Please answer this question.. Very easy.

-What sources of value most plausibly account for the differences between buyer and seller?

-Structure and execute a discounted cash flow valuation of all of the MW reserves using APV. How much are

the reserves worth(use the ppt file to guide you and construct the table)? Is your estimate more likely to be biased high or low? What are the sources of the bias?

I also attach an answer key which is off topic, but the method is the similar(but different), the answer key may help you do the part.

Valuation problem End of year 0 1 2 3 4 annual cash flows EBIT $450.00 $450.00 $450.00 $450.00 interest $67.786 $67.786 $67.786 $67.786 EBT $382.214 $382.214 $382.214 $382.214 Taxes $152.885 $152.885 $152.885 $152.885 NI $229.328 $229.328 $229.328 $229.328 Dep $0.00 $0.00 $0.00 $0.00 CAPEX $0.00 $0.00 $0.00 $0.00 Change in WC $0.00 $0.00 $0.00 $0.00 Avail cash flow $229.328 $229.328 $229.328 $229.328 Equity cash flow annual debt schedule $229.328 $229.328 $229.328 $229.328 Beginning debt $847.330 $847.330 $847.330 $847.330 Debt terminal value estimates Firm Value Debt $847.330 $847.330 $847.330 $1,975.128 ### $847.330 ### $1,975.128 $847.330 $847.330 $847.330 $847.330 Equity annual discounting $1,127.798 ### ### $1,127.798 Debt/capital 0.429 0.429 0.429 0.429 Equity/capital 0.571 0.571 0.571 0.571 Asset beta 1.000 1.000 1.000 1.000 All equity WACC 16.500% 16.500% 16.500% 16.500% Debt beta 0 0 0 0 Equity beta 1.450 1.450 1.450 1.450 Cost of equity 20.324% Cost of debt 8.000% WACC-cost of capital EBIT (1 - T) 13.671% $270 PV of FCFF TV PV Of TV Total PV of FCFF Io NPV $237.528 20.324% 20.324% 8.000% 20.324% 8.000% 8.000% 13.671% 13.671% $270 $270 13.671% $270 $208.961 $183.830 $161.721 $1,974.992 $1,182.953 $792.039 $0.000 $270 $198.936 $270 $170.761 $270 $146.576 $1,636.364 $888.339 $0.000 $27.115 1.08 $27.115 1.166 $27.115 1.260 $25.11 $338.93 $1,636.371 $1,975.303 $23.25 $21.52 $27.115 1.360 $338.93 $249.13 $19.93 $229.328 1.203 $1,128.353 $538.314 $190.592 $1,128.357 $229.328 1.448 $229.328 1.742 $229.328 2.096 $158.399 $131.644 $109.408 $297.11 1.165 $1,800.713 $977.554 $255.034 $0 $1,800.704 $297.11 1.357 $297.11 1.581 $297.11 1.842 $218.91 $187.91 $161.29 $1,974.992 $270 $231.760 UCF PV of UCF TV PV of TV Io NPV(So) $1,636.371 T rB B 0.4 * 8% * 847.330 (1.08)^T TV 27.11/0.08 PV of TV NPFV NPV(So) APV NI Rs 1.20324^t TV PV of TV 1128.353/2.096 PV of LCF 229.328/(1.203)^t FTE EBIT(1-T) + T*Rbt*Bt Ro TV PV of TV of EBIT(1-T) + T*Rbt*Bt Io CCF 1.165 Steps: Operating Income = EBIT Net Operating Income after Taxes = 450 * (1 -0.4) = 270 Firm Value = Net Operating Income/ WACC Firm Value = 270/ 0.1367 = 1975.128 Levered Equity Beta bo = the unlevered asset beta bB = the debt beta Tc = the corporate tax rate 1.0000 0.0000 0.40 B = the market value of the debt S = the market value of the equity Rf = the risk free rate 0.0800 RM = the return on the market portfolio 0.1650 Next shows the debt to equity ratios B/S = the debt -to-equity ratio 0.7500 B/(B+S) = debt-to-valu ratio 0.4286 S/(B+S) = equity to value ratio 0.5714 Levered Equity beta 1.449971 Unlevered Asset Beta bS = the comparable's levered equity beta bB = the comparable's debt beta Tc = the comparable firm's corporate tax rate B = the market value of the comparable's debt S = the market value of the comparable's equity 1.80000 0.3725 0.36 $13,945 $7,000 Next shows the implied debt to equity ratios B/S = the debt -to-equity ratio 1.9921 B/(B+S) = debt-to-valu ratio 0.6658 S/(B+S) = equity to value ratio 0.3342 The unlevered asset beta is 0.999980 Operating Income = EBIT Net Operating Income after Taxes = 450 * (1 -0.4) = 270 Firm Value = Net Operating Income/ WACC Firm Value = 270/ 0.1367 = 1975.128 This calulates the levered equity beta, given asset (unlevered) & debt beta, leverage, & taxe rate Load your numbers here bo = the unlevered asset beta 1.0000 bB = the debt beta 0.0000 Tc = the corporate tax rate This loads the asset beta from the comparable on the next page. But if you know your asset beta, just type it in cell c-6. 0.40 B = the market value of the debt Tip: If you don't know the debt and equity values, but know B/S, S = the market value of the equity Rf = the risk free rate then enter B/S in cell c-15. 0.0800 RM = the return on the market portfolio 0.1650 Next shows the debt to equity ratios B/S = the debt -to-equity ratio 0.7500 B/(B+S) = debt-to-valu ratio 0.4286 S/(B+S) = equity to value ratio 0.5714 Tip: If you know B/V type it here 0.4286 and learn what B/S is 0.75009 Levered Equity beta 1.449971 The asset (unlevered) beta calculator, using equity & debt betas, leverage, & taxe rate Finding the Unlevered Asset Beta Example Load your numbers for the inital levered case. From a comparable firm or the current levered firm. bS = the comparable's levered equity beta 1.80000 bB = the comparable's debt beta 0.3725 Tc = the comparable firm's corporate tax rate B = the market value of the comparable's debt S = the market value of the comparable's equity 0.36 $13,945 $7,000 Tip: If you don't know B and equity S, but know B/S, then enter B/S in cell c-15 Next shows the implied debt to equity ratios B/S = the debt -to-equity ratio 1.9921 B/(B+S) = debt-to-valu ratio 0.6658 S/(B+S) = equity to value ratio 0.3342 Tip: If you know B/V type it here 0.4288 to learn B/S = 0.7505 The unlevered asset beta is 0.999980 III. DCF Methods Present value Terminal value and interim vale Terminal value, TV, & interim cash flows Terminal value and interim cash flows Example III.1, Project V-Plus annual cash flows, Project V-Plus annual debt schedule, Project V-Plus annual discounting, Project V-Plus terminal value estimates, Project VPlus A. NPV NPV/WACC Example NPV Rule Pros and cons of NPV B. The internal rate of return, irr irr Rule Graphically Graphically, many projects Cons of irr C. APV: Adjusted Present Value Finding NPV(S ) O proof APV=NPV APV Example APV Example Finding NPVF We look at the debt tax shield case APV Example APV Example APV Example Pros and cons of of APV D. FTE: Flow-to-Equity FTE Example FTE Example Proof FTE yields same as NPV Pros and cons of of FTE E. CCF Method CCF CCF Example CCF Example CCF Example Does CCF=NPV? Pros and cons of CCF For the exclusive use of N. Santoso, 2016. Harvard Business School 9 - 2 9 5 -029 Rev. November 21, 1994 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. 