<PAGE> 1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
SCHEDULE 14A
(RULE 14a-101)
INFORMATION REQUIRED IN PROXY STATEMENT
SCHEDULE 14A INFORMATION
PROXY STATEMENT PURSUANT TO SECTION 14(a) OF THE SECURITIES
EXCHANGE ACT OF 1934 (AMENDMENT NO. )
Filed by the Registrant [X]
Filed by a Party other than the Registrant [ ]
Check the appropriate box:
<TABLE>
<S> <C>
[ ] Preliminary Proxy Statement [ ] Confidential, for Use of the
Commission Only (as permitted by
Rule 14a-6(e)(2))
[ ] Definitive Proxy Statement
[ ] Definitive Additional Materials
[X] Soliciting Material Pursuant to Rule 14a-12
</TABLE>
UNION PACIFIC RESOURCES GROUP INC.
- --------------------------------------------------------------------------------
(Name of Registrant as Specified In Its Charter)
- --------------------------------------------------------------------------------
(Name of Person(s) Filing Proxy Statement, if other than the Registrant)
Payment of Filing Fee (Check the appropriate box):
[X] No fee required.
[ ] Fee computed on table below per Exchange Act Rules 14a-6(i)(1) and 0-11.
(1) Title of each class of securities to which transaction applies:
-----------------------------------------------------------------------
(2) Aggregate number of securities to which transaction applies:
-----------------------------------------------------------------------
(3) Per unit price or other underlying value of transaction computed
pursuant to Exchange Act Rule 0-11 (set forth the amount on which the
filing fee is calculated and state how it was determined):
-----------------------------------------------------------------------
(4) Proposed maximum aggregate value of transaction:
-----------------------------------------------------------------------
(5) Total fee paid:
-----------------------------------------------------------------------
[ ] Fee paid previously with preliminary materials.
[ ] Check box if any part of the fee is offset as provided by Exchange Act
Rule 0-11(a)(2) and identify the filing for which the offsetting fee was
paid previously. Identify the previous filing by registration statement
number, or the Form or Schedule and the date of its filing.
(1) Amount Previously Paid:
-----------------------------------------------------------------------
(2) Form, Schedule or Registration Statement No.:
-----------------------------------------------------------------------
(3) Filing Party:
-----------------------------------------------------------------------
(4) Date Filed:
-----------------------------------------------------------------------
<PAGE> 2
[UPR LOGO]
UNION PACIFIC RESOURCES
1999 Annual Report
<PAGE> 3
CHAIRMAN'S LETTER TO SHAREHOLDERS
The year 1999 began as the previous year ended, with the promise of
hard times ahead for the oil and gas industry as oil prices bumped along at
near-historic lows and natural gas prices slumped. Virtually no one predicted
that prices would suddenly rebound in the second half, and that 1999 would turn
out to be a much better year for the industry and Union Pacific Resources than
originally forecasted.
At UPR, we executed a "hunker down" strategy in 1999 that emphasized
reducing debt, lowering costs and aiming a much reduced capital budget at our
highest return projects. With the help of rising prices, our "hunker down"
strategy worked: As 1999 earnings and cash flow rose, debt and costs declined.
Earnings from continuing operations exceeded $89 million.
We paid down debt by $1.8 billion using portions of our cash flow from
operations, and the majority of the proceeds from the sale of non-core oil and
gas assets and the sale of our gas gathering, processing and marketing business.
The result was a 39 percent decline in debt from $4.6 billion in 1998 to $2.8
billion at the end of 1999. Thanks to a Company-wide cost-reduction effort, we
also pushed costs down by 20 percent.
Our relatively modest capital spending of $428 million scored three
promising exploration discoveries, the first on our Wyoming Land Grant acreage,
the second in south Louisiana and the third in Canada's British Columbia. In
addition, it funded important development projects in our core areas of Texas,
the Rockies and Canada as well as in the Gulf of Mexico, Guatemala and
Venezuela. We also reduced finding and development costs to just over $0.91 per
thousand cubic feet of gas equivalent (Mcfe), compared to our previous five-year
average of $1.10 per Mcfe.
Predictably, however, lower spending and the difficulty of ramping up
drilling activities from the doldrums of 1998 and early 1999 led to a 13 percent
decline in production volumes and a reserve replacement rate of 63 percent for
the year. We planned to spend the necessary capital in 2000 to stabilize
production and replace 100 percent of produced reserves, while applying at least
$200 million of cash flow to continued debt reduction.
Since taking over as Chairman and CEO of UPR in July 1999, my first
concern has been to create value for shareholders. An extraordinary opportunity
to create value arose early in 2000 - the opportunity to form one of the largest
independent exploration and production companies in the world. On April 3, 2000,
UPR and Anadarko Petroleum Corporation announced an agreement to combine the two
companies in a stock-for-stock merger transaction.
