Information about Western Hemisphere Hemisferio Occidental
Journal Issue

Mexico: Selected Issues

International Monetary Fund. Western Hemisphere Dept.
Published Date:
November 2014
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The Impact of Mexico’s Energy Reform on Hydrocarbons Production1

1. The recently adopted energy reform could revolutionize Mexico’s hydrocarbons sector. The reform aims to increase oil and gas production by eliminating the state oil company’s (PEMEX) monopoly on exploration and production of hydrocarbons, while retaining the prime directive that these resources are the property of the Mexican nation. Additionally, competition and new regulatory structures are being implemented in midstream and downstream activities to enhance the generation and distribution of natural gas and electricity to increase the efficiency of service and reduce costs. Reducing electricity costs, in particular, could have a significant impact on raising manufacturing output as discussed in a companion selected issues paper (SIP).2

2. This SIP will discuss the nature of these reforms and what problems these reforms are addressing. It will then present illustrative production scenarios for crude oil and natural gas and estimate the commensurate investment costs and foreign direct investment (FDI) associated with each scenario. The paper also examines the markets for the distribution of natural gas and electricity. It concludes with the key messages from our analysis.

A. Current Challenges in the Energy Industry3

3. Mexico has been experiencing falling crude oil and natural gas production, bottlenecks in natural gas delivery, high costs of natural gas and electricity, as well as a inefficient energy services.

Constant Reserves-to-Production with No Reserve Additions

Notes: Domestic demand is projected by SENER’s Instituto Mexicano de Petroleo

Source: SENER and IMF staff calculations

  • Crude oil production has fallen to 2.5 million barrels per day (mmbd) since its peak in 2004 of 3.4 mmbd, as the country’s giant fields mature. Despite significant probable and prospective reserves and increasing capital expenditures by PEMEX, the country has only about a decade’s worth of proven crude oil reserves. PEMEX has had a difficult time fully replacing these reserves each year, achieving this only twice in recent years. The yield from new fields has on the whole disappointed expectations, and old fields are in their depletion phase. Without significant additions to proven reserves and if the reserves-to-production ratio is held constant at the average of the last 5 years, production would fall to about 1.5 mmbd and Mexico would turn into a net oil importer4 before the end of the decade (see chart).
  • Natural gas production has also fallen to 6.4 billion cubic feet per day (bcfd) from a peak of 7.0 bcfd in 2010. Mexico has been a natural gas importer since 2002, and imports have been growing significantly since 2009. The country mostly imports natural gas via pipeline from the US, but growing demand has forced it to rely at the margin on much higher priced liquefied natural gas (LNG) primarily from Qatar, Peru, and Nigeria (see chart). Domestically, there have been problems with natural gas delivery, with the system experiencing a significant number of critical shortages that had a negative impact on industrial production in 2013.
  • Mexican consumers pay a significantly higher price for electricity than its northern neighbors and the efficiency of service is weaker than many other OECD countries (see companion SIP for further discussion). The electricity sector has had earlier reforms, which allowed some competition to the Federal Electricity Commission (CFE), the state-owned electric utility. Private actors were allowed to produce power, independent power producers (IPPs), who had to sell their power to CFE before it sold on to third parties, and large electricity consumers who could self-generate. The latter though had limited ability to sell any excess generation to the market. Moreover, while much of the new generating capacity has been natural-gas based, higher priced diesel and fuel oil generation is still used at the margin to meet this demand. Finally, the transmission and distribution system is relatively old, receives little investment, and experiences relatively high losses, which raises the cost of delivery and reduces reliability.

Mexico liquefied natural gas imports by country


Source: U.S. Energy Information Agency and International Energy Agency

B. Most Significant Reform Effort in 75 Years

4. Congress approved several constitutional amendments in December 2013, and passed all the secondary legislation in August 2014. The principles of the reforms were the reaffirmation that the nation owned the hydrocarbons in the ground; promotion of open and competitive markets between state enterprises and private firms in both upstream, midstream, and downstream operations; strengthening of the regulatory framework and institutions and the transformation of Pemex and CFE; transparency and accountability of transactions; industrial safety; and the protection of the environment and promotion of clear energy.5

