Russia and the West and that invariably gives them a geopolitical undertone as many interbrt the move as part of Russia's larger plan to shift its economic focus to Asia.

During 2014, global LNG trade registered an increase of 2.4%. Higher imports by China (+10.8%), Mexico (+19.55), UK (+20.1%) and India (+6.1%) were partly offset by declines in US (-38.4%), Canada (-45.1%), France (-18.4%), South Korea (-5.7%) and Italy (-17.7%).

Natural gas prices

Natural gas must compete with more competitively priced oil, and oil-indexed contracts imply lower realized prices and lower returns as LNG contract prices are set to follow oil prices down. Though Average LNG price in Japan during 2014 increased by one per cent over 2013; it dipped significantly in the fourth quarter of CY2014. LNG prices in Japan fell 17 per cent in December 2014 from a year earlier, the biggest drop since 2009, to $13.68/mmBtu, World Bank data show. LNG price is expected to fall further as Credit Suisse reports average import prices into the world's top buyer (Japan) are forecast to fall to about $11 per mmBtu next year, down from an estimated $16.33 in 2014 and $16.17 in 2013, if Brent crude averages around $75 a barrel. Overall in Asia, as per Bloomberg Finance, LNG costs in Asia will this year average below $10 per mmBtu for the first time in four years. Lower import prices must bode well for importers like India but here they have to compete with much cheaper coal.

Prior to the sharp fall in global crude oil prices, the liquefied natural gas (LNG) industry faced two major challenges: volume, that is lack of strong market demand and spiraling costs (capital cost of a green field liquefaction project has increased by up to four or five times, from between $350 and $600 per metric ton to anywhere between $1,200 and $2,000). Now the industry faces a fresh challenge: Value. The impact of low oil prices will hit hard the two main protagonists of LNG development - the IOCs and the NOCs of exporting countries. As both groups retrench, LNG development is likely to suffer collateral damage. As per Moody's the low LNG prices will result in the cancellation of the vast majority of the nearly 30 liquefaction projects currently proposed in the US, 18 in western Canada, and four in eastern Canada. However, projects already under construction will continue as planned, which will lead to excess liquefaction capacity over the rest of this decade.

Indian Oil & Gas Industry

Crude Oil & Natural Gas production

Crude oil production in FY'2014-15 was slightly more than the brvious year at 37.81 million metric tonnes (MMT) compared to 37.78 MMT of the brvious financial year. Despite natural decline of the matured fields, from which the majority of the output accrues, that ONGC and Oil India Limited (OIL) operate; production from Western Offshore (ONGC) registered a growth of 7.5% whereas the Pvt Companies/PSC

Joint Ventures saw an increase in output by 0.8% (against 3.7% during the brvious year).  Natural Gas output in FY'2014-15 was 33.58 billion cubic metres (BCM), a 5% decrease from FY'2013-14 output of 35.39 BCM. Output of ONGC and PSC-JVs declined by 5% and 7% respectively, compared to the brvious fiscal. hereas OIL production increased by about 4%. The significant fall in annual gas output from the East Coast field operated by a private consortium contributed to the shortfall in cumulative gas output of the country.

Consumption of Petroleum Products

Domestic petroleum products consumption picked up significantly by 4.2 per cent y-o-y during 2014-15 (165 MMT), as against meager growth of 0.6% per cent y-o-y growth achieved in 2013-14 (158 MMT).Four major products i.e., HSD (42.1% of total consumption), Motors Spirit (11.6%), LPG (10.9%), Petroleum Coke (8.7%) and ATF (3.4%) accounted for 76per cent of total petroleum products consumption. These five products accounted for 7.9per cent increase in consumption. On the other side, Naphtha, SKO, Bitumen and other products recorded decline in consumption by3.9%. Consumption of Petroleum Coke increased mainly due to increase in its use in cement industry and power generation. Motor Sprit (MS) consumption increased due to higher consumption by the passenger vehicles which registered a substantial growth in sales (3.9%) during the year. Lower petrol prices also had an effect on consumption. LPG consumption had a positive growth of 9.4% due to increase in number of customers from 166 million in 2014 to 182 million in  2015.

Total crude oil import for FY 2014-15 was 189.43 MMT almost same as the imports during FY 2013-14 (189.24 MMT; increase of 0.1%). However, import of petroleum products (20.28 MMT) increased by 21 per cent on y-o-y basis, mainly on account of increase in import of LPG  (26%), MS (58%), HSD (35%),Bitumen (80%), and other products like - Aviation gas, Pet Coke (33%), etc. Petroleum products export declined for the first time in last 15 years; registering a decline of 6.2per cent mainly on account of decline in export of Naphtha, Fuel oil, Bitumen, etc.

with total import (crude and petroleum products) combined with total products export of 63.66 MMT translates to net import volume of 146 MMT for FY 2014-15. Net import bill for crude oil during FY 2014-15 was Rs.6,873.50 billion (US$ 112.75 billion) against Rs.8,648.75 billion (US$ 142.96 billion) during FY 2013­14 - a decrease of 20.5 per cent in terms of the Indian Rupee and decrease of 21.13 per cent in dollar value mainly on account of lower crude oil prices in the international market.

Crude oil Price: Indian Basket

Crude oil price of the Indian basket averaged US$ 84.16 per barrel (Rs.5,143 per barrel) during FY 2014-15 compared to US$ 105.70 per barrel (Rs.6,380 per barrel) in the brvious fiscal (FY 2013-14); a decrease of 20.4 per cent in dollar terms (19.3 per cent in Rupee term). Slide in oil prices started from August 2014 and recorded lowest average of US$ 46.59 per barrel during January 2015. Subsequently, it climbed up toaverage US$ 55.18 per barrel during last month (March) of the fiscal 2014-15.

The registered decrease has been mainly due to lower crude oil prices in the global market due to comfortable crude oil supply scenario and other geopolitical and economic development, as detailed earlier in the report.

Diesel deregulation

The Government's move to decontrol diesel prices, like MS (Petrol)with effect from October 18, 2014, midnight, was one of the salient highlights of the last year in terms of its overall impact on the finances of the state oil companies and the government's fiscal balances. It also reaffirmed the reformist disposition that the government has embraced in dealing with matters of national economic significance and fuel subsidies, most certainly, featured high among the concerns that the government identified for focused intervention. From FY'2010-11 to FY'2014-15, under-recoveries in diesel amounted to Rs.2,817.31 billion, accounting for more than half of the total under-recoveries (Rs.5,458.54 billion) during those five years. From the point of view of oil companies, money saved by way of reduced outgo on subsidies could be put to use in funding programmes that cater to strengthening the country's domestic supplies, thereby reducing our increasing reliance on costly imports. A direct impact of this move will be on the government's fiscal deficit situation, profitability of domestic upstream players and cash flows of oil marketing companies on account of reduction of under-recoveries.