UPR and Anadarko bring complementary strengths to the merger. The new
Anadarko should prove greater than the sum of its parts: Anadarko's success in
exploration matches up with UPR's record in exploiting reserves through the
application of industry-leading drilling and completion technology. The combined
company will have a stronger balance sheet and access to the capital necessary
to pursue a large number of drilling and development opportunities around the
world. The new company's assets will be concentrated in the natural gas-rich
basins of North America, where it will be the sixth largest company measured by
gas production and the fifth in reserves. Important oil operations in Latin
America, North Africa and elsewhere complement the strong position in the
growing North American gas market. The combination of oil and gas assets,
industry-leading expertise, excellent people, and financial strength should
bring shareholders increased value as the new company delivers on its growth
potential.
The shareholders of both companies, and government regulatory bodies,
must approve the merger, in which UPR shareholders will receive .455 shares of
Anadarko for each share of UPR common stock they own. After the merger, the
company will be called Anadarko Petroleum Corporation and will be based in
Houston. Bob Allison, the Chairman and CEO of Anadarko, and I, as Vice-Chairman
of the new Anadarko, are looking forward to working together to make two already
impressive companies into a stronger competitor in the oil and gas industry.
UPR's enclosed 1999 Annual Report on Form 10-K, which was filed before
the merger agreement was reached, provides greater detail on UPR's past
performance. You will shortly be receiving a joint proxy statement/prospectus,
which will provide you with important information about the proposed merger and
Anadarko.
As always, we are grateful for your continued support.
George Lindahl III
Chairman, President and Chief Executive Officer
April 2000
<PAGE> 4
================================================================================
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549-1004
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999 COMMISSION FILE NUMBER 1-13916
---------------------
UNION PACIFIC RESOURCES GROUP INC.
(Exact name of registrant as specified in its charter)
<TABLE>
<S> <C>
UTAH 13-2647483
(State or other jurisdiction of Incorporation (I.R.S. Employer Identification No.)
or organization)
777 MAIN STREET 76102
FORT WORTH, TEXAS (Zip Code)
(Address of principal executive offices)
</TABLE>
Registrant's telephone number, including area code: (817) 321-6000
Securities registered pursuant to Section 12(b) of the Act:
<TABLE>
<CAPTION>
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- ---------------------
<S> <C>
Common Stock New York Stock Exchange, Inc.
</TABLE>
---------------------
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
As of February 29, 2000, the aggregate market value of the registrant's
common stock held by non-affiliates (using the New York Stock Exchange closing
price) was approximately $2.25 billion.
The number of shares outstanding of the registrant's common stock as of
February 29, 2000 was 251,952,336.
Certain portions of the registrant's definitive Proxy Statement for the
annual meeting of shareholders to be held on May 24, 2000 (the "Proxy
Statement") are incorporated in Part III by reference.
================================================================================
<PAGE> 5
TABLE OF CONTENTS
<TABLE>
<S> <C> <C>
PART I
Item 1. Business.................................................... 1
Item 2. Properties.................................................. 10
Item 3. Legal Proceedings........................................... 12
Item 4. Submission of Matters to a Vote of Security Holders......... 13
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters......................................... 14
Item 6. Selected Financial Data..................................... 14
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 15
Item 7A. Qualitative and Quantitative Disclosures About Market
Risk........................................................ 32
Item 8. Financial Statements and Supplementary Data................. 38
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 86
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 86
Item 11. Executive Compensation...................................... 87
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 87
Item 13. Certain Relationships and Related Transactions.............. 87
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K......................................................... 87
Signatures ............................................................ 94
</TABLE>
Quantities of natural gas are expressed in this report in terms of thousand
cubic feet ("Mcf"), million cubic feet ("MMcf") or billion cubic feet ("Bcf").
Oil and natural gas liquids are quantified in terms of barrels ("Bbl"),
thousands of barrels ("MBbl") or millions of barrels ("MMBbl"). Oil and natural
gas liquids are compared to natural gas in terms of thousands of cubic feet of
natural gas equivalent ("Mcfe"), millions of cubic feet of natural gas
equivalent ("MMcfe"), billions of cubic feet of natural gas equivalent ("Bcfe")
or trillions of cubic feet of natural gas equivalent ("Tcfe"). One barrel of oil
or natural gas liquids is the energy equivalent of six Mcf of natural gas.
Natural gas volumes also may be expressed in terms of one million British
thermal units ("MMBtu"), which is approximately equal to one Mcf. Daily oil and
gas production is signified by the addition of the letter "d" to the end of the
terms defined above. With respect to information relating to working interests
in wells or acreage, "net" oil and gas wells or acreage is determined by
multiplying gross wells or acreage by the working interest owned therein. Unless
otherwise specified, all references to wells and acres are gross.
i
<PAGE> 6
PART I
ITEM 1. BUSINESS
GENERAL
Union Pacific Resources Group Inc. (a Utah corporation) and subsidiaries
(collectively, the "Company" or "UPR") is engaged primarily in the exploration
for and the development and production of natural gas, natural gas liquids
("NGLs") and crude oil in several major producing basins in the United States,
Canada, Guatemala, Venezuela and other international areas. In addition, the
Company engages in the hard minerals business through non-operated joint venture
and royalty arrangements in several coal, industrial minerals and trona (natural
soda ash) mines located on lands within and adjacent to its Land Grant holdings
in Wyoming. The Land Grant consists of land that passes through the states of
Colorado and Wyoming and into Utah, which was granted by the Federal government
to a predecessor of the Company in the mid-1800s. In the Land Grant, the Company
has fee ownership of the mineral rights under approximately 7.9 million acres.