5. These principles are carried out in practice by:

  • Opening up markets to competition. In mid-2014, the government completed the first round of allocating Mexico’s oil fields (so-called “Round 0”), which assigned over 80 percent of Mexico’s proven and probable oil reserves to PEMEX. In 2015, the government will begin to auction the remaining exploration and production (E&P) blocks to state-owned and private firms. The state will enter into a range of risk-sharing contracts with the winning bidders, which include profit- and production-sharing as well as licenses. The flexibility in contracts makes it likely that foreign firms will be willing to undertake the risk of exploration, while at the same time providing incentives to ensure the state gets an appropriate share. The electric generation market will be further opened up to allow independent power producers and firms that generate their own electricity to sell directly to the market. Starting in 2018, domestic gasoline prices will become fully market-determined, and PEMEX’s monoposony on gasoline imports will disappear.
  • Transformation of Pemex and CFE. Both state enterprises have been changed to state productive enterprises, with greater autonomy in operations and budgeting. Gradually over time, the fiscal take from PEMEX will be lowered to 65 percent as new fiscal regimes take hold over the next 5 years. PEMEX will be allowed to enter into joint ventures and other contracts to develop fields it received in Round 0. CFE will be allowed to contract with private parties for natural gas supply and for investment and operations of transmission and distribution projects.
  • Strengthening of the regulatory framework. The role of the Ministry of Energy (SENER) and the National Hydrocarbons Commission (CNH) are enhanced, so that new E&P contracts will be agreed with the federal government and not PEMEX. Transparent auctions will be conducted by CNH, and it will manage the contracts. Independent system operators, National Center for Energy Control (CENACE) and National Center for Control of Natural Gas (CENEGAS), are created to improve the efficiency of natural gas and electricity distribution and reduce potential conflicts of interest. The Energy Regulatory Commission (CRE) will set tariffs for transmission, distribution, and ancillary services.
  • A domestic content rule. Both assignments to PEMEX and other contracts will have domestic content rules that gradually rise to 35 percent by 2025. There is also a minimum participation rule of 20 percent for PEMEX in deep water trans-boundary projects in order for it to gain the know-how in that arena.
  • A new, independent sovereign wealth fund. The Mexican Oil Stabilization Fund, managed by the central bank, has been created to administer the proceeds and payments from assignments and contracts. This aims to increase transparency and could allow the government to save more of its oil revenues.

C. Impact on Energy Production

6. We present baseline and downside scenarios for crude oil and natural gas production for illustrative purposes only. The assumptions used were culled from discussions with and documents from the relevant Mexican authorities, academics, and analysts from the private sector.

7. We approach the analysis by asking the following questions. Are there enough potential reserves given the current geological estimates? What is the timeline for production given the type of production, i.e. conventional, enhanced recovery, deepwater or shale? What would particular targets for production imply for the proven reserve replacement ratios (RRRs)1 over time, and how do those RRRs compare to historical trends. Additionally, how much would it cost to attain these RRRs, and given assumptions for the domestic content rules, how much FDI could the projects attract?

D. Resource Blessed

8. According to PEMEX’s statistics, crude oil and natural gas reserves are substantial. Proven reserves, which are estimated to be extractable with at least 90 percent probability, amount to 10 billion barrels (bbl) of crude oil and 13.6 trillion cubic feet (tcf) of natural gas. Possible and probable reserves, those estimated to be extractable with a probability of 50 to 90 percent and 10 to 50 percent respectively, are reported to be 21 bbl and 38.5 tcf (see chart). These resources represent those in the current fields that have been explored and are being produced by Pemex as of end-2013.

Mexico’s Reserves Potential

Source: Pemex

9. Deepwater and shale could yield sizeable new reserves, but more exploratory drilling is required to more accurately measure the amounts. According to PEMEX, there is an estimated 27.1 billion barrels of oil equivalent (bboe) in the deep water Gulf of Mexico (GoM) and 60.2 bboe in shale deposits in the northern part of the country. The U.S. Energy Information Agency ranks Mexico 8th among countries with 13 bbl of technically recoverable shale oil resources and 6th with 545 tcf of technically recoverable natural gas. However, the number of exploratory wells in deepwater and shale are relatively small compared to those in the U.S. side of the GoM, the deepwaters of Brazil, and the shale fields in Eagle Ford Texas, so more information is need to ascertain the amounts.