Under recoveries on sensitive products

Complete deregulation of the fuel, effectively linking diesel to market price movements, marks a desirable completion of a process that started off with its phased deregulation or periodic revisions in early 2013. It must be noted that the period of staggered price corrections had already primed the customers for a more market-based system and when the dramatic slide in global oil prices set in, the market conditions were the most opportune for the government to remove the element of state of control from diesel prices. In doing so, the government has relayed the right signals to all stakeholders and potential investors about the intent and direction of reforms in the domestic oil and gas sphere.

The real test, however, many say, of the decision will be in a period of higher oil prices given as the move was achieved in a time of exceptionally low global crude prices. But in view of the continued commitment of policymakers to the earlier move to deregulate petrol prices and the results that have followed thereof, there are sufficient reasons to believe that the current move to free prices of diesel will remain untouched through changes in the market environment.

Under-recovery on sensitive fuel (HSD, SKO & LPG) for the fiscal FY'2014-15 has been Rs.723.14 billion; 48.3% lower than the fiscal FY'2013-14 (Rs.1,398.70 billion). Under-recovery declined for consecutive two years mainly on account of lower prices of Indian crude oil basket. Also, it can be construed as the result of the Government's decision to deregulate diesel prices. Out of total under-recovery of Rs.723.14 billion in FY'2014-15, the upstream companies shared Rs.428.23 billion (59.2 percent) compared to Rs.670.21 billion (47.9 percent) during FY'2013-14. The Government's contribution has been Rs.273.08 billion (37.8 percent) against Rs.707.72 billion (50.6 percent during FY'2013-14); while Oil Marketing Companies (OMCs) contribution was Rs.21.83 billion (3.0 percent) compared to Rs.20.77 billion (1.5 percent of the total in FY'2013-14).

Your Company shared Rs.363 billion towards the reported under-recoveries of OMCs in FY'2014-15 as per Government of India (GoI) instructions - a decrease of 36 percent over its share in FY'2013-14 (Rs. Rs.63.84 billion). This translates to Rs.0.2 percent of the total under-recoveries and 84.8 percent of the share for upstream companies.

The average gross price for ONGC's crude oil during FY'2014-15 has been US$ 85.28/bbl compared to US$ 106.72 in FY'2013-14, drop of 20.1per cent. However, as per the Government instructions pertaining to the subsidy-sharing mechanism, ONGC offered an effective discount of US$ 40.4/bbl (US$ 65.75/bbl in FY'2013-14) to OMCs on the sale of crude oil. During the fourth quarter of FY'2014-15, ONGC did not have to bear any discount. Net realized price for every barrel of crude sold in FY'2014-15 for ONGC has been US$ 44.87/bbl, an increase of 9.5per cent compared to FY'2013-14 (US$ 40.97/bbl).

Gas Price Revision

The Government, after extensive discussions in policy making circles and consultations with the various agencies and stakeholders of the domestic energy setup, implemented the much-awaited decision to hike natural gas prices within the country on October 19, 2014. As per the decision, domestic gas prices were increased from the then existing US $4.2 per mmBtu to US $5.61 per mmBtu on net calorific value (NCV), or roughly 33 per cent, effective November 1, 2014 with subsequent revisions every six months. Needless to say, the increase in gas price has come as a huge relief to the upstream players of the country, particularly your Company ONGC. Natural gas was losing its market share in India due to expensive LNG imports and lack of domestic supply.

The latest round of revision to the gas prices, which were implemented on April 01, 2015, saw a reduction in domestic gas prices from US $5.61 per mmBtu to $5.17 per mmBtu on NCV basis for the period between April 1 and September 30, 2015 which essentially reflects the significant drops in global crude oil and LNG prices.

Reform measures: Introduction of more open-  market elements

The reform measures like decision to decontrol diesel prices, gas price revision, rationalization of under-recoveries is a strong indication of the government's drive to introduce more open-market elements into the domestic hydrocarbon business, and gives a timely fillip to investors' sentiment which had weakened in recent times as a result of ongoing uncertainty around key policy decisions. The revision of gas prices, in particular, is expected to incentivize production from new gas reserves, the development costs of which have steadily increased over the years given that most of the promising finds of recent times, as is the trend world over, have been in difficult-to-produce areas.

what this price revision has also helped achieving is the transition from the existing multiple pricing regimes in gas to a uniform price structure as the revised gas price would be applicable to all gas produced from nomination fields given to ONGC and OIL India, NELP blocks, such Pre-NELP blocks where PSC provides for Government approval of gas prices and CBM blocks. However, production from logistically or operationally challenging terrains such as deep or ultra-deepwater and High Pressure High temperature zones will be accorded a special pricing regime owing to its special circumstances, the brmium to which is currently under determination. Clarity on brmium for producing from difficult areas will help incentivizing greater participation from  international players which in turn will facilitate introduction of advanced technologies in the sector.

The increased gas prices will, though, make power plants and fertilizer units more expensive. Every dollar increase in gas price will lead to a Rs.1,370 per tonne rise in urea production cost and a 45 paise per unit increase in electricity tariff (for just the 7% of the nation's power generation capacity based on gas). Also, there would be a minimum Rs.2.81 per kg increase in CNG price and Rs.1.89 per standard cubic metre hike in piped cooking gas (Source: Business Today; October 18, 2014). Despite these cost implications, it is a worthwhile move in view of the overall development of the energy infrastructure of the country, and one that is inherently essential to the creation of a competitive, remunerative and attractive domestic gas market.

4. Operational Performance

FY'15 saw yet again the improved performance in bringing the planned and anticipated oil & gas volume on the surface. Oil & Gas production of ONGC Group, including PSC-JVs and from overseas Assets for FY'15 has been 58.33MMtoe (against 59.21 MMtoe during FY'14). The major upside came from the Western Offshore fields which registered a growth of 7.5%. Overseas assets also registered a growth of 6% in production.

Out of the total crude oil production of 31.47 MMT, 71 percent production came from the ONGC operated domestic fields, 17 percent from the overseas assets and balance 12 percent from domestic joint ventures. As far as natural gas production is concerned majority of production (82per cent) came from ONGC operated domestic fields and of the remaining, 12per cent came from overseas assets and 6 percent from domestic joint ventures.  Oil and gas production profile from domestic as well as overseas assets during last five years are as given below:

Proved reserves

During the year, your Company made 22 oil and gas discoveries in domestic fields (operated by ONGC). Out of 22, 10 discoveries are in Offshore area and 12 in Onshore area. Ten discoveries were made in the new prospects whereas 12 were new pool  discoveries. Seven discoveries were made in NELP blocks and fifteen in the nomination blocks. Out of the discoveries made this year, 7 discoveries are oil bearing, 9 discoveries are gas bearing and 6 discoveries are both oil & gas bearing. Position of proved reserves of your company is as below:

6. Peer Review

Continuing its dominant position since all those long years, this year too, your Company has been the  largest producer of oil and gas in the country (from its domestic operations) contributing 69 per cent of oil and 70 per cent of natural gas production.