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 meanselectronic, mechanical, photocopying, recording, or otherwisewithout the permission of Harvard Business School. 1 This document is authorized for use only by Nicholas Santoso in Advanced Financial Management 2016 taught by Prof. Altinkilic, George Washington University from February 2016 to May 2016. For the exclusive use of N. Santoso, 2016. 295-029 MW Petroleum Corporation (A) 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. 2 This document is authorized for use only by Nicholas Santoso in Advanced Financial Management 2016 taught by Prof. Altinkilic, George Washington University from February 2016 to May 2016. For the exclusive use of N. Santoso, 2016. MW Petroleum Corporation (A) 295-029 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). 3 This document is authorized for use only by Nicholas Santoso in Advanced Financial Management 2016 taught by Prof. Altinkilic, George Washington University from February 2016 to May 2016. For the exclusive use of N. Santoso, 2016. 295-029 MW Petroleum Corporation (A) Table A: MW Petroleum's Estimated Reserves Oil (MMB) Gas (MMCF) Total (MMBOE) 73.6 381.1 137.1 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 Proved developed producing Proved developed non-producing 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 4 This document is authorized for use only by Nicholas Santoso in Advanced Financial Management 2016 taught by Prof. Altinkilic, George Washington University from February 2016 to May 2016. For the exclusive use of N. Santoso, 2016. MW Petroleum Corporation (A) 295-029 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 5 This document is authorized for use only by Nicholas Santoso in Advanced Financial Management 2016 taught by Prof. Altinkilic, George Washington University from February 2016 to May 2016. For the exclusive use of N. Santoso, 2016. 295-029 MW Petroleum Corporation (A) mainly in what they expected in the near term, during the Persian Gulf crisis, and in their specific predictions for the long-term rate of price increase. Estimates of operating expenses and overhead in Exhibits 3-7 also were developed by independent engineers and by Amoco and Morgan Stanley, respectively, not Apache. They were based, in the first instance, on historical costs, and in the second, on cash overhead savings Amoco actually expected to realize if MW were sold. Apache's experience could be better or worse, depending on how efficiently the properties were operated. Depreciation, depletion, and amortization estimates were compiled by the casewriter, based on schedules produced by Amoco and Morgan Stanley for the MW offering memorandum. These depended on the total purchase price, the allocation of the purchase price over the different reserves, and on the nature and timing of capital expenditures. Finally, Exhibit 7 assumes that all opportunities are exploited without delay; that is, capital spending for proved undeveloped, probable, and possible reserves commences in 1991 and proceeds subsequently as shown in Exhibits 3-6. If some or all of these expenditures were postponed, the corresponding operating cash flows also would be delayed. Risks Oil and gas exploration and production in the United States had been a volatile business during the preceding twenty years. The prime cause was volatility in energy prices, which had been pronounced since the early 1970s. Oil prices in particular had long been influenced by global political and economic events in addition to local supply and demand conditions. The sharp drop in oil prices in 1986 was followed by a period of volatile, though generally rising prices, punctuated by an upward spike associated with the invasion of Kuwait by Iraq in August 1990. By January 1991, war had broken out in the Persian Gulf region. However, other oil-producing countries, principally Saudi Arabia, had increased production to offset disruptions in supply and most of the world was united in opposition to Iraq's occupation of Kuwait. As a result, by year-end 1990 oil prices had actually fallen from their September highs. Nevertheless, prices were volatile in early 1991 and many analysts expected them to remain so. The annualized standard deviation of oil price changes, calculated based on observed weekly price fluctuations, was just over 50% per year at the end of January 1991. During 1989 and the first half of 1990, this annualized standard deviation was usually between 20% and 30%, but it had risen steadily since the beginning of the Persian Gulf crisis. Exhibit 8 displays historical data on oil prices and the standard deviation of oil price changes estimated from historical data on weekly prices. Gas prices had declined gradually from their relatively high levels in 1984, but had become much more volatile as they were decontrolled. During most of 1988 and 1989, the standard deviation of changes in gas prices was lower than for oil price changes. Then, in the fall of 1989, the volatility of gas price changes jumped upward to an annualized standard deviation of about 40% per year, nearly twice as high as for oil price changes. Not until the fall of 1990 did oil once again become more volatile than gas. Exhibit 8 displays data on historical gas prices and the standard deviation of gas price changes. In addition to price volatility, Apache naturally would face uncertainties about the quantities of oil