SeEEs Harvard Business School 9-295-029 Rev. November 21. 199 MW Petroleum Corporation(A) In late 1990, executives, engineers, and financial advisors working for Amoco Corporation and Apache Corporation began serious discussions about the sale to Apache of MW Petroleum Corporation, a wholly-owned subsidiary of Amoco Production Company. Amoco had transferred to MW certain of its own assets that it regarded as non-strategic. MW,s size, location, and operations were all very attractive to Apache, which had grown nearly 30% per year since the mid-1980s, largely through acquisitions. The transaction being discussed with Amoco would be Apache's largest to date. It would more than double the size of Apache's current operations, as well as its reserves of oil and natural gas By the end of January 1991, Apache's executives and advisors were sufficiently familiar with the properties in MW to begin refining their estimates of operating and financial performance in order to structure a formal offer. Apache's chief financial officer, Mr. Wayne Murdy, knew that financing would be a challenge, given the size of the proposed transaction. In fact, the availability of external financing, bank debt in particular, was likely to impose some practical limits on both he amount and form of consideration that Apache could offer to Amoco. It was essential that Apache carefully evaluate MW, both the whole and its parts, and study the likely patterns of cash flows so that some creative financing alternatives could be developed Amoco Corporation Amoco Corporation was an integrated petroleum and chemical company based in Chicago, Illinois. With $28 billion in operating revenues and $1. 9 billion in net income in 1990, Amoco was the fifth largest oil company in the United States. Its three primary businesses were oil and gas Company), and chemical production(Amoco Chemical Company). L idog 98n8(Amoco Oil exploration and production(Amoco Production Company), refining and marke 980s, Amoco had been an active acquiror of oil and gas properties, particularly the latter. Its 1988 purchase of Dome Petroleum of Canada made Amoco North America's largest private holder of natural gas reserve and the second largest producer of natural gas. In 1990, Amoco produced 3. 5 billion cubic feet per da (BCFd)of natural gas and 782 thousand barrels per day(MBd)of crude oil and natural gas liquids y f Professors Timothy A. Luehrman and Peter Tufano as the basis for class discussion rather than to illustrate either effective or ineffective handling of an administrative situation Copyright e 1994 by the President and Fellows of Harvard College. To order copies or request permission reproduce materials, call(800)545-7685 or write the Harvard Business School Publishing, Boston, MA 02163 in any form or by any means-electronic, mechanical, photocopying, recording, or otherwise--wit hout the permission of rard Business school
DO NOT COPY Harvard Business School 9-295-029 Rev. November 21, 1994 Research Associate Barbara D. Wall prepared this case under the supervision of Professors Timothy A. Luehrman and Peter Tufano as the basis for class discussion rather than to illustrate either effective or ineffective handling of an administrative situation. Copyright © 1994 by the President and Fellows of Harvard College. To order copies or request permission to reproduce materials, call (800) 545-7685 or write the Harvard Business School Publishing, Boston, MA 02163. No part of this publication may be reproduced, stored in a retrieval system, used in a spreadsheet, or transmitted in any form or by any means—electronic, mechanical, photocopying, recording, or otherwise—without the permission of Harvard Business School. 1 MW Petroleum Corporation (A) In late 1990, executives, engineers, and financial advisors working for Amoco Corporation and Apache Corporation began serious discussions about the sale to Apache of MW Petroleum Corporation, a wholly-owned subsidiary of Amoco Production Company. Amoco had transferred to MW certain of its own assets that it regarded as non-strategic. MW's size, location, and operations were all very attractive to Apache, which had grown nearly 30% per year since the mid-1980s, largely through acquisitions. The transaction being discussed with Amoco would be Apache's largest to date. It would more than double the size of Apache's current operations, as well as its reserves of oil and natural gas. By the end of January 1991, Apache's executives and advisors were sufficiently familiar with the properties in MW to begin refining their estimates of operating and financial performance in order to structure a formal offer. Apache's chief financial officer, Mr. Wayne Murdy, knew that financing would be a challenge, given the size of the proposed transaction. In fact, the availability of external financing, bank debt in particular, was likely to impose some practical limits on both the amount and form of consideration that Apache could offer to Amoco. It was essential that Apache carefully evaluate MW, both the whole and its parts, and study the likely patterns of cash flows so that some creative financing alternatives could be developed. Amoco Corporation Amoco Corporation was an integrated petroleum and chemical company based in Chicago, Illinois. With $28 billion in operating revenues and $1.9 billion in net income in 1990, Amoco was the fifth largest oil company in the United States. Its three primary businesses were oil and gas exploration and production (Amoco Production Company), refining and marketing (Amoco Oil Company), and chemical production (Amoco Chemical Company). During the 1980s, Amoco had been an active acquiror of oil and gas properties, particularly the latter. Its 1988 purchase of Dome Petroleum of Canada made Amoco North America's largest private holder of natural gas reserves and the second largest producer of natural gas. In 1990, Amoco produced 3.5 billion cubic feet per day (BCFd) of natural gas and 782 thousand barrels per day (MBd) of crude oil and natural gas liquids