E. How Long Does it Take?

10. The process of passing the constitutional reform and secondary laws are now complete, as well the Round 0 assignment of fields to PEMEX. The immediate next step is to implement Round 1 of bidding for the fields that were not assigned to Pemex. It is crucial that the process in this round goes relatively smoothly and is perceived to be transparent to maintain investor and political confidence in the reform. The bidding process is expected to be completed by the second half of next year. Additionally, important regulatory changes are taking place that cover exploration and production, as well as the distribution of both natural gas and electricity.

11. Over the next few years, improvements to production are more likely to come from developing conventional fields, and secondary and enhanced recovery from existing, producing fields. The government will likely have to rely on these sources from both PEMEX and new entrants to meet its goal of increasing crude oil production to 3.0 mmbd by 2019.1 These projects will take less time than unconventional sources given relatively faster processes, less complexity, and PEMEX’s enhanced ability to contract with private firms, including farmouts,2 to share investment costs or to import advanced technologies. Authorities indicated that about 70 percent of the blocks in the Round 1 auction will be those that are already probable reserves (2P) that are more ready to become proven reserves and for extraction.

12. While there has been significant attention paid to the shale and deep water potential of the country, they take a long time to develop. They are not likely to yield significant production until the next decade. Goldman Sachs uses data on the experience of deepwater projects in the U.S. side of the GoM and shale projects in the U.S. and Argentina to estimate typical production and cost curves. These estimates suggest that exploration could take place between 2016 and 2018, followed by a decision to commercially develop a discovery 1 to 2 years later. Small amount of production tend to occur between 5 to 10 years after contracts are won, and robust production after that (see chart).

Typical Deepwater and Shale Production Curves

Note: Assumes 300 millon barrels total production over entire period

Source: Goldman Sachs

F. Production Scenarios

13. In our baseline scenario, we assume that the targets set by the government are achieved. Crude oil production would fall from 2.5 in 2013 to PEMEX’s projection of 2.35 and 2.4 mmbd in 2014 and 2015, respectively. Production rises incrementally from there and reaches 3.0 mmbd by 2019 and 3.5 mmbd by 2025 (Figure 1). Reflecting PEMEX’ s commitment to at least maintain production at 2.4 mmbd, we assume between 2016 and 2015 that at least that much is produced. Then between 2016 and 2019, any additional production above that level would likely come from existing and probable reserves that were included in Rounds 0 and 1. Between 2019 and 2025, we start to introduce production from shale and deepwater sources slowly, using the typically production curves in the chart above. If we keep the ratio of proven reserves to production constant at the 5-year historical average of 10.9 years, the RRR for crude oil would have to rise to an average of 159 percent between 2016 and 2019 and 128 percent between 2020 and 2025 (Figure 1).

Figure 1.Illustrative Baseline Scenarios

  • Natural gas production is assumed to rise from 6.5 bcfd to 8.0 bcfd by 2018 and 10.4 bcfd by 2025 (Figure 1), also consistent with authorities’ projection. The proven reserves to production ratio are assumed to remain constant at the historical 5 year average of 5.5 years. At those rates the RRR of natural gas would have to average 126 percent between 2016 and 2019 and 120 percent thereafter (Figure 1).

14. Between 2015 and 2019, additions to proven reserves will likely come from the existing fields and 2P reserves, which can be produced by Pemex and its partners or new entrants. The oil is likely to come from conventional fields and the application of secondary and enhanced recovery techniques on existing fields. Between 2020 and 2025, shale and deep water sources are likely to come into play that are developed and produced by firms winning fields from federal government auctions.

15. We construct a downside scenario which assumes the government’s production goals are not met as scheduled. First, we assume that Pemex production in 2015 stays at the 2014 projected level of 2.35 mmbd, and this level continues between 2016 and 2025. From 2016 to 2019, any additional production above 2.35 mmbd is assumed to come from half of the 2P reserves in the Round 1 blocks announced on August 13, 2014 spread over the 4 years. Production does increase over this time, but only reaches 2.82 mmbd by 2019. From 2020 to 2025, other sources including conventional, shale, and deepwater contribute to production, with the latter two following the typically production schedule shown in Figure 4. Production rises to 3.33 mmbd by 2025 (Figure 2). We also assume that the proven reserves to production ratio stays constant at the historical 5 year average of 10.9 years. The scenario is equivalent to the government achieving its production golas, but with a delay of 2 years, i.e. 3.0 mmbd in 2021 vs. 2019 and 3.5 mmbd in 2027 vs. 2025. Under this scenario, the RRR for crude oil would have to average 149 percent between 2015 and 2019 and then increase to an average of 130 percent from 2019 to 2025 (Figure 2).