and gas to be produced from the MW fields and the expense of producing it. Some risks derived from unanswered geological and engineering questions regarding the amounts of oil and gas physically present and the likely success of secondary and tertiary recovery operations. MW's reserves had been quantified by Amoco and Amoco's external engineering consultants based on seismic and other geological data, Amoco's production experience to date, and other factors that determined the effectiveness of specific recovery techniques. Apache's engineers and advisors also 6 This document is authorized for use only by Nicholas Santoso in Advanced Financial Management 2016 taught by Prof. Altinkilic, George Washington University from February 2016 to May 2016. For the exclusive use of N. Santoso, 2016. MW Petroleum Corporation (A) 295-029 were evaluating reserves and production operations. In addition to checking the independent reserve estimates, they were looking for cost-saving opportunities. The ability to manage costs both direct costs and overheadwould be an important determinant of MW's profitability. Structuring a Proposal To take advantage of what they regarded as an attractive opportunity for growth, Apache's executives and advisors had to design a transaction that would satisfy Amoco's desire to sell MW at a good price; that would be profitable for Apache; and that could be financed externally with a large component of debt. This last requirement was expected to be especially difficult, given the large size of MW, the Ba3 rating of Apache's debt, and the current lending environment. In 1991, the maximum loan-to-value ratio permitted by banks lending against oil and gas assets was typically 50% of the value of proved reserves. In addition, the credit approval process would require the analysis of a worst-case scenario, and loan terms would be set to protect the lender as much as possible in the worst case. The lending environment in 1991 was even tighter than these restrictions suggested, however, because U.S. banks were under pressure from regulators to improve the quality of their loan portfolios following losses on some highly levered transactions of the 1980s. Highly levered transactions were clearly out of favor, and some institutions were out of the market altogether, after the posting of reserves against bad loans had reduced their lending capacity. Consequently, there was a limited number of institutions among which to syndicate a large loan. There were several possible ways to make an MW acquisition more attractive to lenders. One was to reduce its size, though both Amoco and Apache would oppose reducing it beyond a certain point. Another was to have Apache or MW issue equity either to Amoco, to the public, or to some other private investor. Both Amoco's and Apache's shares were traded on the New York Stock Exchange; historical stock price data for both companies is presented in Exhibit 9. Yet another possibility was for Amoco itself to lend to Apache, or to guarantee some part of Apache's external acquisition debt. Finally, Apache could expect to borrow more, the more it could reduce the banks' exposure to a worst-case scenario. Experienced lenders' prime concern was an unexpected drop in oil prices like the one that had occurred in 1986. In early 1991, with a war underway in the Persian Gulf, most experts foresaw higher rather than lower energy prices, though they varied a great deal in their prediction of the near-term path of prices. Not surprisingly though, banks were among the most conservative forecasters. Some had lent too aggressively following the oil price shocks of the 1970s, only to lose badly when oil prices fell. Despite the problems Apache had to overcome, in at least one respect the lending environment was favorable. Inflation in the United States had been low for nearly a decade and interest rates had been generally falling. Long-term treasury bonds offered yields of 8% to 8.25%, and yields on B-rated debt had dropped more than 150 basis points in two months, despite the turmoil in the Middle East. Lower rates made whatever financing was available less expensive, and a lower opportunity cost of capital made long-term investments like MW more attractive. Contemporary financial market data are presented in Exhibit 10. 7 This document is authorized for use only by Nicholas Santoso in Advanced Financial Management 2016 taught by Prof. Altinkilic, George Washington University from February 2016 to May 2016. For the exclusive use of N. Santoso, 2016. 295-029 MW Petroleum Corporation (A) Exhibit 1 xxx Amoco Corporation, Selected Historical Financial Data (in $ millions except as noted) 1986 Income Statements Operating revenues Consumer excise taxes and other Total revenues Purchased crude oil, petroleum products & merchandise Operating expenses Petroleum exploration expenses Selling and administrative expenses Taxes other than income taxes Depreciation, depletion and amortization Interest expense Total costs and expenses Income before income taxes Income taxes Net income Balance Sheets Current assets Investments and other Properties, net Total assets Current liabilities Short term debt Long term debt Other liabilities Shareholders' equity Financial Ratios Return on operating revenues Return on assets Return on average equity Current ratio Debt / capital ratio Interest coverage ratio Debt rating Price - earnings ratio Cash flow per share Common shares outstanding, (millions) Year-end stock price 1987 1988 1989 1990 $18,281 2,064 20,345 $20,174 2,282 22,456 $21,150 2,769 23,919 $23,966 2,794 26,760 $28,010 3,571 31,581 7,593 3,451 925 1,358 2,592 2,418 468 18,805 8,970 3,370 647 1,424 2,840 2,295 410 19,956 8,471 3,915 767 1,466 3,207 2,318 468 20,612 10,619 4,380 726 1,888 3,224 2,500 728 24,065 13,697 5,395 693 1,991 3,395 2,413 587 28,171 1,540 793 2,500 1,140 3,307 1,244 2,695 1,085 3,410 1,497 747 