ONGC's finding cost has been US$ 7.0/boe (3 years' rolling average up to FY'14) and lifting cost (including royalty) US$ 8.6/boe (3 years' rolling average up to  2014) has been well competitive with respect to the  global peers.

7. Opportunities & Threats

'The more the things change, the more they remain the same'. It would be difficult to come up with a more pertinent exbrssion to describe the flux and churn that characterised the energy industry, especially the oil and gas sector, in the last one year. Technology created new avenues of opportunities and with those opportunities came a new wave of optimism, adventure and aggressive activity in the business that lent well to a strengthening bullish sentiment on the future outlook for E&P operators globally. Challenging projects were approved and undertaken brmised upon the high and stable oil prices; NOCs moved ambitiously into the international arena, once the brserve of the global oil majors, to cater to the ever-growing demand for energy back home even as the established players moved further into more difficult terrains in a bid to retain their relevance as well as lock in their future avenues of cash and growth. And the supplies just kept growing, but demand didn't move in tandem.

And then the prices tanked in the backdrop of a global economic recovery that was largely inconsistent and not so confident. Suddenly, projects began to look suspect and the enthusiastic projections about the steady growth of supplies hung in the balance. Cost-cuts and budget or portfolio rationalisation became more common in practice as operators scrambled to either keep businesses afloat or protect their margins while simultaneously contending with mounting debts, irate shareholders and the threats of losing market share. A grim landscape but a situation not unfamiliar for the oil and gas sector.

Even in this scenario, there are opportunities to be tapped into and the companies that do manage to balance their risk mitigation templates with an acceptable degree of growth-oriented approach will stand to benefit the most once the tide turns. Some are already doing that - be it through efficient technology deployment or capital investment. IHS Energy expects

a 25-30% gain in the average efficiency of onshore upstream capital investment in 2015 versus 2014 and a gain of 45% when comparing 4Q2015 to 4Q2014. Eventually, the criticality of the sector does not allow it to remain passive for long, and it is those companies which are adaptive and clued in to changing context that can potentially be at the forefront of the next cycle of high growth.

As per BP Energy Outlook 2035 (published in January 2015), global energy demand is projected to expand by 37 per cent between 2013 and 2035. The energy mix will undergo changes during this period: renewables (including biofuels) are expected to grow from its current share of 3 per cent to 8 per cent globally while the contribution from nuclear and hydro sources remains largely static in this time frame. Although its cumulative share in the basket comes down, fossil fuels continue to be the dominant source of energy with a share of 81 per cent in 2035. Essentially, the oil and gas industry, irrespective of the many extraneous challenges it faces and the sharply cyclical nature of its markets, will remain fundamental to the pace of global economic and social growth. Global liquids demand (oil, biofuels, and other liquids) is projected to rise by around 19 mbpd, to reach 111 mbpd by 2035 whereas demand for natural gas, the fastest among the fossil fuels (1.9 percent), fuelled largely by global transition to cleaner energy sources, reaches 4,900bcfpd in 2035.

Virtually, all of this growth in energy demand is slated to come from non-OECD countries (96 percent) and with China (as mentioned earlier) markedly decelerating from its turbo-charged growth trajectory of the past decade the focus shifts to India in terms of not just picking up the slack but also providing the next big boost to global energy consumption. The IEA's Medium Term Oil Market Report (2015) tips India, currently the fourth largest energy consumer in the world, to upstage Japan as the world's third largest oil consumer by an expanding economy and a robust demand driven by factories and the automobile sector. Overall, India's energy production rises by 117% to 2035 while consumption grows by 128%.This projected supply deficit then has the potential to further compound the stress for an economy that is already hugely reliant on costly imports. Herein lies the enormous opportunity for all the stakeholders in the energy sector in India. The task is huge for Indian companies particularly for your company, ONGC, the flagship energy company in this highly strategic and nationally critical sector.

hat has really aided the growth of the sector and motivated oil and gas operators across the globe to persist in the pursuit of all current and emergent opportunities is the technology evolution in the industry over the past few years as companies have consistently extended the boundaries of frontier exploration and successfully realized volumes from resources that were hitherto deemed commercially unviable or geologically difficult. The unconventional blitz in North America is a fitting testament to the possibilities that have been unlocked through the technological breakthroughs of the past years. Although the brsent low oil price regime, with companies having executed an average of 30 per cent capex cuts, makes riskier upstream projects and aggressive exploratory targets less viable, the companies that continue to judiciously invest in upgrading their technological base and improving their efficiencies in technology application will remain better positioned than others to weather the ongoing downturn in prices

It must not be forgotten that, despite the oil price blip the last one year or so, the industry has generaw itnessed strong returns from frontier exploratio  of  ally  (@13%), from mature fields (@16%) and from emerging basins (@15%). So, once the prices recover, the push for projects that bring new oil into the market will return with renewed vigour and confidence. Till such time when prices stage a reliable turnaround, the "Value over Volume" approach, a trend which had already found takers among big oil companies even in the high oil price scenario of 2013, is expected to intensify in the upstream space as companies keenly commit to maximizing production and returns from existing reserves and producing streams in lieu of expending resources to pursue volume potential in frontier areas. The threats of high breakeven costs are further compounded in the brsent scenario as many of these new oil projects (~3.5 mbpd) need break­even of US$ 60-80/bbl. Companies, in the current situation, are most likely to defer high-cost drilling in favour of lower-cost, lower-risk options. Notwithstanding the exploratory budget cuts, the industry will also experience an average 33 percent cost exploration cost as a result of weakening exploration activity and tapering demand for drilling services. Lower exploration costs will help reduce breakeven prices and improve full-cycle economics by up to US$5/boe. Some of the best improvements will be in deepwater plays. Although just half of the cost deflation gains are expected to be enjoyed in 2015, the full benefits will filter through to E&P players in 2016. For example, seismic acquisition costs are down by 50 per cent making seismic acquisition a low-cost option to continue progressing on frontier acreage. Also, E&P companies are likely to persist with their activity in basins with running room where geology is better understood and infrastructure is in place, which both reduce cycle times. The time is right for STRONG EXPLORERS to capitalise and "do more with less", increasing their drilling in high-impact plays. Also, unique factors in certain regions will act as local props to exploration - commitments in Angola's Kwanza Basin, lease expiries in deepwater Gulf of Mexico (GoM), strong gas prices in the Netherlands. What this period of relatively lean exploration also offers is the opportunity for geoscientists and geologists perform more rigorous analysis of data and thereby improve the quality of the prospect pipeline. The 2010/2011drilling moratorium in GoM had a similar effect and arguably led to a stronger prospect inventory and healthier results in the past two years. A common refrain among upstream players over the last decade has been the diminishing frequency of big-sized finds and how that has further jeopardized the prospects and optimism around the sector in a situation where cashflows are further squeezed. But it does not necessarily mean smaller fields become complete non-starters as IHS-CERA says it is not uncommon to see long production life for small fields -close to 20% of fields in the size range of 20 to 500 Mmboe have been producing for over 50 years. Steady evolution of technology and its effective deployment has resulted in extending field life cycles. IHS estimates that potentially upwards of 140 bboe remains in existing, low-quality oil fields, based on a high-level assessment. And existing reserves are being continually revised upwards as new API tools and techniques become mainstream and are integrated in current models. Right there, that's a substantial opportunity for oil and gas companies. Your Company's time-bound and technology-intensive IOR/EOR schemes and clustered approach to development of marginal fields are a proof of the additional value that can be commercially unlocked from existing producing pools or standing reserves. However, for financially stretched companies, these are undeniably difficult times to negotiate. As mentioned earlier, many of them will intensify their search for partners to sustain the business or even shore up their viability. Even companies with strong balance sheets will be more open to partially farm- down their equity to stretch their budgets further. On the other side of the negotiating table, companies seeking farm-in opportunities will be selective - most will be looking to plug gaps in their portfolio, or bolster existing positions.