Figure 2.Illustrative Downside Scenarios

  • Under a downside scenario, we assume natural gas production stays constant at the projected 2014 level of 6.5 bcfd between 2015 and 2018. This means no additions to production in the first few years, and effectively means that any additions to proven reserves over this time are only in crude oil not natural gas. Natural gas production only increases from 2019 to 2025, reaching 9.5 bcfd in the last year. Shale gas only contributes to production starting in 2021, consistent with the longer end of the 5 to 10 year range between auction and the start of production. The proven reserves to production ratio for gas are assumed to remain constant at the historical 5-year average of 5.5 years. In this scenario, the government’s goal of 8.0 bcfd is only reached after 2021 and 10.4 bcfd in 2027 (Figure 2). The RRR of natural gas under this scenario would have to be 100 percent in the first period and 129 percent in the latter (Figure 2).

G. How Much Investment and FDI?

16. In order to estimate the amount of investment needed annually to achieve the higher RRRs, we need the amount of addition to reserves each year implied by the new RRRs, and a cost per barrel of crude oil or per million cubic feet per day of natural gas to develop the different types of projects.

  • For the exploration of new conventional fields, the cost of finding crude oil and natural gas is about $20 per barrel according to the EIA in South America and the U.S.1 Projects that used advanced recovery techniques to extract more oil or gas from existing fields cost between 15 to 25 dollars per barrel, according to discussions with industry analysts. We assume that cost for these two types of projects is the same for crude oil and natural gas, which is particularly true for associated natural gas—gas found in field where oil is also found.

Typical Capital Expenditures for Shale and Deepwater

Note: Assumes 300 millon barrels total production over entire period

Source: Goldman Sachs

  • For shale and deep water projects, we use cost curves provided by Goldman Sachs (see chart above). Their energy industry researchers used historical cost data from existing projects (like Eagle Ford in the U.S. and deep water fields in Brazil) to estimate the average cost of a typical project. The cost of shale development is about $11 to $20 per boe on average and deep water development at $9 to $20 per boe. We use Goldman’s estimated cost curves in our analysis which better captures the timing of capital expenditures.

17. Given these assumptions, the first phase of development, between 2015 and 2019, is estimated to require investment of about $40 billion per year. For the second stage, between 2020 and 2025, about $50 billion per year is needed (see chart below). These investments include the roughly $25 billion per year already estimated in the capital expenditure plan for E&P of PEMEX. The hump in 2021 in the investment schedule reflects the timing of the increased investment for both shale and deepwater that results from the cost curves we use (see chart above). In our downside scenario with less production and addition to reserves, average annual investments needs are about 10 percent less per year.

Illustrative Investment Costs for Baseline Scenarios

18. To estimate what of this amount might be from foreign investment, we differentiate the two phases.

  • From 2016 to 2019, PEMEX is likely to take the lead role in conventional fields and recovery, along with private partners or contracts with private firms. In this phase, the share of the investment costs borne by foreigners is likely to be smaller than projects in the second phase. We assume less than 30 percent of investment is from foreigners. Starting in 2016 we estimate that related-FDI will increase by about $10 to $15 billion from current levels (chart).
  • For the second phase, 2020–2025, we assume that that the domestic content requirement will steadily increase from 25 percent to the target of 35 percent by 2025 as written in the law. For deepwater, a minimum of 20 percent participation by Pemex is required in trans-boundary projects. We estimate FDI will increase by about $10 to $15 billion from current levels between 2016 and 2019 and by $20 to $30 billion between 2020 and 2025. In our downside scenario, FDI would on average be about 20 percent less annually over the 10 years.

Illustrative FDI and Domestic Investment for Baseline Scenarios

19. In order to compare our results, there is a wide range of analysts’ estimates of the amount of investment and FDI that could result from the energy reform (see table). These estimates come from industry experts and surveys of interest in participation in projects. They range from a low of less than US$10 billion per year to a high of US$30 billion or more. Our estimates are more in line with the lower end of those ranges. Take note that we only estimate investments into the development of oil and natural gas fields, and do not account for the wider scope of the energy reform. Some analysts have considered the broader scope of the reform.