1,360 2,063 1,610 1,913 4,200 1,337 18,169 23,706 5,899 1,072 18,151 25,122 5,393 1,431 23,095 29,919 6,428 1,355 22,647 30,430 8,216 1,287 22,706 32,209 4,180 174 3,556 4,472 4,503 468 3,303 4,741 4,799 444 6,274 5,060 5,148 483 5,915 5,200 6,092 492 5,464 6,093 11,324 12,107 13,342 13,684 14,068 4.1% 3.2% 6.5% 0.9 19.1% 7.4 Aaa 22.59 $6.3 502.0 $32 3/4 6.7% 5.4% 11.6% 1.1 22.1% 8.3 Aaa 14.7 $7.1 515.3 $34 1/2 9.8% 6.9% 16.2% 1.0 32.4% 8.8 Aaa 10.0 $8.1 517.1 $37 1/2 6.7% 5.3% 11.9% 1.1 30.8% 5.3 Aaa 14.4 $8.0 511.5 $54 5/8 6.8% 5.9% 13.8% 1.2 28.8% 7.4 Aaa 15.4 $8.3 502.0 $52 3/8 8 This document is authorized for use only by Nicholas Santoso in Advanced Financial Management 2016 taught by Prof. Altinkilic, George Washington University from February 2016 to May 2016. For the exclusive use of N. Santoso, 2016. MW Petroleum Corporation (A) 295-029 Exhibit 2xxx Apache Corporation, Selected Historical Financial Data (in $ millions, except as noted) 1986 1987 1988 1989 1990 106.0 100.5 141.7 246.9 273.4 82.1 23.5 184.6 25.5 14.6 15.9 18.9 15.1 61.4 27.6 14.4 16.7 14.5 96.3 42.5 31.3 23.4 21.4 116.8 44.6 22.1 21.5 11.0 (30.1) (14.8) (143.6) (62.1) 7.1 1.6 32.0 9.8 57.4 17.2 Income from continuing operations Discontinued operations: Income from discontinued operations, net of income taxes Gain on sale of discontinued operations, net of income taxes (15.3) (81.5) 5.5 22.2 40.2 4.4 0.6 2.6 0.0 0.0 0.0 8.8 0.0 0.0 0.0 Net income before extraordinary item Extraordinary item: Gain on early extinguishment from debt, net of income taxes (10.9) (72.1) 8.1 22.2 40.2 0.0 1.1 1.0 0.0 0.0 Net income (loss) (10.9) (71.0) 9.1 22.2 40.2 Balance Sheets Current assets Property and equipment, net Other assets Total assets 89.6 490.7 64.3 644.6 121.0 363.4 20.0 504.4 109.2 570.9 21.6 701.7 132.6 603.6 28.2 764.4 138.5 663.4 27.8 829.7 Current liabilities Long term debt 75.6 260.9 91.3 238.8 87.3 320.0 105.5 198.1 117.6 200.0 Shareholders' equity 207.4 128.8 206.9 350.3 386.8 1.3% 5.4% 1.11 60.7% 14.5 1.7 2.9% 8.0% 1.23 36.1% 21.4 2.5 4.8% 10.9% 1.13 34.1% 11.0 6.2 B2 33.2 $2.03 33.0 $7 7/8 NRa 19.4 $2.70 44.0 $18 3/8 Ba3 17.9 $3.52 44.7 $14 5/8 Income Statements Revenues Operating Expenses: Depreciation, depletion and amortization Operating costs Gathering and marketing costs Administrative, selling and other Financing costs, net Income from continuing operations before income taxes Provision for income taxes Financial Ratios Return on assets Return on average equity Current ratio Debt / capital ratio Interest expense (net) Interest coverage Debt rating (subordinated convertible debentures) Price - earnings ratio Cash flow per share Common shares outstanding (millions) Year-end stock price Unlevered (asset) betab 1.17 55.7% 15.9 1.26 65.0% 15.1 Ba3 B2 $2.87 20.3 $9 $2.45 20.1 $7 1//2 0.82 aNot rated. bThe mean asset beta, estimated by Morgan Stanley for six independent companies including Apache, was 0.64. 9 This document is authorized for use only by Nicholas Santoso in Advanced Financial Management 2016 taught by Prof. Altinkilic, George Washington University from February 2016 to May 2016. Notes to follow Exhibit 7. (21) Cumulative cash flow (20) Terminal value (19) Cash flow Direct production taxes Direct operating expense Overhead Fin. book DD&A Net income before taxes Federal and state income taxes: Current Deferred Total income taxes Profit contribution Non-cash charges Cash from operations Capital expenditures 89.4 169.4 80.0 44.4 (15.2) 29.2 52.0 30.1 82.0 2.0 48.5 (19.1) 29.4 55.8 38.9 94.7 5.4 89.4 23.6 80.3 32.2 45.2 81.2 180.4 82.1 262.5 8.1 36.8 1992 25.5 79.9 33.9 58.0 85.2 192.0 90.5 282.5 Cash Flows (in millions): (3) Revenues - oil (4) Revenues - gas (5) Total revenues (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16) (17) (18) 9.4 45.3 1991 Production: (1) Crude and condensates (MB) (2) Gas (MMCF) Proved Developed Reserves 239.1 69.6 39.3 (11.8) 27.4 48.6 23.7 72.3 2.7 21.6 79.8 28.6 35.6 76.1 168.2 73.5 241.7 7.1 29.5 1993 302.1 63.0 34.1 (9.5) 24.6 43.9 19.6 63.5 0.5 19.9 78.9 25.9 29.1 68.6 154.5 67.8 222.3 6.3 25.0 1994 358.0 56.0 29.9 (7.7) 22.3 40.4 16.1 56.6 0.6 18.0 76.0 23.0 23.8 62.7 139.4 64.1 203.5 5.3 21.7 1995 407.5 49.5 25.9 (5.9) 20.0 37.0 13.2 50.3 0.8 16.2 71.0 20.4 19.1 57.0 124.5 59.2 183.7 4.5 18.6 1996 452.4 44.9 23.6 (6.2) 17.4 32.2 13.5 45.7 0.8 14.4 63.8 18.3 19.6 49.7 109.1 56.7 165.8 3.7 16.5 1997 494.3 41.9 21.5 (5.1) 16.4 31.0 11.5 42.5 0.6 12.7 56.1 16.1 16.6 47.4 94.7 54.2 148.9 2.9 14.9 1998 531.9 37.6 19.3 (3.9) 15.4 29.2 9.5 38.7 1.1 11.4 49.9 13.9 13.3 44.6 82.7 50.4 133.1 2.4 12.8 1999 Exhibit 3xxx Proved Developed Reserves: Production and Cash Flow Projections ($ millions except as noted) 566.2 34.3 17.5 (3.1) 14.4 27.0 7.7 34.6 0.4 10.5 48.2 12.6 10.7 41.4 75.7 47.6 123.3 2.2 11.3 2000 600.4 34.2 17.4 (2.5) 14.9 27.9 6.4 34.4 0.1 9.8 45.5 10.8 9.0 42.8 72.0 45.8 117.8 1.9 10.3 2001 629.9 29.5 15.2 (2.2) 13.0 24.3 5.3 29.6 0.1 9.1 44.1 9.7 7.5 37.3 66.7 41.1 107.7 1.7 8.5 2002 656.0 26.1 13.4 (1.8) 11.7 21.7 4.5 26.2 0.1 8.5 44.5 9.0 6.3 33.3 63.4 38.2 101.6 1.5 7.6 2003 679.4 23.5 12.7 (1.4) 11.3 20.0 4.0 24.0 0.5 8.1 43.7 8.3 5.3 31.3 59.9 36.9 96.8 1.4 6.7 2004 -10- 793.6 92.1 22.1 12.0 (1.2) 10.8 18.9 3.3 22.2 0.1 7.7 43.0 7.8 4.5 29.7 56.6 36.1 92.7 1.2 6.2 2005 295-029 For the exclusive use of N. Santoso, 2016. This document is authorized for use only by Nicholas Santoso in Advanced Financial Management 2016 taught by Prof. Altinkilic, George Washington University from February 2016 to May 2016. Notes follow Exhibit 7. (21) Cumulative cash flow (20) Terminal value (19) Cash flow Direct production taxes Direct operating expense Overhead Fin. book DD&A Net income before taxes Federal and state income taxes: Current Deferred Total income taxes Profit contribution Non-cash charges Cash from operations Capital expenditures (13.5) (19.3) (5.8) 6.4 (4.2) 2.2 3.5 8.4 11.9 17.7 2.1 (4.1) (2.0) (4.2) 8.3 4.0 17.5 (13.5) 2.4 1.5 3.1 12.6 5.7 14.0 11.3 25.3 0.6 4.9 2 0.9 1.2 1.1 12.3 (6.2) 6.0 3.4 9.4 Cash Flows (in millions): (3) Revenues - oil (4) Revenues - gas (5) Total revenues (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16) (17) (18) 0.3 1.7 Year 1 Production: (1) Crude and condensates (MB) (2) Gas (MMCF) Proved Undeveloped Reserves (11.7) 7.6 7.0 (3.5) 3.5 5.8 7.1 12.9 5.3 2.3 2.0 3.2 10.6 9.2 12.9 14.5 27.4 0.5 5.6 3 (6.4) 5.2 5.0 (3.0) 2.0 3.1 6.3 9.3 4.1 1.8 2.3 2.4 9.3 5.1 11.8 9.1 20.9 0.5 3.3 4 (1.9) 4.6 4.3 (2.6) 1.7 2.6 5.5 8.1 3.5 1.7 2.8 2.1 8.1 4.2 12.3 6.7 19.0 0.5 2.3 5 4.9 6.7 4.1 (2.1) 2.1 3.4 4.6 8.0 1.3 1.7 3.4 2.2 6.7 5.5 13.2 6.2 19.4 0.5 2.0 6 14.6 9.7 5.1 (2.1) 2.9 5.1 4.7 9.8 0.1 2.0 3.3 2.5 6.8 8.1 16.1 6.6 22.7 0.5 2.0 7 27.1 12.5 6.5 (1.8) 4.7 8.8 4.0 12.8 0.3 2.5 3.3 3.0 5.8 13.5 21.0 7.1 28.1 0.7 2.2 8 43.1 16.0 8.0 (1.3) 6.7 12.8 3.2 16.0 0.0 3.1 4.5 3.7 4.6 19.5 27.1 8.2 35.3 0.8 2.3 9 Exhibit 4 xxx Proved Undeveloped Reserves: Production and Cash Flow Projections ($ millions except as noted) 58.2 15.1 7.7 (1.1) 6.6 12.6 2.6 15.2 0.1 2.8 3.4 3.3 3.7 19.2 25.2 7.2 32.4 0.7 1.9 10 65.0 6.8 7.6 (1.2) 6.3 11.8 3.1 14.9 8.1 2.8 3.7 2.9 4.3 18.2 25.3 6.6 31.9 0.7 1.6 11 79.7 14.7 7.5 (1.0) 6.5 12.1 2.5 14.7 (0.0) 3.0 4.2 2.9 3.6 18.6 26.8 5.5 32.3 0.7 1.3 12 95.0 15.2 7.9 (0.9) 7.1 13.3 2.2 15.4 0.2 3.1 4.5 3.0 3.0 20.3 28.7 5.2 33.9 0.7 1.3 13 111.5 16.5 8.8 (0.7) 8.1 14.7 1.9 16.6 0.0 2.9 4.7 3.1 2.5 22.8 30.9 5.2 36.1 0.7 1.0 14 -11- 194.3 67.8 15.1 8.1 (0.6) 7.5 13.5 1.6 15.1 (0.0) 3.0 4.8 2.8 2.1 21.1 29.3 4.5 33.8 0.6 0.9 15 295-029 For the exclusive use of N. Santoso, 2016. This document is authorized for use only by Nicholas Santoso in Advanced Financial Management 2016 taught by Prof. Altinkilic, George Washington University from February 2016 to May 2016. Notes follow Exhibit 7. (21) Cumulative cash flow (20) Terminal value (19) Cash flow Direct production taxes Direct operating expense Overhead Fin. book DD&A Net income before taxes Federal and state income taxes: Current Deferred Total income taxes Profit contribution Non-cash charges Cash from operations Capital expenditures (5.8) (2.0) 3.8 3.7 (0.0) 3.7 7.3 0.8 8.1 4.3 2.9 (0.2) 2.6 4.0 0.2 4.2 10.0 (5.8) 1.3 0.7 1.9 0.8 11.0 6.3 9.4 15.7 0.3 4.2 2 0.8 0.4 1.3 0.4 6.6 3.7 5.8 9.5 Cash Flows (in millions): (3) Revenues - oil (4) Revenues - gas (5) Total revenues (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16) (17) (18) 0.2 2.8 Year 1 Production: (1) Crude and condensates (MB) (2) Gas (MMCF) Probable Reserves (3.5) (1.5) 4.8 (0.2) 4.6 8.9 1.1 9.9 11.4 1.7 0.8 2.3 1.2 13.5 8.0 11.6 19.5 0.4 4.9 3 (6.0) (2.5) 4.8 (0.2) 4.5 9.3 2.2 11.5 14.0 2.0 2.6 2.8 2.5 13.8 9.6 14.1 23.7 0.4 5.3 4 3.7 9.7 3.8 0.3 4.1 10.5 1.9 12.3 2.6 2.2 4.4 3.0 1.6 14.5 13.3 12.3 25.7 0.5 4.2 5 15.7 11.9 4.2 0.3 4.5 10.8 1.6 12.4 0.5 2.3 4.7 2.9 1.3 15.4 14.3 12.3 26.6 0.5 3.8 6 28.8 13.1 5.5 0.1 5.6 11.7 1.6 13.4 0.3 2.7 5.3 3.1 1.5 17.3 17.0 13.0 30.0 0.7 4.5 7 0.9 4.2 8 41.8 13.0 5.8 (0.0) 5.7 11.7 1.9 13.6 0.6 2.9 5.7 3.3 2.0 17.4 19.6 11.6 31.2 Exhibit 5 xxx Probable Reserves: Production and Cash Flow Projections ($ millions except as noted) 55.0 13.2 5.5 0.0 5.6 11.9 1.6 13.5 0.3 3.1 6.0 3.0 1.5 17.5 20.3 10.7 31.0 0.8 3.3 9 66.0 11.0 5.4 0.0 5.4 10.1 1.4 11.5 0.5 3.0 6.4 2.8 1.4 15.5 19.8 9.3 29.2 0.7 2.4 10 76.3 10.2 5.0 0.0 5.0 9.3 1.4 10.7 0.5 2.8 7.0 2.6 1.4 14.3 18.6 9.5 28.1 0.6 2.1 11 86.3 10.0 4.7 0.0 4.7 8.6 1.4 10.0 0.0 2.7 7.4 2.5 1.4 13.3 17.1 10.1 27.2 0.5 2.0 12 94.7 8.4 4.0 0.0 4.0 7.2 1.4 8.6 0.2 2.5 7.4 2.2 1.4 11.3 15.8 8.8 24.7 0.4 1.5 13 101.7 7.0 3.5 0.0 3.5 6.1 1.4 7.5 0.5 2.3 7.3 2.0 1.3 9.6 14.5 8.1 22.6 0.4 1.3 14 -12- 159.0 51.0 6.4 3.0 0.0 3.0 5.1 1.3 6.4 0.0 2.1 7.2 1.9 1.3 8.1 13.4 7.3 20.6 0.3 1.1 15 295-029 For the exclusive use of N. Santoso, 2016. This document is authorized for use only by Nicholas Santoso in Advanced Financial Management 2016 taught by Prof. Altinkilic, George Washington University from February 2016 to May 2016. Notes follow Exhibit 7. (21) Cumulative cash flow (20) Terminal value (19) Cash flow Direct production taxes Direct operating expense Overhead Fin. book DD&A Net income before taxes Federal and state income taxes: Current Deferred Total income taxes Profit contribution Non-cash charges Cash from operations Capital expenditures (8.6) (11.6) (2.9) 3.1 (0.0) 3.1 5.4 1.4 6.8 9.8 0.8 (0.4) 0.3 0.8 0.3 1.1 9.7 (8.6) 1.2 1.0 1.6 1.4 8.5 10.1 3.6 13.7 0.8 3.5 2 0.3 0.2 0.4 0.7 1.2 2.1 0.6 2.7 Cash Flows (in millions): (3) Revenues - oil (4) Revenues - gas (5) Total revenues (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16) (17) (18) 0.1 0.5 Year 1 Production: (1) Crude and condensates (MB) (2) Gas (MMCF) Possible Reserves (25.1) (13.5) 4.2 (0.3) 4.0 7.0 1.9 8.9 22.4 1.6 1.5 2.1 2.2 10.9 13.2 5.1 18.3 0.9 3.8 3 (53.5) (28.4) 4.4 (0.5) 3.9 6.2 4.4 10.6 38.9 1.8 2.1 2.5 4.9 10.0 14.4 6.9 21.3 0.8 3.9 4 (70.6) (17.1) 3.2 0.7 3.8 6.1 4.2 10.4 27.4 2.2 6.5 2.9 3.5 10.0 18.0 7.2 25.1 0.8 3.6 5 (68.1) 2.5 3.2 0.7 3.9 5.5 3.8 9.3 6.8 2.8 13.1 3.4 3.1 9.4 24.1 7.7 31.8 1.0 3.7 6 (55.6) 12.5 5.4 0.2 5.6 9.3 3.8 13.2 0.7 5.0 21.2 5.2 3.6 15.0 42.3 7.7 50.0 1.6 3.2 7 2.1 3.0 8 (42.2) 13.4 6.1 (0.2) 6.0 10.0 4.4 14.4 1.0 6.8 31.9 6.9 4.5 16.0 59.1 7.0 66.1 Exhibit 6 xxx Possible Reserves: Production and Cash Flow Projections ($ millions except as noted) (23.8) 18.5 7.8 0.2 8.0 15.4 3.7 19.1 0.7 7.9 33.0 7.3 3.5 23.4 67.4 7.8 75.2 2.4 3.2 9 (7.7) 16.1 8.9 0.0 8.9 15.7 3.3 19.1 3.0 8.0 35.1 7.6 3.3 24.6 69.4 9.3 78.7 2.3 2.8 10 13.5 21.2 10.9 0.0 11.0 20.2 3.3 23.5 2.3 7.1 26.4 6.9 3.3 31.1 66.8 8.1 74.9 2.0 1.9 11 33.6 20.1 9.4 0.0 9.4 16.9 3.3 20.1 0.0 6.7 26.3 6.3 3.2 26.2 62.7 6.1 68.8 1.7 1.3 12 52.4 18.8 8.8 0.0 8.8 15.7 3.2 18.9 0.1 6.4 25.7 5.9 3.2 24.5 59.7 5.9 65.7 1.6 1.4 13 69.2 16.8 7.9 0.0 7.9 13.7 3.2 16.9 0.0 6.1 25.8 5.7 3.1 21.6 56.4 5.9 62.3 1.4 1.2 