As of December 31, 1999, over 68 percent of the revenues, 44 percent of the
fixed assets and 56 percent of the proved reserves of the Company are generated
or located in the United States. As of December 31, 1999, 19 percent of the
revenues, 35 percent of fixed assets and 28 percent of the proved reserves of
the Company are generated or located in Canada.
In March 1998, the Company acquired Norcen Energy Resources Limited
("Norcen") for a cash purchase price of $2.634 billion ("Norcen Acquisition").
The Company also assumed long-term debt obligations of Norcen totaling
approximately $1 billion and funded the purchase price through the issuance of
commercial paper, supported by a U.S. $2.7 billion 364-Day Competitive
Advance/Revolving Credit Agreement dated March 2, 1998. Norcen was a major
Canadian oil and gas exploration and production company with primary operations
in western Canada, the Gulf of Mexico, Guatemala and Venezuela. The acquisition
expanded the Company's operations beyond its historical domestic focus. See Note
2 to the Consolidated Financial Statements.
Following the Norcen Acquisition, the Company commenced a deleveraging
program which included the sales in 1998 and 1999 of approximately $745 million
of non-strategic properties. Additionally, the Company sold its gathering,
processing and marketing ("GPM") business segment to Duke Energy Field Services,
Inc. ("Duke") for $1.36 billion in March 1999 ("GPM Disposition"). See
"Deleveraging Program and Discontinued Operations" in Note 3 to the Consolidated
Financial Statements.
BUSINESS STRATEGY
During 1999, the Company shifted its business strategy from prior years.
The Company sold its GPM business segment and began to focus on its upstream
exploration and production business segment. Although other international
operations, primarily in Latin America, were expanded as a result of the Norcen
Acquisition, the Company focuses primarily on onshore North American core
operating areas where it has expertise and a large acreage position with natural
gas prospects and can create shareholder value.
The Company's strategy is to become the premier North American onshore
exploration and production value creator through its technical and operational
abilities in the exploitation of natural gas, primarily in Texas, the Rockies
and Canada. In each of its core areas, the Company focuses on the exploration
for and the development of natural gas and crude oil resources, in combination
with efforts to increase margins through reductions in drilling and operating
costs. The Company's long-term strategy is to increase production by enhancing
well results through the application of economies of scale, its operating
experience in its core geographic areas and its expertise in advanced drilling
and completion technologies. The Company strives to keep its drilling inventory
high to supply its drilling operations with an inventory of drill sites in its
core areas through development of its existing properties, exploration, farm-in
agreements and acquisitions of properties and companies. The Company maintains a
high working interest in its core areas and typically serves as operator, which
allows it to control the timing and cost of exploration and development
activities and to enhance its ability to apply its expertise to these
properties.
1
<PAGE> 7
The Company plans to increase its capital spending in 2000 from the $428
million spent in 1999 to approximately $650 million for exploration and
development projects. The Company plans an additional $100 million for select
property acquisitions. The capital program will be funded through cash provided
by operations. Almost 83 percent of the capital budget will be focused on the
development of fields which have already been proved and which are expected to
provide more immediate cash flow with low risk. The remainder of the Company's
budget will be for select exploration projects and other development drilling
that has the potential for long-term impact. Both the development and
exploration programs will employ the Company's ongoing strategy of applying its
expertise in advanced drilling and completion technologies. Approximately 38
percent of the capital budget will be invested in U.S. Onshore, 29 percent in
Canada, 14 percent in U.S. Offshore and 19 percent in Other International. The
Company may adjust its capital spending as commodity prices and cash flows
change. The extent and timing of capital spending may also be affected by
changes in business, financial and operating conditions as well as by the timing
and availability of suitable investment opportunities. See "Outlook and Other
Matters."
The Company's primary financial strategy is to continue to improve its
balance sheet by reducing debt. During 1999, the Company reduced total debt by
over 39% or approximately $1.8 billion. During 2000, the Company expects to
further reduce debt by at least $200 million. The Company expects its cash
provided by operations to be approximately $1 billion for 2000, assuming a NYMEX
price forecast of $26 per barrel for crude oil and $2.70 per Mcf for natural
gas. To the extent that cash provided by operations is generated in excess of
this forecast or due to the monetization of assets, the additional cash could be
used to further reduce debt and/or initiate a common stock repurchase program if
approved by the Board of Directors. See "Outlook and Other Matters."
EXPLORATION AND PRODUCTION OPERATIONS
The Company's exploration and production operations are organized into four
primary business operating areas: U.S. Onshore, U.S. Offshore, Canada and Other
International. Other International is comprised of Guatemala, Venezuela and
other international operations.