As of December 31, 1990, the company had estimated proved developed reserves totaling 5.1 billion barrels on an oil-equivalent basis The 1980s had been a difficult decade for the oil industry, Amoco included. [Exhibit 1 summarizes historical financial data for Amoco during 1986-90. From a high of over $37 per barrel in 1980, the price of oil on the spot market had fallen to just above $10/bbl in July 1986 and had recovered to only a little over $18/bbl by the end of the decade. Low prices depressed the profitability of oil companies, most of which responded with downsizing programs and other cost- cutting measures aimed at overhead expenses. Many major companies also sought to consolidate and rationalize their productive assets, which often meant divesting marginal properties. Since 1983, Amoco itself had sold more than $750 million worth of small properties which, it felt, could be more economically operated by smaller, low-overhead independent companies In 1988, Amoco conducted an extensive review of its cost structure and profitability. The study concluded that direct operating costs were well-controlled and offered little opportunity for major savings. However, it also showed that in the United States 85% of the company's gross margin was provided by just 11% of its 1150 producing fields and that many of the remaining fields had disproportionately high overhead and repair expenses. Based on these and other findings, Amoco initiated a major restructuring to better focus on its most attractive properties and opportunities. The first step was the sale, in 1989, of more than 400 fields in the"tail"of the margin curve, comprising approximately one third of the field portfolio and 12% of leases. These properties were among Amoco's least profitable, contributing only 3% of the company's direct Next, in January 1990, as part of the overall restructuring of Amoco Production Company, Amoco's board of directors approved a plan to divest up to $1.2 billion worth of additional properties from the middle section of the margin curve. Morgan Stanley was engaged to advise and assist in this process, which began with a review of different divestment alternatives. These included selling the properties in regional packages, spinning off a new public company, forming a joint venture, or retaining the properties until they were depleted but without making further material investment. Among these alternatives, a spin-off was judged most likely to produce the highest value for the properties. However, after further study it became clear that, for various reasons, a spin-off could take two or more years to accomplish, which reduced its attractiveness, not least because the future receptivity of the market was hard to forecast. Consequently, Amoco and Morgan Stanley decided to assemble the properties in a new, free-standing exploration and production entity called MW Petroleum Corporation. MW was to be a fully operational oil and gas company. In setting it up, Amoco faced myriad organizational, managerial, staffing, and other issues beyond the scope of this case. Ultimately, this turnkey operation was to be as large as many independent U.S. oil companies and could be marketed as such to non-U S. bidders seeking to establish operations in the United States During the latter part of 1990, Mw was shown to a number of targeted international petroleum concerns. For various reasons, all of these declined to bid. Toward the end of the year, U. S. buyers also were approached and Amoco considered offers from several different bidders large inde interested in some, but not nearly all of MW; another oil and trading concern was interested in all of MW, but offered too low a price; and a venture capital group expressed interest, but Amoco doubted that it could obtain financing for its bid. The most promising expression of interest had come from Apache Corporation
