Effect of Oil and Gas Prices On Asset Retirement Obligations (AROs)

Since The market is under huge fluctuation ,Primarily effected by the Crude Price Rise and the ongoing political position in Egypt. The uprising is having and huge mpact on the growing economies specially like India or we can say the indian subcontinent.Recenlty one of the technlogical reports publised reported higher year-over-year crude and natural gas prices in 2010 may reduce the size of reported Asset Retirement Obligations (AROs) for upstream U.S. oil & gas producers, by extending existing field lives and thereby delaying the remediation costs and associated present value (PV) of related retirement obligations.Now, if primarily saying the net effect of the Oil and Gas prices wil surely effect the area.
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Ques : What is asset retirement Obligation :
Ans : Well it can well explained with the help of an example as follows :
All numbers in this example are in today's dollars.

Consider a fixed asset that has a useful life of 7 years, a present value of cash flows equal to $15,000 and the present value of cleanup at the end of the 7th year equal to $5,000. Suppose the firm pays by cash the net present value, that is $10,000. Prior to SFAS 143, the firm would reduce cash by $10,000 and increase fixed assets by $10,000. No changes would result to the totals on either side of the balance sheet. By SFAS 143, the firm needs to also recognize the future liability of $5,000 and a corresponding asset of $5,000. Hence both sides of the balance sheet consequently increase by $5,000.

As the cash flows from the asset come in, the asset of $5,000 is depreciated down to zero in the seventh year. This makes sense as during the seven years the firm has received cash flows of $5,000 in excess of the present value of $10,000 it paid. And the firm uses these cash flows to meet its retirement obligation, and then extinguishes the liability of $5,000. The fixed asset of $10,000 is depreciated in the usual manner.

If the ARO is not recognized as per SFAS 143 then after the cash flows from the asset have been obtained but prior to its "retirement", the B/S assets will show an excess value of $5,000 that does not actually exist as it would have to be spent on clean up (retirement) costs. When the costs of retirement come in, the B/S assets (and equity on the right side) will drop by $5,000 at one go. Recognizing the ARO keeps the B/S more accurate through time.

The increase of assets and liabilities by $5,000 will affect financial ratios, for example return on assets will decline, debt equity ratio will increase, etc.
Source : Wekepedia
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However, other longer term factors remain in play in the sector which likely will continue to add pressure to the growth of future AROs, including inflation in key input costs such as rigs, boats, skilled labor costs, cement and other site remediation costs, a push by the industry into the offshore, and increased offshore regulations, especially in the Gulf of Mexico (GoM) following the Deepwater Horizon spill.

Output under production-sharing contracts also are an exception to the positive reverse revisions and lower PV of retirement obligations for existing fields from higher oil and gas prices, since output under production sharing contracts moves inversely to prices.

Growth in AROs is likely to continue to vary widely by company and upstream portfolio mix, with integrated and larger independents, the group whose growth prospects are most clearly tied to offshore and deepwater prospects, likely to see the largest growth in AROs relative to debt, while purely domestic onshore names, including companies primarily involved in shale gas and shale liquids plays, are expected to show more modest growth in AROs relative to debt.

As a result, AROs are a relatively small component of total liabilities for North American onshore producers relative to debt obligations. The low growth in AROs relative to debt for this group is due not only to the lower cost of remediation for onshore wells relative to offshore, but also to a greater preference among smaller producers to fund reserve and production growth with debt.

In contrast, integrated and large independent companies had cumulative growth in AROs slightly higher than 128 percent from 2005 to 2009, but was matched against a more conservative debt profile, with debt growing only a cumulative total of 75 percent between 2005 and year-end 2009. Cumulative reserve growth was nine percent for this group and reflects the ongoing difficulty among larger entities, particularly supermajors, to move the needle in terms of reserve growth.

The greatest increase in ARO among offshore independents was seen at Anadarko Petroleum Corp. with a 472 percent increase, which was driven by an aggressive drilling program and the build-out of key deepwater positions in the GoM, West Africa and Brazil. Anadarko’s growth in debt was also significant at 247 percent, fueled by the all-debt-financed acquisition of Kerr-McGee Corporation and Western Gas Resources Inc; however, reserve growth was down by six percent over this period, as asset sales were subsequently used to pay down acquisition debt.

Among larger integrated companies, Chevron's ARO grew 136 percent while its balance sheet gross debt fell 18 percent over the same time frame. Chevron is one of largest deepwater players in the GoM, with stakes in Tahiti, Jack/St. Malo, Perdido, and Big Foot discoveries. Chevron also has extensive deepwater exposure in West Africa, Brazil and Asia.

Noble Energy Inc. experienced a 32 percent reduction in ARO from 2005 to 2009 when it was impacted by Hurricanes Katrina and Rita, which resulted in extensive platform damage for assets in the GoM and accelerated the company's plugging and abandonment (P&A) activity in the GoM.