Estimates of FDI from different sources
Estimate by:20152016201720182019
Consejo Coordinador Empresarial3468684523
International comparisons to Brazil and Colombia
Weight of global greenfield FDI relative to weight in world GDP102121147
FDI trends after energy reform410141411
Source: Banamex
Source: Banamex

H. Natural Gas Imports and Transport

20. Although in our scenarios natural gas production increases, Mexico is projected to remain a net importer of gas. Since 2010, natural gas demand has been growing at 6.5 percent per year on average in real terms in contrast to the 2.4 percent average decrease in production. The Instituto Mexicano del Petroleo, the in-house institute of SENER, projects demand to continue to grow at an average annual rate of 3.9 percent between 2015 and 2025. In the baseline scenario, production grows at a rate of 4.3 percent per year (see chart), which implies that by 2025 estimate imports would fall 9 percent compared with 2013, but remain substantial at 2.9 bcfd. In the downside scenario, imports would increase by 24 percent by 2025 in relation to 2013

Natural Gas Domestic Supply and Demand

Source: SENER and IMF staff estimates

21. The majority of Mexico’s natural gas imports are via pipeline from the U.S., but imports of the more expensive liquefied natural gas (LNG) have grown. Mexico began to import LNG in 2006, and imports peaked in 2010 at 0.55 bcfd (see chart). In 2013 LNG’s share of natural gas imports had grown to a peak of 26 percent. For most of these sources, the prices of LNG gas are much higher than pipeline gas. In 2013, pipeline gas from the U.S. cost $3.9 per thousand cubic feet, while LNG cost $13.3 (see charts).

Natural Gas Imports by Type

Source: SENER

U.S. Pipeline vs. LNG Export Prices

Source: US Energy Information Agency

22. Increasing pipeline capacity to the U.S. is necessary to take advantage of the shale revolution in the U.S. U.S. pipeline gas prices have been falling over 50 percent since 2008, due in part to the increasing supply of natural gas from unconventional sources in the Bakken and Eagle Ford shale plays. The U.S. exported 1.8 bcfd to Mexico in 2013, but projects are in train to significantly increase that amount. According to industry analysts, between 2013 and 2016 about 5.2 bcfd in pipeline capacity is being built (see map). Delays in construction would delay Mexico’s ability to take advantage of lower-priced U.S. gas.

23. The reforms and ambitious infrastructure plans by SENER aim to prevent future strains in the natural gas system. In 2013, the system experienced a significant increase in critical alerts, putting a strain particularly on industrial users and electricity generators. While these have eased, policies are geared towards preventing future stresses. The reforms change the governance of the pipeline system, so that an independent regulatory body, Cenegas, manages natural gas traffic to make the allocations more efficient. The transport and storage markets are now open to private participants, which will hopefully increase supply. Additionally, SENER has plans to build out the domestic pipeline infrastructure to connect to the pipelines to the U.S. and expand the transport of gas within Mexico.

I. Electricity Reform

24. Lowering natural gas prices will help to lower electricity prices, which could significantly improve firms’ cost structure. The largest users of natural gas are electricity generators, as natural gas combined cycle plants have been the main choice for adding new generation capacity since the 1990’s. In particular, private firms that generate power for themselves are projected by SENER to have the fastest growth in natural gas demand over the next decade. This will help to further displace diesel and fuel oil, which is costlier and more polluting than natural gas but remains the marginal source of generation (see chart).

Use of Fuel for Electricity Generation

25. The energy reforms also further opens up the generation market to competition. Firms that self-generate and independent power producers (IPPs) had already been allowed to compete with CFE to build and produce their own generating capacity. However, IPPs had to sell their electricity to CFE, and there was no mechanism for self-generators to sell their excess electricity to the market. Thus, the benefits of earlier reform accrued more to these self-generators than to the wider public, but that system is set to change. Over time, authorities are also considering expanding the scope of qualified users who can buy electricity in the wholesale market. The wholesale market is where end users can benefit more directly from lower natural gas and electricity prices.