At a more macro level, the ongoing debrssion in global crude prices have ushered in a context where countries, governments and regimes have been forced to reassess their stance on how they want to exploit or want to incentivize the exploitation of their energy resources. To that extent, it would be fair to say that the threat of resource nationalism which had loomed worryingly on the fortunes and expansion plans of E&P companies globally has receded in recent times after this most recent onslaught on prices. Companies will want to rationalize their expenses and planned investment, which means it is not merely the size of the resource base, although that will remain a major factor, that will determine where companies choose to make their commitments. ith growing abhorrence for fiscal and policy instability in corporate boardrooms, terms offered in licensing rounds may need to be adjusted to increase attractiveness in a world where the worth and returns of every dollar spent comes under ever increasing scrutiny.

Though good hydrocarbon assets have been located in East Coast Africa and Latin America, clarity on key issues of energy policies, fiscal and regulatory regimes are yet to evolve. More delays on these fronts could result in money being directed to more stable and remunerative regimes. And countries are responding to this threat: Myanmar and Suriname negotiate each PSC after the conclusion of the bid round, and changes are already under discussion in Myanmar for contracts awarded following the 2013 round. Tanzania may soften its PSC terms for the next round. In Mexico, PSC terms put forward for shallow water exploration have been met with disappointment by the industry, putting brssure on the authorities to sweeten them. Iran, soon expected to become a full-fledged participant in the oil markets after a long hiatus once the nuclear negotiations reach an agreeable resolution, is busy drafting a modified petroleum contract with improved commercial terms in a bid to revitalize their flagging oil industry.

Particularly, for Africa, which brsented itself as an emerging hotspot in global energy circles, the threat posed by the oil price slide to its aspirations as a future hub of new supplies is very real. Delays are likely in many of its capital-intensive deepwater projects and LNG supply projects that were expected to be sanctioned in 2015. Here, too, operators have chosen to defer FID decision to take full advantage of falling costs. For countries in the region such as Mozambique or Tanzania, it then becomes undeniably imperative to  use the current downturn to bring in greater clarity and transparency to their fiscal and policy frameworks to retain investor interest through the turmoil.

Coming to LNG, opportunities in the sector have definitely been weighed down by the implications of low oil prices regime as majority of current term contracts are oil-linked. IHS expects prices to drop considerably in 2015versus last year. For example, Japan's weighted average import price for 2015 is projected to be below $10/mmBtu, as opposed to nearly $16/mmBtu in 2014. Spot LNG prices have already plummeted. Even before oil prices began to fall last year, the LNG industry faced significant challenges with significant supply overhang (owing to sub-optimal demand) and serious project cost escalations that threatened the viability of many greenfield LNG projects that require substantial capital investment and strong returns. But an upside of low prices is that the industry could bring in new customers and that, to a degree, should offset the threat posed by coal as a feed fuel for electricity generation or industrial purposes, particularly in Southeast Asia where the rise in demand for power generation is likely to be the most intense. However, despite the realities of the current ecosystem that the sector has to contend with, the long-term outlook of LNG remains robust considering the abundance of gas resources and the its proposition of LNG as a cleaner energy source. Also the breakeven costs for most greenfield projects are in tandem with projected oil prices in the longer term. So, although companies will be disinclined to invest in new projects in the current cycle, developers who take steps to minimize costs and stay invested in promising projects will reap the benefits when prices trend north. Globally, the surge in the activity related to unconventional hydrocarbons has been stymied to an extent by the steep fall in prices. Nonetheless, leading explorers continue to add unconventionals to their portfolio while keeping their conventional reserves steady, largely because the returns from the particular resource base is quite compelling, particularly with liquids-rich plays as their returns often exceed that from conventional exploration. In fact, the US shale or tight oil sector which was expected to be hardest hit due to the low prices has discovered greater efficiencies in drilling and withdrawn from non-core areas in a manner that has made unconventional supply growth possible even as rig counts have declined to record lows. Although the pace of growth has slowed, and supplies are projected to start contracting in the latter half of 2015, it is far from the grim picture that many in the industry had foretold at the time when prices started declining. This resilience has, in turn, allowed countries such as Argentina and China, despite dissimilar geologies and regulatory regimes, to remain enthusiastic about unconventional hydrocarbons and invest capital and resources to put in place the necessary infrastructure and policies conducive to the shale industry. Having said so, fossil fuels are expected to face good threat from renewable in medium to long term. Renewables percentage in total energy supply continues to rise growing at the rate of 6.4 percent per annum thereby registering a share of 7 percent by 2035 as compared to around 2 per cent today. Nuclear energy will keep growing 1.9% per annum and hydro-electric growing 1.8% per annum. All these taken together (39%) will be responsible for much larger contributor of growth during 2025-35 periods as compared to those from liquid or natural gas. As in longer run, this higher percentage of renewable, owing to continued greener push, offers a good threat to fossil fuel based industries like that of ours. Talking specifically for India, huge potential still lies with Indian oil and gas explorers and producers. ith more than 28 billion tonnes of prognosticated reserves, Indian sedimentary basins have good potential. However, with 12% areas still unexplored and 22% areas which are poorly explored, huge pools of prognosticated resources are waiting to be converted into in-place volume. In India, only 7 basins are producing (out of 26) and exploration is yet to be initiated in 11 basins. This provides a huge opportunity for all explorers, like your Company, to convert these remaining basins into a producible proposition. On production front, so far our recovery factor has been quite low (around 30% or so on average) as compared to matured fields of similar vintage having recovery factor around 45% plus. This offers a huge opportunity as a lot of oil is still left in those reservoirs. As mentioned already, ONGC is increasingly pursuing the agenda of improving recovery factor through technology and capital intensive interventions, and aims to increase recovery factor to 40% by 2020. In FY'15, over 34 percent of the Company's domestic crude oil production was accounted for the incremental oil extracted through its IOR/EOR schemes. But considering the increasing costs of the marginal barrel of oil, innovation and technological improvements are a must for continued viability of such endeavours.