14 -13- 155.9 72.3 14.4 6.7 0.0 6.8 11.4 3.1 14.5 0.0 5.6 25.6 5.3 3.1 18.1 52.0 5.7 57.7 1.2 1.0 15 295-029 For the exclusive use of N. Santoso, 2016. This document is authorized for use only by Nicholas Santoso in Advanced Financial Management 2016 taught by Prof. Altinkilic, George Washington University from February 2016 to May 2016. Direct production taxes Direct operating expense Overhead Fin. book DD&A Net income before taxes Federal and state income taxes: Current Deferred Total income taxes Profit contribution Non-cash charges Cash from operations Capital expenditures Notes follow Exhibit 7. (21) Cumulative cash flow (20) Terminal value (19) Cash flow (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16) (17) (18) Cash Flows (in millions): (3) Revenues - oil (4) Revenues - gas (5) Total revenues Production: (1) Net crude and condensates (MB) (2) Net gas (MMCF) Aggregated MW Projections 61.4 136.5 75.1 57.6 (19.4) 38.2 68.3 40.6 108.9 33.8 54.2 (23.8) 30.4 56.4 47.6 104.0 42.6 61.4 28.5 83.5 38.7 60.0 106.5 210.9 106.3 317.2 9.8 49.5 2 27.5 81.7 36.6 71.4 86.8 203.9 100.3 304.1 10.0 50.2 Year 1 198.8 62.2 55.3 (15.8) 39.5 70.3 33.8 104.0 41.8 27.3 84.1 36.3 49.6 109.7 202.3 104.7 306.9 8.9 43.7 3 236.2 37.4 48.3 (13.2) 35.0 62.5 32.4 95.0 57.5 25.5 85.9 33.6 45.7 97.5 190.3 97.9 288.3 8.1 37.5 4 289.3 53.2 41.2 (9.3) 31.9 59.6 27.7 87.3 34.1 24.1 89.7 31.0 37.0 91.5 183.0 90.3 273.3 7.1 31.8 5 360.0 70.7 37.4 (7.0) 30.5 56.8 23.3 80.0 9.4 23.0 92.2 28.8 30.2 87.2 176.1 85.4 261.5 6.5 28.1 6 440.2 80.2 39.5 (7.9) 31.6 58.4 23.6 82.1 1.9 24.1 93.7 29.2 31.6 90.0 184.5 84.0 268.5 6.5 26.2 7 Exhibit 7 xxx Aggregated MW Production and Cash Flow Projections ($ millions except as noted) 520.9 80.7 39.9 (7.1) 32.8 61.5 21.8 83.3 2.6 25.0 97.0 29.3 28.9 94.3 194.4 80.0 274.4 6.6 24.4 8 606.2 85.3 40.7 (4.9) 35.8 69.2 18.1 87.3 2.0 25.4 93.3 27.9 23.0 105.0 197.5 77.2 274.7 6.4 21.6 9 682.7 76.5 39.4 (4.1) 35.3 65.3 15.1 80.4 3.9 24.3 93.2 26.3 19.2 100.7 190.2 73.4 263.6 5.8 18.3 10 755.2 72.5 40.9 (3.7) 37.2 69.2 14.3 83.5 11.0 22.5 82.6 23.2 18.0 106.5 182.7 70.0 252.7 5.2 15.9 11 829.5 74.3 36.8 (3.2) 33.6 61.9 12.5 74.4 0.0 21.5 82.0 21.4 15.7 95.5 173.2 62.8 236.0 4.6 13.1 12 898.0 68.5 34.2 (2.6) 31.6 57.9 11.3 69.1 0.6 20.4 82.0 20.1 13.8 89.5 167.7 58.1 225.8 4.3 11.8 13 283.1 58.0 29.8 (1.8) 28.1 48.9 9.3 58.2 0.2 18.4 80.6 17.8 11.0 77.0 151.3 53.5 204.8 3.4 9.3 15 -14- 961.8 1302.9 63.8 32.8 (2.0) 30.8 54.5 10.4 64.9 1.1 19.4 81.5 19.1 12.3 85.4 161.7 56.1 217.8 3.8 10.2 14 295-029 For the exclusive use of N. Santoso, 2016. This document is authorized for use only by Nicholas Santoso in Advanced Financial Management 2016 taught by Prof. Altinkilic, George Washington University from February 2016 to May 2016. For the exclusive use of N. Santoso, 2016. MW Petroleum Corporation (A) 295-029 Line Notes to MW Petroleum Projections, Exhibits 3 - 7 (0) The cash flow projections presented in Exhibits 3-7 were prepared by the casewriter based primarily on operating and financial data from the MW offering memorandum. (1) Crude and condensates - annual production quantities of crude oil and associated liquid hydrocarbons expressed in thousands of barrels (MB). One barrel is equivalent to 42 gallons. (2) Gas - annual production quantities of gas expressed in millions of standard cubic feet (MMCF). A standard cubic foot is one cubic foot of gas at one atmosphere and 60 degrees Fahrenheit. (3-5) Revenues - projected annual oil, gas and total revenues, net of royalties, based upon the production quantities on lines 1 and 2. (6) Direct production taxes - includes production and ad valorem taxes. (7) Direct operating expense - includes lease and well operating costs, escalated at 5% per year. (8) Overhead - general and administrative expenses, such as non-field personnel compensation, as estimated by Amoco and Morgan Stanley. (9) Financial book DD&A - depreciation, depletion and amortization, computed for financial reporting purposes, including allocation and amortization of the purchase price; estimated by the casewriter, based on the MW offering memorandum. (10) Net income before taxes - revenues less the sum of the expenses in lines 6 through 9. (11) Federal and state income taxes - projected federal and state income tax expense broken down into current and deferred portions. (12) Current - the current portion of federal and state income taxes. (13) Deferred - the deferred portion of federal and state income taxes relating primarily to the timing difference in book versus tax treatment of DD&A. (14) Total income taxes - the sum of current and deferred taxes on lines 12 and 13. (15) Profit contribution - the difference between net income before taxes on line 10 and total income taxes on line 14. (16) Non-cash charges - includes financial book DD&A and deferred income taxes. (17) Cash from operations - profit contribution (line 15) plus non-cash charges (line 16). (18) Capital expenditures - investments (including additions to working capital) required to perform procedures and projects such as workovers, recompletions, development drilling, waterflooding, etc., to extract additional reserves. (19) Cash flow - cash from operations less capital expenditures. (20) Terminal value - the estimated present value, in year 15, of all future net cash flows until reserves are exhausted. Discounting performed at 13% per year. (21) Cumulative cash flow - the accumulated value of the cash flows presented in line 19. 15 This document is authorized for use only by Nicholas Santoso in Advanced Financial Management 2016 taught by Prof. Altinkilic, George Washington University from February 2016 to May 2016. For the exclusive use of N. Santoso, 2016. 