A third group of companies, which have either transitioned from the offshore to the onshore or are transitioning, have seen or are likely to see reductions in AROs as offshore fields with higher liabilities are sold. This group includes Devon Energy, which exited all offshore plays with 2010 asset sales as it refocuses on North American onshore plays, Forest Oil, which spun off its GoM subsidiary in March 2006 to Mariner, and Newfield Exploration, which divested its shallow water properties in mid-2007 to McMoRan Exploration Co. The sale included the transfer of all associated asset retirement obligations.

Oversight of drilling activity, including (P&A) activity, has increased following the Macondo spill in the GoM, and heightened scrutiny of offshore operations is expected to persist for years. Regulations issued by the Bureau of Ocean Energy Management, Regulations and Enforcement that requires that platforms deemed no longer useful for operations must be removed as soon as possible but no later than Oct. 15, 2015, and that wells on expired leases must be plugged permanently on a lease within one year after the lease terminates, either by relinquishment, expiration, cancellation or forfeiture. Additional tightening of P&A requirements affect P&A expense by either increasing expense associated with well plugging or accelerating the timing of P&A.

AROs are a key liability for exploration & production balance sheets which can have a wide-range of potential credit impacts. In terms of liquidity, lower-rated or smaller producers may be required to provide assurance to regulators or other parties that they are financially able to meet future remediation costs through Letters of Credit (LOCs), surety bonds, or other assurances, all of which can lower liquidity. AROs are also a factor in the consideration received for a property in a sale.

However, it is important to note that AROs also have characteristics of 'soft obligations'--unlike straight debt for example, an ARO can be effectively deferred through a successful drilling program which extends the life of an existing field and therefore delays the ultimate date of site remediation.

Over the last few months, several articles and papers have emphasized the potential role shale gas will play in India's hunt for energy. Shale gas is natural gas trapped in fine grained sediment. These articles did not have any graphics so I am putting up a map of Indian sedimentary basins and a graphic depicting shale gas geological reservoirs.



Indian Sedimentary Basins




Source: Geotimes

The basins of interest in terms of shale gas potential are the mostly marine Mesozoic and Cenozoic basins in Rajasthan and Gujarath and the Cenozoic basins of Assam. The Gondwana basins of central and eastern India are continental interior rift basins and are coal rich and have associated coal bed methane which if tapped could also play an important role in India's energy mix.


Shale Gas Geological Reservoirs




Unlike gas reservoirs in coarser materials like sands, natural gas in shale is trapped in micro pores which may not be connected to each other i.e. they have low permeability and the gas is quite difficult to extract.


India's conventional natural gas reserves are growing with new discoveries mostly along the east coast Krishna Godavari offshore basins. Early estimates of these gas resources if proved correct may more than double in terms of energy equivalence India's proven reserves of about 5.6 billion barrels of oil. Unconventional resources like shale gas have the potential of adding substantially more to these resources. Currently natural gas makes up a small portion of India's energy consumption pie (see fig on left) and the chance to move towards a cleaner emissions profile by substantially displacing coal in power generation (coal makes up about 70% of electricity generation) and eventually as fuel for transport makes these unconventional sources a critical energy resource of the future.

I don't know how much shale gas resources India has because there has not been a systematic evaluation of shale gas. India's current energy policy prohibits exploitation of shale gas and coal-bed methane. The sooner that policy changes the better for energy starved India.

[Update Sept 3:] As a reader pointed out in the comments there is recent movement from the government on the exploitation of shale gas and coal bed methane. See this article. A policy on shale gas is likely to be out by next year, while the government has already auctioned of several blocks for exploration of CBM from various basins.

Still, there is one aspect of exploiting these resources that has not been touched upon by any of the articles I have come across and that is the environmental costs of extracting shale gas. Since this gas is locked up in impermeable layers one of the common methods of extracting it is by hydraulic fracturing of the rock. This involves injecting the shale with fluids and gels mixed with particulates like sand to keep the induced fractures open and enable migration of the gas along open fractures.

A new film "Gasland" discussed on Science Friday last month looks at some of the problems of hydraulic fracturing or "fracking" of the Marcellus shale that underlies large parts of Pennsylvania, New York and Ohio and West Virginia. Chemicals used in the injecting fluid has been reported to contaminate groundwater in Pennsylvania. At least according to the film, the energy companies have been less than forthright about the chemical composition of the injecting fluids which the film claims includes carcinogens and neurotoxins.

All this should send warning signals about the way and means by which India goes about exploiting these shale gas resources. Groundwater is as important a resource for India's economic development as is natural gas. Almost all drinking water needs in rural areas are met by groundwater. A significant majority, about 2/3, of arable area in India is irrigated by groundwater. Contamination of large portions of the overlying aquifer will be nothing short of a catastrophe for farmers who have no other water supply but groundwater.