The following table sets forth 1999 capital spending, production
information and proved reserves as of December 31, 1999, with respect to each of
the Company's operating areas. Natural gas constituted 58% of the Company's
total proved reserves of 5.7 Tcfe as of December 31, 1999, and 59% of the
Company's sales volumes of 2.15 Bcfed for the year then ended. Production from
properties sold in 1999 is included in producing property volumes for each area
through the date of each sale.
<TABLE>
<CAPTION>
PRODUCING
TOTAL TOTAL PROPERTY
CAPITAL PERCENT PROVED PERCENT SALES PERCENT
SPENDING OF RESERVES OF VOLUMES OF
OPERATING AREA (MILLIONS) TOTAL (BCFE) TOTAL (MMCFED) TOTAL
- -------------- ---------- ------- -------- ------- --------- -------
<S> <C> <C> <C> <C> <C> <C>
U.S. Onshore.......................... $185 43% 2,814 49% 1,274 59%
U.S. Offshore......................... 53 13 361 7 139 7
---- --- ----- --- ----- ---
Total United States.............. 238 56 3,175 56 1,413 66
Canada........................... 123 29 1,585 28 462 21
Guatemala............................. 19 4 322 6 128 6
Venezuela............................. 43 10 538 9 114 5
Other................................. 5 1 84 1 35 2
---- --- ----- --- ----- ---
Total Other International........ 67 15 944 16 277 13
---- --- ----- --- ----- ---
Total....................... $428 100% 5,704 100% 2,152 100%
==== === ===== === ===== ===
</TABLE>
United States Operations
The Company's United States operations currently has proved reserves of 3.2
Tcfe and produced 1,413 MMcfed in 1999. Over 70 percent of the proved reserves
in the United States is natural gas. Capital spending in the United States in
1999 was $238 million.
2
<PAGE> 8
U.S. Onshore
The Company's U.S. Onshore oil and gas activities are concentrated in five
core geographic areas. The core areas in the U.S. Onshore are comprised of the
following: (1) the Land Grant area in Colorado, Wyoming and Utah, (2) the
Coastal Plain area of Texas and Louisiana, (3) the Austin Chalk trend in Texas
and Louisiana, (4) the East Texas area and (5) the West Texas area. During 1999,
the Company spent $185 million or 43 percent of its capital budget in the U.S.
Onshore and produced 1,274 MMcfed or 59 percent of the Company's total produced
volumes.
The Land Grant core area includes the Company's oil and gas properties in
Colorado, Wyoming and Utah, and the Hugoton/Panoma field in Kansas. The
Company's operations in the Land Grant are concentrated in the Green River Basin
and the Overthrust area. The Company currently controls approximately 8.9
million developed and undeveloped net acres, principally attributable to its
Land Grant ownership. During 1999, the Company drilled a successful Rock Island
4H well in the deep over-pressured Frontier formation of the Green River Basin.
Although the wells drilled in early 2000 near the Rock Island 4H were not
successful, the formation's resource is large so the Company will continue to
test the Frontier formation during 2000 to further understand its potential.
The Coastal Plain core area includes the Company's oil and gas properties
along the onshore coastal plain of Texas and Louisiana. In addition to its
producing activities, the Company conducted extensive seismic evaluations in
1999 and drilled a successful exploration well in the Company's Etouffee
prospect in South Louisiana. The Company will continue to develop this area and
explore the nearby Turtle Soup area during 2000, while bringing on production
from the successful well in the Etouffee prospect.
The Austin Chalk core area includes the Company's oil and gas properties in
the Austin Chalk trend, which extends 700 miles from southern Texas through
central and eastern Texas into Louisiana. At present, the Company's Austin Chalk
production is located primarily in three fields: Giddings, Brookeland and
Masters Creek. The Company controls nearly 1.9 million developed and undeveloped
net acres in the Austin Chalk.
The East Texas core area includes the Company's oil and gas properties in
northeastern Texas, primarily in the Carthage and Oakhill fields. In addition to
its Carthage and Oakhill production operations, the Company has participated in
3-D seismic and has identified several high impact exploratory prospects.
The West Texas core area includes the Company's oil and gas properties in
western Texas, primarily in the Ozona field. The Company has drilled
approximately 1,000 wells in the Ozona area, which is characterized by
long-lived natural gas wells that typically produce for 30 or more years.
U.S. Offshore
The U.S. Offshore operations are comprised of the Company's oil and gas
properties in the Gulf of Mexico, including operations added in the Norcen
Acquisition in 1998. During 1999, the Company spent $53 million of its capital
budget in the U.S. Offshore and produced 139 MMcfed. During 1997, the Company
drilled a successful deepwater well in Mississippi Canyon Block 755 in the Gulf
of Mexico, which resulted in the discovery of significant reserves. The Company
has and will continue to delineate the discovery during 2000 and 2001, with
first production anticipated in 2002. The Company may also drill an exploration
well in both the Garden Banks Block 700 and Green Canyon Block 281 during 2000.