DO NOT COPY 295-029 MW Petroleum Corporation (A) 2 As of December 31, 1990, the company had estimated proved developed reserves totaling 5.1 billion barrels on an oil-equivalent basis. The 1980s had been a difficult decade for the oil industry, Amoco included. [Exhibit 1 summarizes historical financial data for Amoco during 1986-90.] From a high of over $37 per barrel in 1980, the price of oil on the spot market had fallen to just above $10/bbl in July 1986 and had recovered to only a little over $18/bbl by the end of the decade. Low prices depressed the profitability of oil companies, most of which responded with downsizing programs and other costcutting measures aimed at overhead expenses. Many major companies also sought to consolidate and rationalize their productive assets, which often meant divesting marginal properties. Since 1983, Amoco itself had sold more than $750 million worth of small properties which, it felt, could be more economically operated by smaller, low-overhead independent companies. In 1988, Amoco conducted an extensive review of its cost structure and profitability. The study concluded that direct operating costs were well-controlled and offered little opportunity for major savings. However, it also showed that in the United States 85% of the company's gross margin was provided by just 11% of its 1150 producing fields and that many of the remaining fields had disproportionately high overhead and repair expenses. Based on these and other findings, Amoco initiated a major restructuring to better focus on its most attractive properties and opportunities. The first step was the sale, in 1989, of more than 400 fields in the "tail" of the margin curve, comprising approximately one third of the field portfolio and 12% of leases. These properties were among Amoco's least profitable, contributing only 3% of the company's direct margin. Next, in January 1990, as part of the overall restructuring of Amoco Production Company, Amoco's board of directors approved a plan to divest up to $1.2 billion worth of additional properties from the middle section of the margin curve. Morgan Stanley was engaged to advise and assist in this process, which began with a review of different divestment alternatives. These included selling the properties in regional packages, spinning off a new public company, forming a joint venture, or retaining the properties until they were depleted but without making further material investment. Among these alternatives, a spin-off was judged most likely to produce the highest value for the properties. However, after further study it became clear that, for various reasons, a spin-off could take two or more years to accomplish, which reduced its attractiveness, not least because the future receptivity of the market was hard to forecast. Consequently, Amoco and Morgan Stanley decided to assemble the properties in a new, free-standing exploration and production entity called MW Petroleum Corporation. MW was to be a fully operational oil and gas company. In setting it up, Amoco faced myriad organizational, managerial, staffing, and other issues beyond the scope of this case. Ultimately, this turnkey operation was to be as large as many independent U.S. oil companies and could be marketed as such to non-U.S. bidders seeking to establish operations in the United States. During the latter part of 1990, MW was shown to a number of targeted international petroleum concerns. For various reasons, all of these declined to bid. Toward the end of the year, U.S. buyers also were approached and Amoco considered offers from several different bidders. None of these offers was entirely satisfactory, however. One large independent oil company was interested in some, but not nearly all of MW; another oil and trading concern was interested in all of MW, but offered too low a price; and a venture capital group expressed interest, but Amoco doubted that it could obtain financing for its bid. The most promising expression of interest had come from Apache Corporation
PEtroleum Corporation(A) 295029 Apache Corporation Apache Corporation was an independent oil and gas company based in Denver, Colorado and engaged in exploration, development, and production of oil and natural gas, primarily in the United States. It had earnings of $40 million in 1990 on revenues of $270 million and a market equivalent basis and were concentrated in the Gulf Coast region, in the Rocky Mountains, and in the Anadarko Basin of Oklahoma. Daily production in 1990 had been 259.1 million cubic feet (MMCF) of gas and 9.2 toeeded its oil production by about 4-to-1. Historical financial data for Apache are Isand barrels(MB)of oil. At these levels, on an oil-equivalent basis, Apache 's gas prod ummarized in exhibit 2 labe perti. ache had low costs and was considered an efficient operator of small-to medium-sized To exploit these strengths, Apache chairman Raymond Plank developed a strategy he labeled"rationalize and reconfigure "The strategy involved acquiring producing properties whose operations Apache could control and quickly make more efficient. In the 1980s, Apache's tactics frequently entailed significant borrowing to finance the purchase of a portfolio of properties, the best of which would be retained and operated, while the remainder was sold to help pay down debt. A total of more than $1. 