8. Risks and Concerns

The oil and gas industry, owing to its fundamental importance to the global economy and world affairs at large, is influenced by a wide variety of factors and players which together through their resultant tension determine the direction and position the market assumes during a given period. The spectacular drop in oil prices which was the headliner theme of 2014's panorama of the energy industry was the end-result of  an interplay between many such determinants. Geopolitics, despite its characteristic brsence in the scene through the worrying episodes of unremitting disturbance in places like Libya, Iraq and Ukraine, was outweighed in significance in terms of its influence on the markets by the growth indices of the global economy and, more importantly, the fundamentals of energy demand and supply.

This volatility and pronounced cyclicality makes 'oil and gas' one of the less easy places to do business in. Add to this, the sheer sbrad of operations and the variety and complexity of regimes and geologies that companies have to deal with on a regular basis to make their businesses tick further add to the weight of the challenge. Inevitably so, such multitude of risks and possible ramifications for any given event make it imperative for oil and gas players to continuously assess the new and developing strains of their immediate and wider ecosystem. Subsequent to what we saw in 2014 and what we have seen so far in 2015, there are some primary concern areas that are expected to remain relevant in the near or even medium term for oil and gas operators as they negotiate affairs in what can only be mildly said to be an 'infirm' climate.

Crude prices, given its wide-rangingand deep impact, will be at the top of every company's agenda. Price forecasts and supply-demand trends form a routine part of the industry's analysis of the current state of affairs and its outlook going forward but those, with their strong bias towards the status quo, can only provide you with so much information with so much certainty and the current downward spiral is one such strong example. But they are important nonetheless, more so in uncertain times like now.

- The International Energy Agency (IEA) in its May 2015 Oil Market Report projected a strengthening of global demand growth from 0.7 mbpd in 2014 to 1.1 mbpd in 2015. Despite the pick-up in demand, global supplies continue to be on a strong footing with a y-o-y growth of 3.2 mbpd in April 2015 as slowing US tight oil output growth is offset by higher OPEC output. Projected demand and supplies for 2015 are 93.6 mbpd and 95.7 mbpd respectively. As such, the recent rally(April and May 2015) in crude prices cannot be expected to be sustained through the rest of the year.

- US Energy Information Administration forecasts Brent crude oil prices will average US$61/bbl in 2015 and US$67/bbl in 2016.West Texas Intermediate (WTI) prices in both 2015 and 2016 are expected to average $5/bbl less than the Brent price.

- Energy Consultancy IHS Energy has brsented an outlook for Brent at an average of US$58.92/bbl in 2015 and US$65.50/bbl in 2016. The firm expects robust global demand growth of 1.3 mbpd in 2015 and 1.1 mbpd in 2016 but a combination of high grading of drilling sites and cost reductions in US unconventional sector and greater OPEC output will continue to keep the market oversupplied through 2016.

with tighter operating margins, companies will face it increasingly difficult to generate the kind of returns that have big E&P firms the darlings of the community of investors. Not just this, companies that do not enjoy the luxury of healthy cash reserves or are already highly leveraged will find even the management of day-to-day operations a challenging proposition. The brvalent circumstances, thus, in a way, are priming the market for an environment that would be ripe for strong M&A activity, although companies will want plunge in only after prices are deemed to have settled down and execution of rigorous portfolio assessments.

For producing countries, the degree of dependence on oil revenues, the availability (and liquidity) of financial reserves and/or access to external financing will help to determine their economic and political resilience.

Another concern is how the oil field service providers steer their activities in this oil price regime. They are feeling the heat. As outlined by one study, Oilfield contractors will have to lower prices by as much as 20 percent to help keep their cash-strapped customers working.

Not surprisingly, for your Company too, the last one year has not been all easy going amid the surrounding uncertainty and volatility that has gripped the markets despite a lot of positive sentiment in the domestic environment arising out of the government's progressive stance on reforms and policy making. Financing of new projects, particularly in matured field areas to boost recovery rates and in new & marginal fields and also in deep-water areas to realize fresh volumes, has certainly come under a squeeze in the brsent market reality. Of course, being an NOC with a national mandate for securing energy needs of the country, we are fully seized of the significance of our sustained performance in situations of any stripe. And ONGC's performance in the last concluded fiscal does more than attest its strong fundamentals and operational excellence.

Globally, monetization of reserves has become a huge concern area with merely 30 per cent of recent finds being deemed commercial. This is largely a result of newer finds being made in more logistically and geologically difficult areas and the lack of availability of high-quality data for many of the promising finds which make their development highly prone to  operational surprises, as risk operators would rather not want to run right now. Complicating matters further are the myriad political interventions and accompanying policy instability that impede the evolution of a stable operating environment, a br­requisite for sustaining the confidence and interest among E&P players in host countries. So, not only is there a need for advances in technologies related to seismic data acquisition and reservoir modelling to develop a greater understanding of the reserves that await monetization but also a more transparent, stable and economically incentivizing regime to make development of the new reserves commercially more viable, particularly for the deep-water, ultra-deep-water, basement plays and HP/HT reservoirs and subtle traps.

Particularly for India, where more than two-thirds of its sedimentary basins remain largely under-explored, a facilitating fiscal and policy framework, be it in the form of relaxed financial terms or a more pragmatic land-acquisition policy, will go a long way in allaying the concerns around hydrocarbon prospectivity and associated commerciality of finds among all current and potential players in the upstream oil and gas landscape. Moreover, the country's recent finds which are mostly medium-sized at best and the fact that its foray into unconventional hydrocarbons, be it CBM or Shale, is still very much at an incipient stage further accentuate such a requirement. Coming to the domestic production situation, till such time when a 'breakthrough, game-changing find' is made, effective brown-field management is the only reasonable way to sustain supplies at brsent levels as a major portion of your Company's output is attributable to mature fields. Arresting declines from these legacy assets through cost-intensive operational schemes is a challenge, more so in a low oil price scenario. Continued investments in these programs will warrant greater clarity on issues such as the subsidy sharing mechanism as further erosion of our profit margins could significantly compromise future exploratory and development pursuits. Also, the existing technological gaps in the areas of work-over operations, non-flowing wells, deep water drilling etc. do poses some risks for improving upon production volumes.

Operational safety is a fundamental concern in the oil and gas sector given the degree of risks that the companies are routinely exposed to and the potentially worrying ramifications of any untoward event as tellingly borne out by the Deepwater Horizon disaster in the Gulf of Mexico. Many of these risks - be it spillage, rupture, blowout of wells, earthquake, tsunami or terrorist activities etc. - are being mitigated right from design stage; however probability of emergency situations cannot be totally eliminated.

However, ONGC has implemented improved OISD Standards to improve contingency combat capabilities. ONGC offshore assets have been rated under 'acceptable risk' by international underwriters, enabling a lower-than-peer insurance brmium for these assets.