The exploitation of coal bed methane offers another avenue for social conflict. The Gondwana basins which are coal rich are forested regions and home to many tribal communities. There has been a long history in India of the government and private mineral companies riding roughshod over tribal rights. The current violent insurgency that is taking place along tribal regions of Chattisgarh, Maharashtra and Jharkhand has its roots in the rampant exploitation and callous indifference shown by the state and private companies towards tribal communities.

So, shale gas and coal bed methane offer a significantly large energy source but also open up the possibility of more environmental and social disruption.

Shale Gas - A retrospect

In a telephone interview, Jessica Ernst says she’s “still getting used to” being compared to Erin Brockovich (the environmental activist made famous by Julia Robert’s film portrayal ten years ago). The comparison comes easy because the outspoken Ernst, a landowner in the town of Rosebud, Alberta, is one of the few Albertans who have publicly criticized hydraulic fracturing (called “fracking,” in the trade).

Fracking is a technology used by the oil and gas industry to access “unconventional” natural gas deposits trapped in shale, coalbed, and tight-sand formations – potentially at the expense of underground water supplies.

After her well water was contaminated by nearby fracking in 2006, Ernst decided to go public, showing visiting reporters how she could light her tap water on fire, and speaking out about Alberta land owners’ problems with the industry, especially Calgary-based EnCana. EnCana is Canada’s second biggest energy company (after Suncor) and is now also a major player in British Columbia, with hundreds of natural-gas wells in the province.

Ernst, a biologist and environmental consultant to the oil and gas industry, says EnCana “told us ‘we would never fracture near your water.’ But the company fracked into our aquifer in that same year [2004].” By 2005, she says, “My water began dramatically changing, going bad. I was getting horrible burns and rashes from taking a shower, and then my dogs refused to drink the water. That’s when I began to pay attention.” More than fifteen water-wells had gone bad in the little community.

Tests revealed high levels of ethane, methane, and benzene in Ernst’s water. “EnCana told us they use the same gelled [fracking] fluids as in the States.” Fracking has become a huge controversy in the US, with pending legislation that would impact its regulation.

Ernst says she heard from “at least fifty other landowners the first year” she went public, and she continues to get calls. Groundwater contamination from fracking “is pretty widespread” in Alberta, “but they’re trying to keep it hidden.” Canada has no national water standards and conducts little information gathering about groundwater.

Chromium-6 In The WaterBeing an activist on behalf of her community is not the only connection Ernst has with Brockovich. Through expensive Freedom of Information requests, Ernst obtained post-fracking water well monitoring data that showed the Alberta Environment people had found hexavalent chromium in Rosebud’s well water. “The government hasn’t told this to people” in the hamlet, says Ernst.

Hexavalent chromium, otherwise known as chromium-6, is the extremely toxic substance Brockovich found in the drinking water in Hinkley, California, which led to a major class action lawsuit against Pacific Gas & Electric, which finally paid the plaintiffs more than $200 million (€146M) in 2006.

Ernst, who knows the industry well, says chromium-6 “is used in fracking and drilling.” In an odd coincidence, Erin Brockovich herself is currently involved in investigating a mile-long plume of chromium-6 contamination of drinking water – apparently caused by fracking and drilling – in Midland, Texas. In July 2009, Brockovich investigators told the press they have evidence that hydraulic fracturing specialist Schlumberger is to blame. In the continuing case, Brockovich is representing 40 householders whose water has been contaminated.

Trade SecretsIn 2006, when EnCana was fined $266,000 (€194,000) by the state of Colorado for “failure to protect water bearing formations,” a company spokesman complained to the press that environmentalists had been spreading “misinformation” about fracking and creating a climate of fear about hydraulic fracturing fluids.

The public however, has no way of knowing what’s in the fracking fluids because the chemicals used are considered a “trade secret” – or rather, many trade secrets.
Oil and gas companies like EnCana, Imperial Oil, Suncor, ConocoPhilips, ExxonMobil, etc., generally don’t do the hydraulic fracturing themselves, but instead hire specialty services to do it. Each of the big players in the multi-billion-dollar fracking industry – Halliburton, Calfrac Well Services, Schlumberger, BJ Services (all of which operate in Western Canada) – has its own recipe for fracking fluids, of which they are fiercely protective. The precise nature and concentrations of the chemicals in these “proprietary fluids” are not even fully known to government regulatory agencies.

By examining drillers’ patent applications and government worker health and safety records, some environmentalists and regulators in the US have been able to piece together a list of some of the fracking fluid ingredients. These include potentially toxic substances such as diesel fuel (which contains benzene, ethylbenzene, toluene, xylene, and napththalene), 2-butoxyethanol, polycyclic aromatic hydrocarbons, methanol, formaldehyde, ethylene, glycol, glycol ethers, hydrocholoric acid, and sodium hydroxide.