295-029 Exhibit 8 MW Petroleum Corporation (A) Historical Oil and Natural Gas Prices and Volatilities 16 This document is authorized for use only by Nicholas Santoso in Advanced Financial Management 2016 taught by Prof. Altinkilic, George Washington University from February 2016 to May 2016. Exhibit 9 Historical Stock Price Data for Amoco and Apache 295-029 -17- For the exclusive use of N. Santoso, 2016. This document is authorized for use only by Nicholas Santoso in Advanced Financial Management 2016 taught by Prof. Altinkilic, George Washington University from February 2016 to May 2016. For the exclusive use of N. Santoso, 2016. 295-029 MW Petroleum Corporation (A) Exhibit 10xxx Selected Contemporary Financial Market Data U.S. Government Bond Yields, Year-end 1990xxx Term Yield 30-day 10-year 30-year 6.52% 8.03% 8.24% Note: Yields are expressed on a bond-equivalent basis. Industrial Bond Yieldsxxx Rating Dec-90 Jan-91 Feb-91 AAA AA A BBB BB B 9.08% 9.45% 9.54% 11.55% 12.41% 19.02% 8.95% 9.40% 9.50% 11.67% 12.24% 20.20% 8.80% 9.09% 9.29% 10.38% 12.30% 17.37% Sources: Wall Street Journal, Morgan Stanley, Standard & Poor's. 18 This document is authorized for use only by Nicholas Santoso in Advanced Financial Management 2016 taught by Prof. Altinkilic, George Washington University from February 2016 to May 2016. MW Petroleum Corp. - A Harvard Business School Case #295-029 Case Software #XLS083 Copyright 2010 President and Fellows of Harvard College. No part of this product may be reproduced, stored in a retrieval system or transmitted in any form or by any meanselectronic, mechanical, photocopying, recording or otherwisewithout the permission of Harvard Business School. Table A: MW Petroleum's Estimated Reserves Oil (MMB) Proved developed producing Proved developed non-producing Proved undeveloped Total Proved Total Probable Total Possible Total Reserves 73.6 7.9 15.8 97.3 14.1 44.5 155.9 Gas (MMCF) 381.1 61.5 58.5 501.1 70.4 75.4 646.9 Total (MMBOE) 137.1 18.1 25.6 180.8 25.8 57.1 263.7 Exhibit 1 Amoco Corporation, Selected Historical Financial Data (in $ millions except as noted) 1986 Income Statements Operating revenues Consumer excise taxes and other Total revenues Purchased crude oil, petroleum products & merchandise Operating expenses Petroleum exploration expenses Selling and administrative expenses Taxes other than income taxes Depreciation, depletion and amortization Interest expense Total costs and expenses Income before income taxes Income taxes Net income Balance Sheets Current assets Investments and other Properties, net Total assets Current liabilities Short term debt Long term debt Other liabilities Shareholders' equity Financial Ratios Return on operating revenues Return on assets Return on average equity Current ratio Debt / capital ratio Interest coverage ratio Debt rating Price - earnings ratio Cash flow per share Common shares outstanding, (millions) Year-end stock price 1987 1988 1989 1990 $18,281 2,064 20,345 $20,174 2,282 22,456 $21,150 2,769 23,919 $23,966 2,794 26,760 $28,010 3,571 31,581 7,593 3,451 925 1,358 2,592 2,418 468 18,805 1,540 793 8,970 3,370 647 1,424 2,840 2,295 410 19,956 2,500 1,140 8,471 3,915 767 1,466 3,207 2,318 468 20,612 3,307 1,244 10,619 4,380 726 1,888 3,224 2,500 728 24,065 2,695 1,085 13,697 5,395 693 1,991 3,395 2,413 587 28,171 3,410 1,497 747 1,360 2,063 1,610 1,913 4,200 1,337 18,169 23,706 5,899 1,072 18,151 25,122 5,393 1,431 23,095 29,919 6,428 1,355 22,647 30,430 8,216 1,287 22,706 32,209 4,180 174 3,556 4,472 4,503 468 3,303 4,741 4,799 444 6,274 5,060 5,148 483 5,915 5,200 6,092 492 5,464 6,093 11,324 12,107 13,342 13,684 14,068 4.1% 3.2% 6.5% 0.9 19.1% 7.4 Aaa 22.59 $6.3 502.0 $32 3/4 6.7% 5.4% 11.6% 1.1 22.1% 8.3 Aaa 14.7 $7.1 515.3 $34 1/2 9.8% 6.9% 16.2% 1.0 32.4% 8.8 Aaa 10.0 $8.1 517.1 $37 1/2 6.7% 5.3% 11.9% 1.1 30.8% 5.3 Aaa 14.4 $8.0 511.5 $54 5/8 6.8% 5.9% 13.8% 1.2 28.8% 7.4 Aaa 15.4 $8.3 502.0 $52 3/8 Exhibit 2 Apache Corporation, Selected Historical Financial Data (in $ millions, except as noted) 1986 1987 1988 1989 1990 106.0 100.5 141.7 246.9 273.4 82.1 23.5 184.6 25.5 14.6 15.9 18.9 15.1 61.4 27.6 14.4 16.7 14.5 96.3 42.5 31.3 23.4 21.4 (30.1) (14.8) (143.6) (62.1) 7.1 1.6 32.0 9.8 57.4 17.2 Income from continuing operations Discontinued operations: Income from discontinued operations, net of income taxes Gain on sale of discontinued operations, net of income taxes (15.3) (81.5) 5.5 22.2 40.2 4.4 0.6 2.6 0.0 0.0 0.0 8.8 0.0 0.0 0.0 Net income before extraordinary item Extraordinary item: Gain on early extinguishment from debt, net of income taxes (10.9) (72.1) 0.0 1.1 Net income (loss) (10.9) (71.0) Balance Sheets Current assets Property and equipment, net Other assets Total assets 89.6 490.7 64.3 644.6 121.0 363.4 20.0 504.4 109.2 570.9 21.6 701.7 132.6 603.6 28.2 764.4 138.5 663.4 27.8 829.7 Current liabilities Long term debt 75.6 260.9 91.3 238.8 87.3 320.0 105.5 198.1 117.6 200.0 Shareholders' equity 207.4 128.8 206.9 350.3 386.8 1.3% 5.4% 1.11 60.7% 14.5 1.7 2.9% 8.0% 1.23 36.1% 21.4 2.5 4.8% 10.9% 1.13 34.1% 11.0 6.2 Income Statements Revenues Operating Expenses: Depreciation, depletion and amortization Operating costs Gathering and marketing costs Administrative, selling and other Financing costs, net Income from continuing operations before income taxes Provision for income taxes Financial Ratios Return on assets Return on average equity Current ratio Debt / capital ratio Interest expense (net) Interest coverage Debt rating (subordinated convertible debentures) Price - earnings ratio Cash flow per share Common shares outstanding (millions) Year-end stock price 1.17 55.7% 15.9 1.26 65.0% 15.1 Ba3 B2 $2.87 20.3 $9 $2.45 20.1 $7 1//2 8.1 1.0 9.1 B2 33.2 $2.03 33.0 $7 7/8 22.2 0.0 22.2 NRa 19.4 $2.70 44.0 $18 3/8 Unlevered (asset) betab a Not rated. The mean asset beta, estimated by Morgan Stanley for six independent companies including Apache, was 0.64. b 116.8 44.6 22.1 21.5 11.0 40.2 0.0 40.2 Ba3 17.9 $3.52 44.7 $14 5/8 0.82 Exhibit 3 Proved Developed Reserves: Production and Cash Flow Projections ($ millions except as