One of the more important highlights of the latest BP Statistical Review of orld Energy (2015) was that carbon emissions in 2014 grew the slowest (0.5%) since the 1990s. Perhaps, it was China's slowing growth or its choosing to be a more consumption-oriented than investment-intensive economy which meant less energy consumption, or the developed economies achieving greater efficiencies in energy consumption and generation that contributed to this slowdown in emissions, but, going forward, it is a trend that can be expected to become increasingly common as sustainability and cleaner energy become mainstream concerns of businesses globally than mere academic concerns.

Globally, the 'big crew change' has become a priority concern among the best of companies. In USA, for example, as per US Department of Labour estimates, 50% of the oil and gas industry's workforce will be eligible for retirement within the next five to ten years. In India as well, oil and gas companies need to deal with this impending crisis of talent assignificant retirements are expected in the sector by 2020, not only are companies staring at a loss of significant capital of experience and expertise with these exits, the fact that they also have to replenish from a talent pool that is already quite lean and scarce further compounds a situation that is already quite alarming for them. The resultant knowledge gaps between new employees and experienced industry leaders may affect the efficiency, efficacy and deliverability for the company. ONGC has also been witnessing a large number of retirements over the last few years. Though it is very difficult to replace such a huge pool of experience, your Company has taken it as a challenge and has been taking all-out efforts to address the situation through redeployment of its manpower and also through induction of sizeable number of young executives to take care of the future. Some small yet significant concerns do exist because of less evacuation of gas by GAIL, in particular from Eastern offshore and Rajahmundry Asset and also in Gujarat. The gas sales are also getting affected by lack of customers in isolated fields in Assam and at other onshore locations. Increasing availability of cheaper alternatives has led to replacement of naphtha and other liquid fuels. Naphtha has already been rendered surplus in various regions and overall in the country. Your company has been putting in efforts to tie-up with consumers for sustained sale of various liquid products.

9. Outlook

a. Exploration acreage & mining Lease

Your Company holds the largest exploration acreage in India as an operator. Despite deregulation and increasing private participation, your company holds54% of PELs and 81% of ML (Reference: DGH, Hydrocarbon E&P Activities Report 2013-14). So far, your Company has established7,644MMtoE of In-place volume of hydrocarbon in domestic basins. As on 01.04.2015, ONGC is holding a total of 338 PMLs with total area of 56,335 Km2. ONGC added 1,671.60 Km2 areas to PML. ONGC has 10 nomination PELs with approximate area of 37,818 Km2.As the validity of these 10 PELs is going to expire soon, ONGC has accelerated exploratory efforts in these blocks with focus on drilling of maximum identified potential prospects before the PEL expiry so that the maximum PML conversion can be achieved.

b. Exploration

During the year 2014-15, ONGC has made 22 Oil and gas discoveries in domestic fields (operated by ONGC). Out of 22, 10 discoveries are in Offshore and 12 in Onshore; 10 discoveries were made in the new prospects whereas 12 were new pool discoveries. 7 discoveries were made in NELP blocks and 15 in nomination blocks. Two discoveries (Rudrasagar-184 & Gandhar-699) of Nomination blocks have already been put on production and efforts are on for bringing the other discoveries on production as early as possible. Seven discoveries in NELP blocks (5 on-land, 2 offshore) are governed by the PSC guidelines and appraisal/development activities will be taken up keeping in view the timelines of the respective blocks. In addition to these discoveries, exploratory wells conclusively tested and proved to be hydrocarbon bearing will help in field growth of existing fields.

c. NELP Blocks

Your company was awarded 114 NELP blocks as  operator (including KG-DWN-98/2, KG-ONN-2003/1 &  VN-ONN-2003/1) and at brsent (as on 1st June 2015) is operating in 41 blocks. In addition ONGC had participative interest (PI) in 10 NELP blocks, where it is not operator. Out of these 10 blocks 3 blocks have been surrendered; as such it has PI in 7 active blocks. A total of 53 discoveries (21 in deep-water, 10 in shallow water and 22 in on-land) has been made in 22 of these NELP blocks (6 deep-water, 6 shallow water & 10 on-land) as on 1st June 2015. Commencement of production from these discoveries is governed by stipulations laid down in the respective PSCs and is to be taken up after successful completion of appraisal programme followed by submission of DOC and approval of Field Development Plan Production has already been started in 4 on-land NELP blocks (Vadatal#1, West Patan#3, Karannagar#1, and Nadiad #1) in Gujarat. For one discovery, FDP is under approval; for 5 discoveries, FDP is under review by MC and DOC has been submitted for 5 discoveries. 3 discoveries were sub-commercial as such these have been surrendered; another two discoveries are under study. Rest of the discoveries are under appraisal stage.

d. Redevelopment of existing matured fields

Your company is striving hard to improve the production volumes because the majority of the fields have become aged and matured. 14 of ONGC's major producing assets are of the vintage of 25-50 years and contribute around 68% of total domestic productions. Despite being of such a long vintage, silver lining is that those matured assets are still left with significant recoverable volume with recovery factory hovering around the figure of 30-35%. ONGC is pursuing larger objectives of enhancing productions from these matured fields through capital and technology intensive drive through Improved Oil Recovery (IOR) mechanism like Redevelopment and Enhanced Oil Recovery (EOR). Facilities are getting revamped and upgraded to ensure that the new volumes which are coming from the changed reservoir parameters are getting adequately processed to meet the requisite quality standards and dispatch parameters. At brsent, your Company is pursuing a number of projects both at Offshore and onshore areas. These together are expected to give us an incremental cumulative production volume of 185 MMT of oil (in its project life cycle) through an overall investment of 1 550,000million. These are being pursued since a decade and half back in order to enhance the production and improve the recovery factor 21 of the 26 projects have so far been completed and an investment of Rs.361,870million has already been made till 31st March'15. Two projects i.e., "Heera & South Heera Redevelopment Project" and "Development of estern Periphery of Mumbai High

South" project is likely to be completed by Mid FY'16 and the remaining three projects i.e., "Redevelopment of Mumbai High North Phase-III", "Redevelopment of Mumbai High South Phase-III" and "Additional development of Vasai East"will be completed by the year 2017-18. Redevelopment efforts, as on 31st March'15, have fetched ONGC an incremental oil volume of 94.66 MMT. During FY'15 alone contribution from these schemes have been incremental volume of 7.19 MMT of oil (34.5% of ONGC's domestic crude oil production on standalone basis).