26. Improvements to the grid and grid operations would also help to lower prices and improve service. Mexico suffers from an aging grid system with just under half of transmission lines more than 30 years old and less than 10 percent added in the last five years. CFE plans to expand the system by about 1 percent per year over the next decade. This has led to higher rates of electricity loss via distribution compared to other OECD countries. Additionally, prior to the passage of the reforms the management of grid traffic was operated by an entity within CFE, raising concerns about conflict of interest in prioritizing the dispatch of power plants to the grid. To address this, Cenace will be transformed into an independent system operator. Under the new structure, Cenace can better dispatch plants based on efficiency (lowest marginal cost) or emergency needs. Additionally, the CRE will set the tariffs on transmission, distribution, and ancillary services. These tariffs will be charged to all users of the grid, and CRE can provide incentives to reduce the losses of electricity during transmission.

27. The conversion of CFE into a state productive enterprise will give it more operational and budgetary autonomy. It will also have an expanded ability to contract with third parties that potentially could be more efficient at providing transmission and distribution services. CFE is also charged with adopting international standards for the management of state enterprises aimed at making its operations more efficient and lowering costs. This increased independence, as in the case of Pemex, will hopefully lead to an improved ability to investment in energy infrastructure.

J. Conclusion

28. The energy reform is comprehensive and has the potential to reshape Mexico’s economy to support faster growth, better living standards, and greater energy security. In the short-run, it is a defensive reform aimed at overcoming the risk of falling hydrocarbons production and improving the outlook for fiscal revenues. In the medium- to long-run, the reforms allow the country to tap its potential in shale and deepwater, as well as to provide the incentives to reduce domestic energy costs and improve services.

29. While the focus of market attention is on deepwater and shale, in the short-run improvements in recovery and development of existing fields is crucial. Authorities have wisely focused the majority of Round 1 on auctioning 2P fields that could yield hydrocarbons quickly. Additionally, Pemex will now have more freedom to partner with third parties to increase investment and import technologies to enhance its production.

30. The legislative hurdles have been tackled, but implementation risks remain. Round 1 is critical and will set the tone for future rounds, and many changes to regulations and institutions still have to be made. Delays or problems with implementation that dampen investor confidence will have consequences. Our downside scenarios show a stylized illustration of the lower production path and commensurate lower investments needs and FDI. These could have knock on negative impacts on exports and fiscal revenues.

31. Managing expectations about the shale and deep water potential is critical. Patience is needed given that it will take a long time before meaningful production can be extracted from these sources.

32. While there has been so much focus on exploration and production, the pipes and the grid are very important for growth. Lower energy costs and improving services will reap benefits on the manufacturing sector and the broader economy. Planned natural gas pipeline projects will help Mexico further lower its dependence on LNG, diesel, and fuel oil. Independent system operators for natural gas and electricity will help to reduce critical alerts and enhance service delivery.

33. Besides opening up the energy markets, Pemex and CFE needed to be shaken up to improve their efficiency, costs, and ability to invest in infrastructure. Transforming them into productive state enterprises and reducing their fiscal burdens are the first steps in this path.


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Prepared by Phil de Imus.


See Selected Issues Paper Made in Mexico: the Energy Reform and Manufacturing Output.


The scope of Mexico’s energy reform is wider than what is covered in this SIP. There are important reforms that are aimed at improving oil refining and distribution, liberalizing gasoline prices, and addressing some of the environmental concerns.


Assuming oil demand rising in line with the scenario prepared by the Ministry of Energy (SENER).


The focus of this SIP is on the former four principles. It does not examine issues of environmental protection and industrial safety. Important reforms were enacted here, including the creation of a new regulatory agency.


The proven RRR is a key statistic which indicates how much of the production in a year is replaced by additions to proven reserves. For example, a 100 percent RRR means that given 1 barrel in production, the energy company is able to find 1 new barrel of oil in proven reserves. This would keep the level of proven reserves at a constant level.


The government’s 3.0 mmbd production expectations had to be changed to 2019 due to an unexpected decline in Pemex’s production in 2013.


Farmouts are E&P projects in which PEMEX contracts with a third party to perform all or parts of a project in blocks assigned to PEMEX in Round 0.


The EIA estimates these costs from data collected from major U.S. energy producing companies as of their 2009 reports.

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