US Fracking ControversyAs a sign of just how controversial hydraulic fracturing has become in the US, Exxon Mobil Corp.’s US$29 billion (€21.5b) takeover of fracking specialist XTO Energy Inc. includes a clause stating that any changes to US law that make fracking “illegal or commercially impracticable” would allow the companies to terminate their deal without paying a $900 million (€666) breakup fee.

By 2007, there were 449,000 natural gas wells in 32 American states, an increase of more than 30 percent since 2000, with serious episodes of groundwater contamination near drilling sites documented in seven states.
Companion legislation (S.1215/H.R.2766) – the Fracturing Responsibility and Awareness of Chemicals (FRAC) Act – is currently before Congress to require regulation of hydraulic fracturing under the federal US Safe Drinking Water Act, as well as disclosure of all chemicals used in fracking fluids. New York City Council, the mayor of New York, and a New York Times editorial have all called for a ban on hydraulic fracturing throughout the watershed from which the city obtains its drinking water. That watershed is part of the huge Marcellus shale area being staked out for natural gas drilling and fracking of tens of thousands of wells.

Drilling in CanadaMeanwhile, the BC government has been pushing drilling for unconventional sources of natural gas since at least 2005, offering $50,000 (€36,500) royalty credits for every well drilled before December 2008, and selling oil and gas “sub-surface rights” at a fever pitch.

Both BC and Saskatchewan have been courting the industry with lax or no environmental regulations and promises of low royalties charged to the companies. The Petroleum Services Association of Canada (PSAC) predicts a 10 percent increase in drilling in BC in 2010, mostly in the Montney shale field of northeastern BC and the Horn River Basin near Fort Nelson.

In 2006, researchers for West Coast Environmental Law published a report noting that the oil and gas industry had identified at least six areas of BC holding coalbed methane (CBM) natural gas potential: Peace country in the north east; Elk Valley in the southeast; Vancouver Island; the south central interior (around Merritt and Princeton); northwestern BC (around Telkwa and Iskut); and the Queen Charlotte Islands.

Nanaimo Daily News (Nov. 7, 2009) reported that Vancouver Island’s CBM gas deposits – stretching from Chemainus to Parksville, and in the Comox-Campbell River area – are currently not of interest to the industry. Nonetheless, a group called Citizens Concerned About Coalbed Methane-Vancouver Island, has for the past year been pushing for development under its action plan, “Building a Safe Future for CBM.”

In 2008, BC took in a record $2.4 billion (€1.75b) from these leases, which is now its biggest source of royalties’ income.
Fracking is also in high demand in the Bakken natural gas field in southern Saskatchewan, where 1,000 wells have been drilled and fracked over the past five years. PSAC is predicting 1,935 new wells will be drilled there in 2010, and 300 new wells in Manitoba. As a result, Alberta has just announced that it is removing environmental and regulatory “hurdles” in order to entice the natural-gas industry back.

Huge shale developments are also planned for Quebec, New Brunswick and Nova Scotia. The Utica shale gas field in Quebec covers an area of 5,000sq.km (1,930sq.m) that runs along the St. Lawrence River from Montreal to Quebec City.

The industry is especially interested in the Utica shale because it is close to the New York City market, with export capacity available on TransCanada Corp.’s pipeline system. If the US curtails natural gas development in the Marcellus shale, the Utica could provide gas to the New York market.

Horizontal Drilling AddedThe newest technology used by the industry increases the scope of fracking. By drilling horizontal wells, where the drill bit is steered along a horizontal trajectory, the well bore is exposed to as much of the shale gas reservoir as possible. Combined with hydraulic fracturing, the two technologies create many kilometres of contact area for natural gas to flow into a well, giving the operator a fast payback.

BC energy activist Arthur Caldicott, a frequent contributor to the Watershed Sentinel, explained by email: Fracking “is a nearly-continuous operation in shale gas production. Wells may be fracked up to seventeen times along their entire length.”

Now some geologists are saying that the use of horizontal drilling and fracking for shale production exhausts the well within a mere eight years, with a decline in output of 75 percent in the first year alone. Some are even calling the sector “a speculative bubble.”

In other words, the drilling and fracking endanger the groundwater and deplete rivers and lakes all for a quick payoff to the industry and the province, after which the taxpayer is left with the clean up.
A new report from BC Auditor-General John Doyle states that the BC oil and gas commission must “improve its oversight” of the industry in order to adequately manage the risks of contamination during drilling, production and final site restoration. The minimum cost to restore one well site is $100,000 (€74,000).

While natural gas is touted as a “clean energy” source, the method of extracting this fossil fuel is dirty indeed.