e. Development of new fields

Your Company took up 15 projects for development of 39 new/marginal fields with an investment of Rs.386,024million. Out of these 15 projects, 11 projects have already been completed. Production from development of G-1 & GS-15 fields has already commenced. Rest three projects, Development of WO-16 Cluster, C-26 Cluster and B-127 Cluster, are under implementation and are expected to be completed in FY'17. These new/marginal fields have yielded very positive results and contributed close to 14% of domestic crude oil and 15% of gas output in FY'15. Their contribution is expected to go up further during the fiscal FY'16, as current production streams peak and new projects get completed. Your Company has also invested greater focus and expedited work on new development projects - some of which will play a substantial role in ONGC's production profile in the coming years. ONGC has taken up 6 major field development projects with an investment of Rs.241,881 million. Expeditious development of deepwater block KG-98/2 is also part of our short to medium term growth plan.

infrastructure Projects

In order to comply with the international standards on safety, health, environment, sustainability, process, etc., and also to comply with the technical, statutory and production linked requirement of the fields, your Company is pursuing a number of re-engineering/ revamping and infrastructure projects for replacing the old infrastructure and creation of new facilities for smooth operations. As of 31st March' 2015, your company is pursuing 17 such infrastructure project; 10 in onshore at an investment of Rs.64,070 million and 7 in offshore with an investment of Rs.92,520million.

g. Unconventional Source of Energy

ONGC plans to continue its endeavour for exploration and development of Unconventional & other resources like Shale Gas, CBM, HP/HT, Fractured Basement plays etc. Your Company has prioritized suitable actions for exploration and exploitation of Non-conventional and Alternate sources of energy which has the potential to change the energy business landscape in the country, as it is happening in the other parts of the world. The initiatives by ONGC in these areas are summarized below

h. Exploration of Shale Plays

Your company has the distinction of establishing the first flow of shale gas in the country on 25thJanuary, 2011.Government of India during October, 2013 brought out shale gas policy which allows National Oil Companies Viz. ONGC and OIL to initiate the shale gas and oil exploration activities in their allocated nomination blocks in phased manner. Shale Gas exploration was initiated in 2013-14 keeping in view the YTF (Yet-to-Find) hydrocarbons envisaged from Shale Gas play. As per the new Policy, 50 nomination PML blocks have been identified in four Basins, including 28 PMLs in Cambay Basin, 3 PMLs in A&AA, 10 PMLs in KG and 9 PMLs in Cauvery basins for Shale Gas assessment within three year period of Phase-I. A total of 57 pilot/assessment wells are to be drilled by April 2017.

Up to FY'15, ONGC has taken up drilling of 14 wells for shale gas assessment in Cambay, KG, Cauvery and Assam & Assam-Arakan Basins. Out of which drilling of 8 wells were taken up during FY'15. In FY'16, ONGC has plans to drill 19 wells including 11 exclusive Shale Gas wells and 8 wells with dual objectives. Based on the results of planned exploration campaign, drilling of more wells mainly horizontal wells, multi-stage hydro-fracturing will be required to establish the production potential of envisaged shale reservoirs and their commerciality by unlocking unconventional shale gas and oil reserves in different basins.

i. Coal Bed Methane

Of the total thirty-three CBM Blocks awarded by GOI to various operators through four rounds of bidding and nomination, Your Company was awarded nine CBM blocks. Due to poor potential, concluded on the basis of the data generated in the exploratory activities, five Blocks viz. Satpura (Madhya Pradesh), Wardha (Maharashtra), Barmer-Sanchor (Rajasthan), North Karanpura (West) and South Karanpura (Jharkhand) have been relinquished.

Currently, your company is operating in four CBM Blocks i.e.,Jharia, Bokaro, North Karanpura (Jharkhand) and Raniganj (West Bengal),FDP of which has been approved. Nearly 400 wells and 2,000 hydro-fracturing jobs are required to be carried out in the coming 4-5 years as per timelines of the CBM Contract.

In view of the mammoth and time bound task, ONGC is in the process of farming out its Participative Interest to experienced CBM players through formation of JV. Farm out Agreement (FoA) was signed for North Karanpura Block on 7th October 2014. Documents have been submitted to DGH for Government's approval of PI assignment. Farm out of Bokaro Block is under negotiation. Formation of joint ventures for the blocks Jharia and Raniganj are under process.  

Underground Coal Gasification Your company in collaboration with GIPCL selected Vastan Mine block site in Gujarat as an R&D project to establish UCG technology. All the ground work and inputs for construction and implementation of UCG Pilot Project at Vastan, has been completed and further development is awaiting award of Mining Lease from MoC, GoI.

Further, a number of sites have been jointly identified by ONGC &Neyveli Lignite Corporation Limited (NLC) for studying their suitability to UCG. These are Tadkeshwar in Gujarat and Hodu-Sindhari& East Kurla in Rajasthan. One more site was jointly identified by ONGC & GMDC viz. Surkha in Bhavnagar district, Gujarat. The data of all the fields have already been analysed for evaluating the suitability of these sites for UCG. All the sites have been found suitable for UCG exploration.

Alternate sources of energy

Your Company is also pursuing green energy options. Though your Company is already generating wind power of 51 M, another 102 M wind farm at Rajasthan is likely to be commissioned by Sept-2015. ONGC Energy Centre (OEC), a trust set up by your Company, has contemplated a Geothermal Pilot Project in association with technology partner M/s. Talboom, Belgium in Cambay Basin, which has a high geothermal gradient. Thirteen Parametric wells in Suket-Jhalawar area of Rajasthan & three wells in Kaikalur area of Tamil Nadu taken up during FY'15 for Uranium exploration. OEC is also pursuing the Thermo-Chemical Reactor project for Hydrogen Generation; a collaborative projects with IIT-D & ICT, Mumbai. Three of these reactors are under installation. It is pertinent to mention that US Patent & Trademark Office has issued a Patent to ONGC Energy Centre (OEC) & Institute of Chemical Technology (ICT), Mumbai for the innovative research work on"Hydrogen Production Method by Multi-step Copper- Chlorine Thermochemical Cycle  

l. Other Exploration Initiative

Results of recent exploration activities clearly show that even well explored basins have provided unexpected positive surprises. Among these are HP-HT/Deeper plays and Basement Plays. Structured initiatives taken by your Company in this regard are as below.

HP-HT, Tight& Deeper plays

Your company has prioritized HP-HT, Tight&Deeper plays in KG onland & shallow water offshore, Good potential has already been established in Bhuvnagiri, Malleswaram, Periyakudi, Kottalanka, Bantimulli South, Yanamshallow offshore,GS-OSN-2004 and G-4-6. All these fields are expected to have large growth components to be established and vast potential area remains unexplored. Our long term plans envisage establishment of 500-740 MMT of in-place volume of hydrocarbons from such reservoirs, with cumulative production of 70-90 MMT(O + OEG). About 180 MMT of In-place hydrocarbon volume has already been established. Processesfor monetizing these established volumes are under finalization. Services of M/S Blade Energy Partners, USA have been hired to study the six discovered HP-HT/Tight Reservoir Fields. During the year 2014-15, 4 wells were drilled to probe HP/HT play including 1 well each in KG and Cauvery onland basins and 2 wells in KG shallow water. During 2015-16, 4 wells have been planned for drilling for HP/HT playin KG and Cauvery Basins.  