4 billion in assets were acquired in this fashion in the 1980s, with the two largest purchases each exceeding $400 million. compa,. The properties in MW held several attractions for Apache. First, MW was a large company that would more than double Apache's reserves, and it was comprised mostly of properties well-suited to Apache's operating capabilities. Further, Amoco itself, on behalf of Mw, operated fields accounting for nearly 80% of MW's production. This was considered a high operating percentage among U.S. producers and it promised Apache significant cost-saving opportunities(the remaining 20% of MW,s production consisted of interests in fields operated by other companies) Adding MW to its portfolio also would shift Apache's oil-gas ratio from 20-80 to about 40-60. Such a shift was desirable because gas prices had been extremely volatile recently: during 1990 they had allen nearly 50% from a four-year high at the beginning of the year. The resulting instability in Apache's revenue stream made high leverage more dangerous and the company's acquisition-driven growth strategy more difficult. Finally, MWs properties would further diversify Apache geographically. This would add further stability, enhance the company's standing among U.S independents, and could lead to other future acquisition opportunities MW Petroleum Corporation MW had been set up as a free-standing, wholly-owned subsidiary of Amoco, complete with its own reserves, management team, and with full ownership of or access to extensive geologic and engineering data from studies performed or purchased by Amoco on MW fields. MWs holdings included working interests in more than 9, 500 wells in more than 300 producing fields situated on nearly 350,000 net acres in the Gulf Coast, Rocky Mountain, and Mid-continent regions and in the Permian Basin of Texas and New Mexico. The company's proved, probable, and possible reserves, as estimated by independent petroleum engineering consultants, totaled 264 million barrels on an oil- equivalent basis. I Of this, about 60% was oil and 40% gas. Table a gives a further breakdown of MWs reserves according to their engineering, development, and production status To obtain a total for oil and gas reserves, 6 billion cubic feet(BCF)of gas are converted to one million barrels of oll-equivalent (MMBOE
DO NOT COPY MW Petroleum Corporation (A) 295-029 3 Apache Corporation Apache Corporation was an independent oil and gas company based in Denver, Colorado and engaged in exploration, development, and production of oil and natural gas, primarily in the United States. It had earnings of $40 million in 1990 on revenues of $270 million and a market capitalization of $850 million. Apache's proven reserves totaled 106.1 million barrels on an oilequivalent basis and were concentrated in the Gulf Coast region, in the Rocky Mountains, and in the Anadarko Basin of Oklahoma. Daily production in 1990 had been 259.1 million cubic feet (MMCF) of gas and 9.2 thousand barrels (MB) of oil. At these levels, on an oil-equivalent basis, Apache's gas production exceeded its oil production by about 4-to-1. Historical financial data for Apache are summarized in Exhibit 2. Apache had low costs and was considered an efficient operator of small- to medium-sized properties. To exploit these strengths, Apache chairman Raymond Plank developed a strategy he labeled "rationalize and reconfigure." The strategy involved acquiring producing properties whose operations Apache could control and quickly make more efficient. In the 1980s, Apache's tactics frequently entailed significant borrowing to finance the purchase of a portfolio of properties, the best of which would be retained and operated, while the remainder was sold to help pay down debt. A total of more than $1.4 billion in assets were acquired in this fashion in the 1980s, with the two largest purchases each exceeding $400 million. The properties in MW held several attractions for Apache. First, MW was a large company that would more than double Apache's reserves, and it was comprised mostly of properties well-suited to Apache's operating capabilities. Further, Amoco itself, on behalf of MW, operated fields accounting for nearly 80% of MW's production. This was considered a high operating percentage among U.S. producers and it promised Apache significant cost-saving opportunities (the remaining 20% of MW's production consisted of interests in fields operated by other companies). Adding MW to its portfolio also would shift Apache's oil-gas ratio from 20-80 to about 40-60. Such a shift was desirable because gas prices had been extremely volatile recently: during 1990 they had fallen nearly 50% from a four-year high at the beginning of the year. The resulting instability in Apache's revenue stream made high leverage more dangerous and the company's acquisition-driven growth strategy more difficult. Finally, MW’s properties would further diversify Apache geographically. This would add further stability, enhance the company's standing among U.S. independents, and could lead to other future acquisition opportunities. MW Petroleum Corporation MW had been set up as a free-standing, wholly-owned subsidiary of Amoco, complete with its own reserves, management team, and with full ownership of or access to extensive geologic and engineering data from studies performed or purchased by Amoco on MW fields. MW's holdings included working interests in more than 9,500 wells in more than 300 producing fields situated on nearly 350,000 net acres in the Gulf Coast, Rocky Mountain, and Mid-continent regions and in the Permian Basin of Texas and New Mexico. The company's proved, probable, and possible reserves, as estimated by independent petroleum engineering consultants, totaled 264 million barrels on an oilequivalent basis.1 Of this, about 60% was oil and 40% gas. Table A gives a further breakdown of MW's reserves according to their engineering, development, and production status. 1To obtain a total for oil and gas reserves, 6 billion cubic feet (BCF) of gas are converted to one million barrels of oil-equivalent (MMBOE)