Canadian Operations
The Company's Canadian operations principally include properties acquired
in the Norcen Acquisition. Operations in ten core areas are centered in the
province of Alberta, with additional properties in northeastern British Columbia
and southwestern Saskatchewan. Canada currently has proved reserves of 1.6 Tcfe
and produced 462 MMcfed in 1999. Capital spending in 1999 in Canada was $123
million. Canada provides a balanced commodity mix of 35 percent crude oil and
NGLs and 65 percent natural gas, as well as an asset portfolio with long reserve
lives. Approximately 46 percent of Canadian oil production is heavy oil. The
Company has significant heavy crude oil assets in the Moose Hill, Lindbergh and
Hayter areas which are located in eastern Alberta and western Saskatchewan.
These areas cover approximately 420,000 acres and consist of over 860 producing
wells and over 1,000 drill site prospects. As a result of the Company's
successful Klua well in British Columbia during 1999, the Company will continue
to focus on the region and add reserves.
3
<PAGE> 9
Other International Operations
The Company's Other International oil and gas operation activities are
concentrated in Latin America, primarily in Guatemala and Venezuela. The Company
also maintains less significant international oil and gas operation activities,
including interests in six fields in Argentina, two non-operated offshore
producing properties in Australia, an exploitation interest in Brazil with
potential exploration upside, and a producing interest in a non-operated
property in Egypt. Other International currently has proved reserves of 0.9 Tcfe
and produced 277 MMcfed in 1999.
Guatemala. The Company's Guatemalan operations are conducted by Basic
Resources International, a company that was acquired in the Norcen Acquisition.
The majority of activity for the Guatemalan operations is currently in the Xan
area, producing heavy to medium quality crude oil. The Company owns a 100
percent working interest in several exploration blocks and is focusing on an
aggressive seismic acquisition strategy to evaluate exploration and development
opportunities. Capital spending in 1999 in Guatemala was $19 million, with
average production volumes of 21 MBbld. The Company owns, controls and operates
infrastructure in Guatemala which includes gathering and processing facilities
at each producing field, an asphalt refinery, 285 miles of pipeline with seven
pump stations and a 420 MBbl capacity shipping terminal on the Caribbean coast.
The combination of these assets provides the Company with an integrated network
of facilities from producing fields to the port.
Venezuela. The Company's Venezuelan operations primarily consist of the
Oritupano-Leona and the West Guarico concessions. The Oritupano-Leona block, in
which the Company has a 45 percent working interest, covers 433,000 acres and
has approximately 205 producing wells. Most of the activity in the block has
been driven by a 3-D seismic program conducted in prior years. The West Guarico
block covers over 800,000 acres, approximately nine producing wells and is
operated by the Company, which has a 50 percent working interest. The project is
in the beginning stages of redevelopment and in 1999, the Company focused on
seismic, drilling, recompletions and the improvement of infrastructure. After
drilling a dry hole on the Delta Centro prospect in 1999, the Company fully
impaired the project's lease with a $50 million charge to exploration expense.
During 1999, the Company spent $43 million of capital in Venezuela, with average
production volumes of 19 MBbld.
VOLUMES, PRICES AND PRODUCTION COSTS
The following table sets forth certain information regarding the Company's
volumes and average price realizations after the effects of hedging for natural
gas, NGL and crude oil sales, and average production costs per Mcfe for each of
the last three years.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------------
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Average daily production:
Natural gas (MMcfd)....................................... 1,278.8 1,441.1 1,108.5
Natural gas liquids (MBbld)............................... 28.4 33.1 31.7
Crude oil (MBbld)......................................... 117.1 137.9 52.9
Total (MMcfed).................................... 2,151.6 2,467.0 1,615.7
Average sales prices including the effects of hedging:
Natural gas (per Mcf)..................................... $ 1.83 $ 1.74 $ 2.00
Natural gas liquids (per Bbl)............................. 10.95 7.88 11.23
Crude oil (per Bbl)....................................... 11.81 10.48 18.36
Production costs (per Mcfe)(a).............................. 0.51 0.49 0.51
</TABLE>
- ---------------
(a) Includes lease operating costs, production overhead, other operating
expenses and taxes other than income taxes.
PRINCIPLE CUSTOMER
In connection with the GPM Disposition, the Company entered into a
long-term sales agreement with Duke. The long-term sales agreement obligates the
Company to sell the majority of its domestic natural gas and existing NGL
production to Duke through March 2004. During 1999, sales to Duke accounted for
31% of the Company's consolidated revenues and 38% of United States revenues.
4
<PAGE> 10
MINERALS
The Minerals business segment contributes significantly to the Company's
operating income by exploiting the hard minerals portion of the Company's
extensive fee mineral interests in the Land Grant through non-operated joint
venture and royalty arrangements in coal, trona and industrial mineral mines. In
general, the Company reinvests the cash flow from its hard minerals operations
into its oil and gas business segment. The Minerals business segment generated
$117.8 million of operating income during 1999, as follows:
<TABLE>
<CAPTION>
1999 OPERATING INCOME
----------------------------------
AMOUNT PERCENT
--------------------- -------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Royalties:
Soda ash(a)........................................... $ 27.2 23%
Coal(b)............................................... 11.8 10
------ ---
Total royalties............................... 39.0 33
------ ---
Non-operated joint ventures:
Soda ash(c)........................................... (0.9) --
Coal(d)............................................... 79.3 67
------ ---
Total joint ventures.......................... 78.4 67
Overhead/other.......................................... 0.4 --
------ ---
Total operating income........................ $117.8 100%
====== ===
</TABLE>
- ---------------
(a) Includes royalties from properties leased to four soda ash producers. In
total, these properties contain resources sufficient to support over 50
years of production at current production levels.