noted) Proved Developed Reserves 1991 Production: (1) Crude and condensates (MB) (2) Gas (MMCF) Cash Flows (in millions): (3) Revenues - oil (4) Revenues - gas (5) Total revenues (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16) (17) (18) Direct production taxes Direct operating expense Overhead Fin. book DD&A Net income before taxes Federal and state income taxes: Current Deferred Total income taxes Profit contribution Non-cash charges Cash from operations Capital expenditures (19) Cash flow 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 9.4 45.3 8.1 36.8 7.1 29.5 6.3 25.0 5.3 21.7 4.5 18.6 3.7 16.5 2.9 14.9 2.4 12.8 2.2 11.3 1.9 10.3 1.7 8.5 1.5 7.6 1.4 6.7 1.2 6.2 192.0 90.5 282.5 180.4 82.1 262.5 168.2 73.5 241.7 154.5 67.8 222.3 139.4 64.1 203.5 124.5 59.2 183.7 109.1 56.7 165.8 94.7 54.2 148.9 82.7 50.4 133.1 75.7 47.6 123.3 72.0 45.8 117.8 66.7 41.1 107.7 63.4 38.2 101.6 59.9 36.9 96.8 56.6 36.1 92.7 25.5 79.9 33.9 58.0 85.2 23.6 80.3 32.2 45.2 81.2 21.6 79.8 28.6 35.6 76.1 19.9 78.9 25.9 29.1 68.6 18.0 76.0 23.0 23.8 62.7 16.2 71.0 20.4 19.1 57.0 14.4 63.8 18.3 19.6 49.7 12.7 56.1 16.1 16.6 47.4 11.4 49.9 13.9 13.3 44.6 10.5 48.2 12.6 10.7 41.4 9.8 45.5 10.8 9.0 42.8 9.1 44.1 9.7 7.5 37.3 8.5 44.5 9.0 6.3 33.3 8.1 43.7 8.3 5.3 31.3 7.7 43.0 7.8 4.5 29.7 48.5 (19.1) 29.4 55.8 38.9 94.7 5.4 44.4 (15.2) 29.2 52.0 30.1 82.0 2.0 39.3 (11.8) 27.4 48.6 23.7 72.3 2.7 34.1 (9.5) 24.6 43.9 19.6 63.5 0.5 29.9 (7.7) 22.3 40.4 16.1 56.6 0.6 25.9 (5.9) 20.0 37.0 13.2 50.3 0.8 23.6 (6.2) 17.4 32.2 13.5 45.7 0.8 21.5 (5.1) 16.4 31.0 11.5 42.5 0.6 19.3 (3.9) 15.4 29.2 9.5 38.7 1.1 17.5 (3.1) 14.4 27.0 7.7 34.6 0.4 17.4 (2.5) 14.9 27.9 6.4 34.4 0.1 15.2 (2.2) 13.0 24.3 5.3 29.6 0.1 13.4 (1.8) 11.7 21.7 4.5 26.2 0.1 12.7 (1.4) 11.3 20.0 4.0 24.0 0.5 12.0 (1.2) 10.8 18.9 3.3 22.2 0.1 89.4 80.0 69.6 63.0 56.0 49.5 44.9 41.9 37.6 34.3 34.2 29.5 26.1 23.5 22.1 (20) Terminal value (21) Cumulative cash flow Notes to follow Exhibit 7. 2005 92.1 89.4 169.4 239.1 302.1 358.0 407.5 452.4 494.3 531.9 566.2 600.4 629.9 656.0 679.4 793.6 Exhibit 4 Proved Undeveloped Reserves: Production and Cash Flow Projections ($ millions except as noted) Proved Undeveloped Reserves Year 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Production: (1) Crude and condensates (MB) (2) Gas (MMCF) 0.3 1.7 0.6 4.9 0.5 5.6 0.5 3.3 0.5 2.3 0.5 2.0 0.5 2.0 0.7 2.2 0.8 2.3 0.7 1.9 0.7 1.6 0.7 1.3 0.7 1.3 0.7 1.0 0.6 0.9 Cash Flows (in millions): (3) Revenues - oil (4) Revenues - gas (5) Total revenues 6.0 3.4 9.4 14.0 11.3 25.3 12.9 14.5 27.4 11.8 9.1 20.9 12.3 6.7 19.0 13.2 6.2 19.4 16.1 6.6 22.7 21.0 7.1 28.1 27.1 8.2 35.3 25.2 7.2 32.4 25.3 6.6 31.9 26.8 5.5 32.3 28.7 5.2 33.9 30.9 5.2 36.1 29.3 4.5 33.8 0.9 1.2 1.1 12.3 (6.2) 2.4 1.5 3.1 12.6 5.7 2.3 2.0 3.2 10.6 9.2 1.8 2.3 2.4 9.3 5.1 1.7 2.8 2.1 8.1 4.2 1.7 3.4 2.2 6.7 5.5 2.0 3.3 2.5 6.8 8.1 2.5 3.3 3.0 5.8 13.5 3.1 4.5 3.7 4.6 19.5 2.8 3.4 3.3 3.7 19.2 2.8 3.7 2.9 4.3 18.2 3.0 4.2 2.9 3.6 18.6 3.1 4.5 3.0 3.0 20.3 2.9 4.7 3.1 2.5 22.8 3.0 4.8 2.8 2.1 21.1 2.1 (4.1) (2.0) (4.2) 8.3 4.0 17.5 6.4 (4.2) 2.2 3.5 8.4 11.9 17.7 7.0 (3.5) 3.5 5.8 7.1 12.9 5.3 5.0 (3.0) 2.0 3.1 6.3 9.3 4.1 4.3 (2.6) 1.7 2.6 5.5 8.1 3.5 4.1 (2.1) 2.1 3.4 4.6 8.0 1.3 5.1 (2.1) 2.9 5.1 4.7 9.8 0.1 6.5 (1.8) 4.7 8.8 4.0 12.8 0.3 8.0 (1.3) 6.7 12.8 3.2 16.0 0.0 7.7 (1.1) 6.6 12.6 2.6 15.2 0.1 7.6 (1.2) 6.3 11.8 3.1 14.9 8.1 7.5 (1.0) 6.5 12.1 2.5 14.7 0.0 7.9 (0.9) 7.1 13.3 2.2 15.4 0.2 8.8 (0.7) 8.1 14.7 1.9 16.6 0.0 8.1 (0.6) 7.5 13.5 1.6 15.1 0.0 (13.5) (5.8) 7.6 5.2 4.6 6.7 9.7 12.5 16.0 15.1 6.8 14.7 15.2 16.5 15.1 (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16) (17) (18) Direct production taxes Direct operating expense Overhead Fin. book DD&A Net income before taxes Federal and state income taxes: Current Deferred Total income taxes Profit contribution Non-cash charges Cash from operations Capital expenditures (19) Cash flow (20) Terminal value (21) Cumulative cash flow Notes follow Exhibit 7. 67.8 (13.5) (19.3) (11.7) (6.4) (1.9) 4.9 14.6 27.1 43.1 58.2 65.0 79.7 95.0 111.5 194.3 Exhibit 5 Probable Reserves: Production and Cash Flow Projections ($ millions except as noted) Probable Reserves Year 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Production: (1) Crude and condensates (MB) (2) Gas (MMCF) 0.2 2.8 0.3 4.2 0.4 4.9 0.4 5.3 0.5 4.2 0.5 3.8 0.7 4.5 0.9 4.2 0.8 3.3 0.7 2.4 0.6 2.1 0.5 2.0 0.4 1.5 0.4 1.3 0.3 1.1 Cash Flows (in millions): (3) Revenues - oil (4) Revenues - gas (5) Total revenues 3.7 5.8 9.5 6.3 9.4 15.7 8.0 11.6 19.5 9.6 14.1 23.7 13.3 12.3 25.7 14.3 12.3 26.6 17.0 13.0 30.0 19.6 11.6 31.2 20.3 10.7 31.0 19.8 9.3 29.2 18.6 9.5 28.1 17.1 10.1 27.2 15.8 8.8 24.7 14.5 8.1 22.6 13.4 7.3 20.6 0.8 0.4 1.3 0.4 6.6 1.3 0.7 1.9 0.8 11.0 1.7 0.8 2.3 1.2 13.5 2.0 2.6 2.8 2.5 13.8 2.2 4.4 3.0 1.6 14.5 2.3 4.7 2.9 1.3 15.4 2.7 5.3 3.1 1.5 17.3 2.9 5.7 3.3 2.0 17.4 3.1 6.0 3.0 1.5 17.5 3.0 6.4 2.8 1.4 15.5 2.8 7.0 2.6 1.4 14.3 2.7 7.4 2.5 1.4 13.3 2.5 7.4 2.2 1.4 11.3 2.3 7.3 2.0 1.3 9.6 2.1 7.2 1.9 1.3 8.1 2.9 (0.2) 2.6 4.0 0.2 4.2 10.0 3.7 0.0 3.7 7.3 0.8 8.1 4.3 4.8 (0.2) 4.6 8.9 1.1 9.9 11.4 4.8 (0.2) 4.5 9.3 2.2 11.5 14.0 3.8 0.3 4.1 10.5 1.9 12.3 2.6 4.2 0.3 4.5 10.8 1.6 12.4 0.5 5.5 0.1 5.6 11.7 1.6 13.4 0.3 5.8 (0.0) 5.7 11.7 1.9 13.6 0.6 5.5 0.0 5.6 11.9 1.6 13.5 0.3 5.4 0.0 5.4 10.1 1.4 11.5 0.5 5.0 0.0 5.0 9.3 1.4 10.7 0.5 4.7 0.0 4.7 8.6 1.4 10.0 0.0 4.0 0.0 4.0 7.2 1.4 8.6 0.2 3.5 0.0 3.5 6.1 1.4 7.5 0.5 3.0 0.0 3.0 5.1 1.3 6.4 0.0 (5.8) 3.8 (1.5) (2.5) 9.7 11.9 13.1 13.0 13.2 11.0 10.2 10.0 8.4 7.0 6.4 (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16) (17) (18) Direct production taxes Direct operating expense Overhead Fin. book DD&A Net income before taxes Federal and state income taxes: Current Deferred Total income taxes Profit contribution Non-cash charges Cash from operations Capital expenditures (19) Cash flow (20) Terminal value (21) Cumulative cash flow Notes follow E