Table a: Mw Petroleum's Estimated Reserves Oil(MMB) Gas (MMCF) Total (MMBOE Proved developed producing 73.6 381.1 137.1 Proved developed non-producing 7.9 61.5 18.1 Proved undeveloped 25.6 Total Probable 70.4 258 Total Possible 44.5 75 Total Reserves 1559 Mr Plank was interested in Mw because most of its properties fit well with Apache's Unfortunately, MW was simply too large for Apache to finance. As a result, Apache intended to exclude from its proposal a group of properties located in Michigan and the Gulf of Mexico that fit less well with its own portfolio. Amoco, for its part, indicated it would entertain such a proposal and, if it seemed promising, might even be willing to help locate financing producing and non-producing we w had proved developed reserves associated with both Proved developed reserves They included projected production both from currently functioning wellbores and from others that required only modest expenditures to become fully operational. Apache was interested in 121.4 MMBOE of MW's proved developed reserves, or about 80% of the total. More than half of the reserves Apache proposed to exclude were gas. Annual production of oil and gas from the wells to be purchased would decline over time as the reserves were depleted. Though production could be slowed to extend the life of the reserves, this practice of"shutting in"reserves was rare in the United States. Oil production was expected to start at 9.4 MB in 1991 and decline to 1.2 MB in 2005. By that time, only 24% of the beginning proved developed crude oil reserves would remain in the ground. Similarly, gas production was expected to drop from 45.3 to 6.2 MMCF over the fifteen years from 1991 to 2005. At the end of 2005, only about 14% of the beginning gas reserves would remain. Exhibit 3 presents projections for the production of proved developed reserves along with associated cash flows, excluding the above-mentioned fields in Michigan and the Gulf of Mexico Proved undeveloped reserves MW had other reserves that were proved but not developed. Developing these reserves would require drilling additional wells adjacent to existin wells, recompleting existing wellbores, or, in some cases, utilizing so-called"secondary"and tertiary"recovery techniques. The most common of these was waterflooding, whereby a producing field is injected with water at selected sites to increase pressure in the field and push more oil and gas out of the ground. The properties in which Apache terested comprised about 75% of MW,s proved undeveloped reserves, including more than 80% of the available oil reserves Bringing these reserves into production would require estimated expenditures for development of about $35 million over two years, and only minimal capital spending afterwards. Once these reserves were developed, about 70% of the oil and 90% of the gas could be extracted during the first fifteen years of production. In most fields, MW could leave these reserves undeveloped while retaining the right to develop them later. How long it could wait without forfeiting its rights varied from property to property, depending on the terms of the lease, on sharing arrangements with other companies, and on the level of production from other wells on the property. In virtually all cases, MW could wait 5-7 years without jeopardizing its rights. Exhibit 4 shows production and
DO NOT COPY 295-029 MW Petroleum Corporation (A) 4 Table A: MW Petroleum's Estimated Reserves Oil (MMB) Gas (MMCF) Total (MMBOE) Proved developed producing 73.6 381.1 137.1 Proved developed non-producing 7.9 61.5 18.1 Proved undeveloped 15.8 58.5 25.6 Total Proved 97.3 501.1 180.8 Total Probable 14.1 70.4 25.8 Total Possible 44.5 75.4 57.1 Total Reserves 155.9 646.9 263.7 Mr. Plank was interested in MW because most of its properties fit well with Apache's. Unfortunately, MW was simply too large for Apache to finance. As a result, Apache intended to exclude from its proposal a group of properties located in Michigan and the Gulf of Mexico that fit less well with its own portfolio. Amoco, for its part, indicated it would entertain such a proposal and, if it seemed promising, might even be willing to help locate financing. Proved developed reserves xxx MW had proved developed reserves associated with both producing and non-producing wells. They included projected production both from currently functioning wellbores and from others that required only modest expenditures to become fully operational. Apache was interested in 121.4 MMBOE of MW's proved developed reserves, or about 80% of the total. More than half of the reserves Apache proposed to exclude were gas. Annual production of oil and gas from the wells to be purchased would decline over time as the reserves were depleted. Though production could be slowed to extend the life of the reserves, this practice of “shutting in” reserves was rare in the United States. Oil production was expected to start at 9.4 MB in 1991 and decline to 1.2 MB in 2005. By that time, only 24% of the beginning proved developed crude oil reserves would remain