(b) The Company leases coal resources to six operating mines. In 1999, 52
percent of the Company's coal royalties were attributable to a single mine
which supplies an adjacent power station that is owned and operated by
affiliates of the mine owners.
(c) Represents operating income from the Company's 49 percent interest in OCI
Wyoming LP, a non-operated joint venture.
(d) Represents operating income from the Company's 50 percent non-operating
interest in Black Butte Coal Company ("Black Butte").
The Company's low sulfur coal deposits, which are located in southeastern
Montana and southwestern Wyoming, compete with other western coal for industrial
and utility boiler markets which burn the coal to produce steam to generate
electricity. The Company's mines primarily use the surface mining method of
extraction, although the Company also receives royalties on some underground
mines. The Company's coal mines are served by a single rail line and incur
greater transportation costs than some of its competitors in the western United
States. Additionally, competing western coal companies in the Powder River Basin
in Wyoming have lower stripping ratios than the Company's mines. At current coal
pricing and higher transportation and extraction cost levels, most of this
resource is not economic to extract except for sale to local markets. As a
result, there are limited opportunities for new coal mine development in the
Land Grant.
Approximately 80%, 84% and 78% of the Black Butte revenues in 1999, 1998
and 1997, respectively were derived from a coal supply contract with
Commonwealth Edison Company which terminates at the end of 2000. In 1999, $73.4
million of the Company's operating income was attributable to the contract. See
"Management's Discussion and Analysis of Financial Condition Results of
Operations", "Outlook and Other Matters" and Note 14 to the Consolidated
Financial Statements.
The world's largest deposit of trona, constituting 90 percent of the
world's known trona resources, is located in the Green River Basin in
southwestern Wyoming. All of the reserves which can be mined in this trona
deposit lie within the Land Grant and adjoining lands. The Company owns lands
containing approximately 50% of these reserves and has leased a portion of those
lands to companies which mine and refine trona. Natural soda ash, which is
produced by refining trona ore, is used primarily in the production of glass for
containers and flat glass, in the paper and water treatment industries and in
the manufacture of certain chemicals and detergents. Natural soda ash from
Wyoming contributes 31 percent of the world soda ash supply with the remainder
principally from synthetic processes. In addition to fee mineral ownership of
and royalty interests in trona reserves, the Company, along with its partner,
Oriental Chemical Industries, Inc. ("OCI"), owns a soda ash refining facility at
OCI Wyoming LP. This facility is ranked second in soda ash capacity among
domestic producers at 3.1 million tons per year.
5
<PAGE> 11
COMPETITION
The oil and gas industry is highly competitive. The Company actively
competes for reserve acquisitions, exploration leases, licenses, concessions and
skilled industry personnel, frequently against companies with substantially
larger financial and other resources. The Company's competitors include major
integrated oil and gas companies and numerous other independent oil and gas
companies and individual producers and operators. In the past several years,
some consolidation within the industry has occurred, as companies combined their
strengths and financial resources to improve overall stability and operating
efficiencies and to reduce costs. To the extent the Company's capital budget is
lower than that of certain of its competitors, the Company may be disadvantaged
in effectively competing for certain reserves, leases, licenses and concessions.
Competitive factors include price, contract terms, pipeline access and types and
quality of service.
GOVERNMENT REGULATION
The Company's natural gas, NGL and crude oil exploration, development and
production operations are subject to extensive rules and regulations promulgated
by Federal, provincial, state and local authorities and foreign governmental
entities.
Numerous Federal, state and local departments and agencies have issued
rules and regulations binding on the oil and gas industry and its individual
members, some of which carry substantial penalties for non-compliance. State
statutes and regulations require permits for drilling operations, drilling bonds
and reports concerning operations. Most states in which the Company operates
also have statutes and regulations governing conservation and safety matters,
including the unitization or pooling of oil and gas properties, the
establishment of maximum rates of production from oil and gas wells and the
spacing of such wells. Such statutes and regulations may limit the rate at which
oil and gas otherwise could be produced from the Company's properties. The
regulatory burden on the oil and gas industry increases its cost of doing
business and, consequently, affects its profitability.
A substantial portion of the Company's oil and gas leases in the Gulf of
Mexico and a portion of its onshore leases were granted by the United States
Government and are administered by the U.S. Department of the Interior, Minerals
Management Service ("MMS"). Such leases are issued through competitive bidding,
contain relatively standardized terms and require compliance with detailed MMS
regulations and orders. Certain operations on such leases must be conducted
pursuant to appropriate permits issued by the MMS in addition to permits
required from other agencies (such as the Coast Guard, Army Corps of Engineers
and Environmental Protection Agency). The MMS also administers bonding
requirements and has the right to require lessees to post supplemental bonds if
it deems that additional security is necessary to cover royalties due or the
costs of regulatory compliance.