Basement Exploration

Basement rocks are known for hydrocarbon accumulation for many years. Concerted efforts for Basement exploration, a frontier exploration play has been taken up by your Company as a major initiative. Established hydrocarbon potential in Basement in estern Offshore (Archean Basement, Deccan Basalt) and Borholla-Champang fields are well known basement producers. Commercial brsence of hydrocarbons has been established in prospects like -Padra, Karjan, Halisa, Chadra and Mansa in Cambay basin. Hydrocarbon occurrences in basement in Mattur, Pundi, Vadatheru and Pondichery Offshore, and recent commercial discoveries around Mandam and Portonova Highs have rejuvenated exploration thrusts on Basement exploration. A collaborative research project with University of New South ales (UNSW), Australia has also been carried out for Heera field. One location was released in Heera Field to test the technology showcased by UNSW. During 2014-15, thirteen wells were drilled for Basement exploration in  estern Offshore basin, Cauvery and A&AA basins. Out of these, five wells proved to be hydrocarbon bearing including BH-69 & BH-72 in Western Offshore.

ONGC is focusing towards drawing an effective and successful Basement exploration strategy through special studies and modelling. Further Exploratory inputs for Basement exploration have been identified in prospective blocks/acreages of estern offshore, estern Onshore, A & AA and Cauvery Basins. Accordingly, drilling of 12 wells has been planned during 2015-16.  

Un-appraised Areas:

A concerted effort for resource appraisal of the un-appraised areas of Indian Sedimentary Basins has been under taken by DGH. ONGC is earnestly collaborating with DGH in identification and prioritization of the areas. ONGC would be involved in 2D seismic data acquisition in Un-appraised areas in onshore sectors of different sedimentary basins of India except in North east region.

10. Internal Control Systems

Energy business, particularly oil & gas, has always been a very dynamic business, not just because of its fundamental economic and strategic significance to the nations of the world but also because of the high-risk nature of the business. The business is challenged by uncertainties, geological surprises, volatile markets and number of external factors like-geo-political uncertainties, fiscal & regulatory regime, etc.

In such scenario, where the uncertainties are the rule, it becomes imperative to have a balanced portfolio. Keeping these in view, your Company adopted the vision to grow as an integrated global energy company. Exploration and production of oil and gas remains the core business of your Company; however, keeping in view the business imperatives, ONGC has meaningfully integrated itself in the hydrocarbon value chain. Now the portfolio of your Company (including overseas assets) is large, diversified and assuring.

To manage this large portfolio, your Company has institutionalized robust internal control systems to continuously monitor critical businesses, functions and operations; particularly field operations. The top management of your Company monitors and reviews the various activities on continuous basis. A set of standardised procedures and guidelines have been issued for all the facets of activities to ensure that best practices are adopted even up to ground level. Performance of every business unit is monitored by the respective directorates for suitable corrective measures, if any, in time.

Your Company has a dedicated Performance Management and Benchmarking Group (PMBG) which monitors the performance of each business unit against the Key Performance Indicators (KPIs) defined in the Performance Contracts between the top management and the Key Executives. These performance contracts are aligned to the goals and objectives of the organization.

As part of its push for systemic transformation and strengthening of control systems, your Company has placed adequate emphasis on institutionalization of tools, practices and systems that facilitate greater operational efficiencies and workplace productivity. Revamping of 'Material Management Manual' was carried out during the year to ensure procurement of quality materials and services and identification of world-class vendors. 'Book of Delegated Powers' (BDP) was revamped and implemented w.e.f 1st January, 2015, with the objective to empower working level officers and enhancement of delegation to put commensurate accountability on all decision makers. At the same time, Rig Bar Charts for planning and allocating resources for drilling operations was also introduced.

Your Company also introduced E-Grievance handling mechanism for quick redressal of grievances of the various stake-holders.

Occupational health, safety and environmental protection are the adopted motto of your Company. Achieving highest standards in these areas remains a priority objective for your Company. Internal and external audits have been institutionalised and are conducted on a continuous basis to ensure compliance tovarious industry norms and benchmarks.

Your Company has dedicated Internal Audit (IA) group which carries out audits in-house. At the same time, based on requirement, specialized agencies are engaged to carry out audit in the identified areas. Statutory auditors are appointed by Comptroller and Auditor General (CAG) of India for fixed tenures. Audits and Ethics committee of the Board oversees the functioning of Internal Audit and control systems.

Third party safety audits are conducted regularly for offshore and onshore installations by established national and international HSE agencies such as Oil Industry Safety Directorate ("OISD"), an organization under the control of the MoPNG, which issues safety guidelines. Further, subject to the safety regulations brscribed by the Directorate General of Mines and Safety (DGMS), each work center has teams dedicated to HSE, which execute the safety guidelines brscribed by OISD as well as DGMS. HSE teams are also responsible for obtaining necessary licenses and clearances from the State Pollution Control Boards.

All transactions in the company are carried out on SAP R/3 ERP based business portal. Proper and adequate system of internal control exists to ensure that all aspects are safeguarded and protected against loss from unauthorized use or disposition and that each transaction is authorized, recorded and reported. The system further ensures that financial and other records are fact-based and reliable for brparing the financial statements.

11. Human Resource Development

Your organization has always valued its most important human resource and due to sincere efforts only a vast pool of experienced and talented scientists, engineers and professionals today passionately take care of the energy needs of the country. 'Strengthen staffing and capabilities' has been the focus area all long the pursuits towards structured Human Resource Development. This is a critical issue keeping in view crew change in next few years. The basic principle revolves around grooming younger generations as future 'energy leaders'. Talent replenishment and bridging competency gap become crucial aspect for human resource development. Further, your Company believes that continuous development of its human resource fosters engagement. There are multifaceted efforts for grooming technical talent and develop managerial competence. Structured training programmes have been developed to impart required skills to the people in identified critical areas. Besides training, work association with industry leaders in the challenging areas of business is yet another attempt to improve capabilities. Your Company also took structured initiatives to provide a desirable work-life balance to the employees as well as improving the living and working conditions. The endeavours of your Company, towards Human Resource development, are well recognized in the industry. ONGC is in the list of "Most Attractive Employer" in India as per the Randstad survey 2015.

12. Corporate Governance

The initiatives taken by your Company are detailed in the Corporate Governance report, a part of the Annual report.

13. Corporate Social Responsibility (CSR)

Initiatives taken by your Company towards CSR are  detailed in Board's Report.

14. Cautionary Statement

Statements in the Management Discussion and Analysis and Board's Report describing the Company's strengths, strategies, projections and estimates, are forward-looking statements and progressive within the meaning of applicable laws and regulations. Actual results may vary from those exbrssed or implied, depending upon economic conditions, Government Policies and other incidental factors. Readers are cautioned not to place undue reliance on the forward looking statements.