in the ground. Similarly, gas production was expected to drop from 45.3 to 6.2 MMCF over the fifteen years from 1991 to 2005. At the end of 2005, only about 14% of the beginning gas reserves would remain. Exhibit 3 presents projections for the production of proved developed reserves along with associated cash flows, excluding the above-mentioned fields in Michigan and the Gulf of Mexico. Proved undeveloped reserves xxx MW had other reserves that were proved but not developed. Developing these reserves would require drilling additional wells adjacent to existing wells, recompleting existing wellbores, or, in some cases, utilizing so-called "secondary" and “tertiary” recovery techniques. The most common of these was waterflooding, whereby a producing field is injected with water at selected sites to increase pressure in the field and push more oil and gas out of the ground. The properties in which Apache was interested comprised about 75% of MW's proved undeveloped reserves, including more than 80% of the available oil reserves. Bringing these reserves into production would require estimated expenditures for development of about $35 million over two years, and only minimal capital spending afterwards. Once these reserves were developed, about 70% of the oil and 90% of the gas could be extracted during the first fifteen years of production. In most fields, MW could leave these reserves undeveloped while retaining the right to develop them later. How long it could wait without forfeiting its rights varied from property to property, depending on the terms of the lease, on sharing arrangements with other companies, and on the level of production from other wells on the property. In virtually all cases, MW could wait 5-7 years without jeopardizing its rights. Exhibit 4 shows production and
W Petroleum Corporation(A) 295029 cash flow projections for exploiting proved undeveloped reserves, excluding, once again, those reserves in Michigan and the Gulf of Mexico Probable reserves Geologic and engineering data showed some reserves to be potentially recoverable, but a lack of complete data or some unresolved uncertainty caused them to be classified as probable rather than proved reserves. Hence, production and cash flow forecasts for probable reserves often had to be"risk-weighted"based on available data and historical experience in comparable fields, to arrive at an estimate that reflected their expected value. Amounts actually covered could be higher or lower, depending on geology and on the nature and extent of recovery operations undertaken. For the properties in MW, Amoco and Apache each made their own independent estimates. Exhibit 5 presents production and cash flow projections for MW's probable reserves, excluding Michigan and the Gulf of Mexico. Exploiting probable reserves would require significant expenditures, exceeding $40 million in the first five years, for additional engineering to prove the reserves and then for subsequent development and production, mostly using secondary recovery techniques. As with undeveloped reserves, engineering and development expenditures could be deferred, at MWs option, for at least 5-7 years Possible reserves Possible reserves were speculative in that geologic and engineering data suggested the presence of significant amounts of oil or gas, but proving, developing, and recovering them was deemed fairly risky. Accordingly, these also had to be risk-weighted in order to arrive at production and operating forecasts. Exhibit 6 shows that expenditures estimated at more than decide to pursue them. Anticipated expenditures were high because advanced recon hould mw $100 million within the first five years would be necessary to recover these reserves should MW both secondary and tertiary, would be required to develop and produce possible reserves ' echniques, Other opportunities In addition to the existing reserves, there were other opportunities to create value from the properties in MW. Perhaps the most obvious, if not the easiest, was further exploration. Through MW, Apache would own or have access to sophisticated technical data gathered by Amoco. These data and further exploration of Mw acreage might lead to the discovery of new reserves. All parties agreed, however, that the possibility of a major new discovery in these geographic areas was remote and the value of the exploration opportunities was probably about $25 million. This figure was not expected to be a controversial part of the negotiations The remaining opportunities did not involve increasing reserves, but finding ways to ptimize production. Processes such as recompletion, plugback, well-deepening, and repair could b used on some existing wells to lower costs, extend well life, or increase the rate of production Likewise, skillful timing and application of secondary and tertiary recovery methods could improve production even for wells in good repair. Such opportunities had to be recognized and exploited by the operator in field as they arose. Their net cash flow effects were positive, but usually not large for any one well, and difficult to estimate. They are not included in the projections shown in Exhibits 3-6. More generally, Apache believed it would be possible to lower the costs, both direct and indirect, of operating