Under certain extraordinary circumstances, the Federal agencies have the
power to suspend or terminate Company operations on Federal leases. Any such
suspension or termination could materially and adversely affect the Company's
financial condition and operations. In 1998, the MMS adopted financial
responsibility regulations under the Oil Pollution Act of 1990. See
"Environmental Regulation -- Oil Spills."
Currently, there are no Federal, state or local laws that regulate the
price for sales of natural gas, NGLs or crude oil produced by the Company.
However, the rates charged and terms and conditions for the movement of gas in
interstate commerce through certain intrastate pipelines and production area
hubs are subject to regulation under the Natural Gas Policy Act of 1978
("NGPA"). Pipeline and hub construction activities are, to a limited extent,
also subject to regulation under the Natural Gas Act of 1938 ("NGA"). The NGA
also establishes comprehensive controls over interstate pipelines, including the
transportation of gas in interstate commerce. While these NGA controls do not
apply directly to the Company, their effect on natural gas markets can be
significant in terms of competition and cost of transportation services. The
Federal Energy Regulatory Commission ("FERC") administers the NGA and the NGPA.
Through a series of orders, FERC has taken significant steps to increase
competition in the sale, purchase, storage and transportation of natural gas.
FERC's regulatory programs generally allow more accurate and timely price
signals from the consumer to the producer. Nonetheless, the ability to respond
to market forces can and does add to price volatility, inter-fuel competition
and pressure on the value of transportation and other services.
6
<PAGE> 12
Through many interstate pipeline specific orders, FERC has revised its
policy regarding jurisdiction over gathering facilities and services. FERC no
longer asserts jurisdiction over these facilities and services and has stated
that it is a matter to be left to the states for regulation. In 1996, the
District of Columbia Court of Appeals largely upheld FERC's policy. As a result
of the court's decision, the Texas Railroad Commission conducted inquiries
regarding the scope of its regulation of gathering facilities and services. The
Company owns several gathering systems in Texas. In 1996, the Texas Railroad
Commission initiated a rulemaking and ultimately issued new regulations
regarding gathering activities. Although the new regulations increased the
regulatory burden to a limited extent, the regulations have not had a
significant impact on the Company's gathering activity. It is also possible that
other states where the Company owns gathering facilities will become more active
in the regulation of gathering activities.
Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, FERC, state regulatory
bodies and the courts. Several proposals that might affect the natural gas
industry are pending before FERC. The Company cannot predict when or if any such
proposals might become effective and their effect, if any, on the Company's
operations. Historically, the natural gas industry has been heavily regulated;
therefore, there is no assurance that the less stringent regulatory approach
being pursued by FERC, Congress and the states will continue indefinitely into
the future.
The oil and gas industry in Canada is subject to extensive controls and
regulations imposed by various levels of government. Oil and gas exported from
Canada is subject to regulation by the National Energy Board ("NEB") and the
government of Canada. Exporters are free to negotiate prices and other terms
with purchasers, provided that the export contracts meet certain criteria
prescribed by the NEB and the government of Canada. Exports may be made pursuant
to export contracts with terms not exceeding one year in the case of light crude
oil and not exceeding two years in the case of heavy crude oil and natural gas,
provided that an order approving any such export has been obtained from the NEB.
Any export to be made pursuant to a contract of longer duration requires an NEB
license and Governor in Council approval. The governments of Alberta, British
Columbia and Saskatchewan also regulate the volume of natural gas that may be
removed from these provinces for consumption elsewhere based on such factors as
reserve availability, transportation arrangements and market considerations. In
addition, each province has legislation and regulations which govern land
tenure, royalties, production rates, environmental protection and other matters.
It is not expected that any of these controls or regulations will affect the
operations of the Company in a manner materially different than they would
affect other oil and gas companies of similar size.
The Company is subject to various laws and regulations governing its other
international operations. The Company's other international operations can be
affected from time to time by political developments and laws and regulations in
the countries where it operates, such as the forced divestiture of assets,
production restrictions, import and export controls, price controls, changes in
taxes, royalties and other amounts payable to governments, retroactive tax and
royalty claims, expropriation of property, cancellation of contract rights and
concessions by host governments, foreign exchange rate changes, restrictions as
to currency conversion, tariffs and other international trade restrictions and
environmental regulations. The likelihood of such occurrences is not
predictable.
The Company's minerals operations are subject to a variety of Federal and
state regulations with respect to safety, land use and reclamation. In addition,
the Department of the Interior regulates the leasing of Federal lands for coal
development as provided in the Mineral Lands Leasing Act of 1920.
SECTION 29 TAX CREDITS
Federal tax law provides an income tax credit against regular Federal
income tax liabilities with respect to sales of the Company's production of
certain fuels produced from non-conventional sources (including both coal seam
natural gas and natural gas produced from tight sand formations), subject to a
number of limitations ("Section 29 tax credits"). Fuels qualifying for the tax
credit must be produced from a well drilled or a facility placed in service
after December 31, 1979, and before January 1, 1993, and must be sold before
January 1, 2003.