the properties in MW Aggregate MW cash flows The production and cash flow estimates presented in Exhibits 3-6 for each of the different types of reserves are aggregated by year in Exhibit 7 to produce one possible picture of the whole company, under specific purchase price, energy price, investment, and operating assumptions. In particular, Exhibits 3-7 all exclude properties in Michigan and the Gulf of Mexico. Were these properties to be included at the time Apache bought MW, they almost certainly would be sold as soon as possible. Projected revenues were based on forecasts of oil and gas prices, which in turn were based on opinions offered by Morgan Stanley's economists(Amoco and Apache each also prepared private forecasts, for use internally). In late 1990, most forecasters predicted gradually rising prices for both oil and gas over the next fifteen years; they differed
DO NOT COPY MW Petroleum Corporation (A) 295-029 5 cash flow projections for exploiting proved undeveloped reserves, excluding, once again, those reserves in Michigan and the Gulf of Mexico. Probable reserves xxx Geologic and engineering data showed some reserves to be potentially recoverable, but a lack of complete data or some unresolved uncertainty caused them to be classified as probable rather than proved reserves. Hence, production and cash flow forecasts for probable reserves often had to be "risk-weighted" based on available data and historical experience in comparable fields, to arrive at an estimate that reflected their expected value. Amounts actually recovered could be higher or lower, depending on geology and on the nature and extent of recovery operations undertaken. For the properties in MW, Amoco and Apache each made their own independent estimates. Exhibit 5 presents production and cash flow projections for MW’s probable reserves, excluding Michigan and the Gulf of Mexico. Exploiting probable reserves would require significant expenditures, exceeding $40 million in the first five years, for additional engineering to prove the reserves and then for subsequent development and production, mostly using secondary recovery techniques. As with undeveloped reserves, engineering and development expenditures could be deferred, at MW’s option, for at least 5-7 years. Possible reserves xxx Possible reserves were speculative in that geologic and engineering data suggested the presence of significant amounts of oil or gas, but proving, developing, and recovering them was deemed fairly risky. Accordingly, these also had to be risk-weighted in order to arrive at production and operating forecasts. Exhibit 6 shows that expenditures estimated at more than $100 million within the first five years would be necessary to recover these reserves should MW decide to pursue them. Anticipated expenditures were high because advanced recovery techniques, both secondary and tertiary, would be required to develop and produce possible reserves. Other opportunities xxx In addition to the existing reserves, there were other opportunities to create value from the properties in MW. Perhaps the most obvious, if not the easiest, was further exploration. Through MW, Apache would own or have access to sophisticated technical data gathered by Amoco. These data and further exploration of MW acreage might lead to the discovery of new reserves. All parties agreed, however, that the possibility of a major new discovery in these geographic areas was remote and the value of the exploration opportunities was probably about $25 million. This figure was not expected to be a controversial part of the negotiations. The remaining opportunities did not involve increasing reserves, but finding ways to optimize production. Processes such as recompletion, plugback, well-deepening, and repair could be used on some existing wells to lower costs, extend well life, or increase the rate of production. Likewise, skillful timing and application of secondary and tertiary recovery methods could improve production even for wells in good repair. Such opportunities had to be recognized and exploited by the operator in field as they arose. Their net cash flow effects were positive, but usually not large for any one well, and difficult to estimate. They are not included in the projections shown in Exhibits 3-6. More generally, Apache believed it would be possible to lower the costs, both direct and indirect, of operating the properties in MW. Aggregate MW cash flows xxxThe production and cash flow estimates presented in Exhibits 3-6 for each of the different types of reserves are aggregated by year in Exhibit 7 to produce one possible picture of the whole company, under specific purchase price, energy price, investment, and operating assumptions. In particular, Exhibits 3-7 all exclude properties in Michigan and the Gulf of Mexico. Were these properties to be included at the time Apache bought MW, they almost certainly would be sold as soon as possible. Projected revenues were based on forecasts of oil and gas prices, which in turn were based on opinions offered by Morgan Stanley's economists (Amoco and Apache each also prepared private forecasts, for use internally). In late 1990, most forecasters predicted gradually rising prices for both oil and gas over the next fifteen years; they differed