The basic credit which is approximately $0.52 per MMBtu of natural gas
produced from tight sand reservoirs, is computed by reference to the price of
crude oil and is phased out as the price of oil exceeds certain specified
levels. The commencement of phaseout would be triggered if the average price for
crude oil
7
<PAGE> 13
rose above approximately $48 per barrel. The natural gas production from wells
drilled on certain of the Company's properties in the Moxa Arch and Wamsutter
areas in Wyoming, the Carthage field in eastern Texas, the Ozona field in
western Texas and certain areas in the Austin Chalk trend qualifies for this tax
credit. The Company recorded approximately $17.9 million of Section 29 tax
credits in 1999. Section 29 tax credits are not creditable against the
alternative minimum tax but under certain circumstances may be carried over and
applied against regular tax liabilities in future years. Therefore, no assurance
can be given that the Company's Section 29 tax credits will reduce its Federal
income tax liability in any particular year.
TEXAS SEVERANCE TAX REDUCTION
Natural gas produced from wells that have been certified as deep wells or
geologic formations certified as tight formations by the Texas Railroad
Commission ("high cost wells") and that were spudded or completed during the
period from May 24, 1989 to September 1, 1996 qualifies for an exemption from
the 7.5 percent severance tax in Texas on natural gas and NGLs produced by such
wells. Such exemption ends August 31, 2001. The natural gas production from
wells drilled on certain of the Company's properties, primarily in the Austin
Chalk trend and fields in East and West Texas, qualifies for this tax reduction.
In addition, high cost wells that are spudded or completed during the period
from September 1, 1996 to August 31, 2010 are entitled to receive a severance
tax reduction. For the maximum tax rate reduction, operators must file by the
later of 180 days after first production or the 45th day after approval by the
Texas Railroad Commission. The tax reduction is based on a formula composed of
the statewide "median" as determined by the State of Texas based on actual
drilling and completion costs reported by producers. More expensive wells will
receive a greater amount of tax reduction. This tax rate reduction remains in
effect for ten years or until the aggregate tax reductions received equal 50
percent of the total drilling and completion costs.
ENVIRONMENTAL REGULATION
The Company's operations are subject to extensive Federal, state, local,
provincial and international environmental laws and regulations governing the
protection of the environment. The Company is in compliance, in all material
respects, with applicable environmental requirements. Although future
environmental obligations are not expected to have a material impact on the
results of operations or financial condition of the Company, there can be no
assurance that future developments, such as increasingly stringent environmental
laws or enforcement thereof, will not cause the Company to incur material
environmental liabilities or costs.
Air Emissions. The primary legislation affecting the Company's air
emissions is the Federal Clean Air Act and its 1990 Amendments (the "CAA").
Among other things, the CAA requires all major sources of air emissions to
obtain operating permits. The amendments also revised the definition of a "major
source" such that additional equipment involved in oil and gas production is now
covered by the permitting requirements.
Hazardous Substances and Waste Disposal. The Company currently owns or
leases numerous properties that have been used for many years for hard minerals
production or natural gas and crude oil production. Although the Company has
utilized operating and disposal practices that were standard in the industry at
the time, hydrocarbons or other wastes may have been disposed of or released on
or under the properties owned or leased by the Company. In addition, some of
these properties have been operated by third parties over whom the Company had
no control. The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA") and comparable state statutes impose strict, joint and several
liability on owners and operators of sites and on persons who disposed of or
arranged for the disposal of "hazardous substances" found at such sites. The
Federal Resource Conservation and Recovery Act ("RCRA") and comparable state
statutes govern the disposal of "solid wastes" and "hazardous wastes." Although
CERCLA currently excludes petroleum from its definition of hazardous substance,
many state laws affecting the Company's operations impose clean-up liability
regarding petroleum and petroleum-related products. In addition, although RCRA
classifies certain oil field wastes as "non-hazardous," such exploration and
production wastes could be reclassified as hazardous wastes thereby making such
wastes subject to more stringent handling and disposal requirements. If such a
change in legislation were to be enacted, it could have a significant impact on
the Company's operating costs, as well as the oil and gas industry in general.
See "Other Matters -- Environmental Costs."
8
<PAGE> 14
Oil Spills. Under the Oil Pollution Act of 1990 ("OPA"), owners and
operators of onshore facilities and pipelines and lessees or permittees of an
area in which an offshore facility is located ("Responsible Parties") are
strictly liable on a joint and several basis for removal costs and damages that
result from a discharge of oil into United States waters. OPA limits the strict
liability of Responsible Parties for removal costs and damages that result from
a discharge of oil from $10 million to $150 million in the case of onshore
facilities and from $35 million to $150 million plus removal costs in the case
of offshore facilities, except that these limits do not apply if the discharge
was caused by gross negligence or willful misconduct, or by the violation of an
applicable Federal safety, construction or operating regulation by the
Responsible Party, its agent or subcontractor.
In addition, OPA requires owners of certain vessels and offshore facilities
to provide evidence of financial responsibility in the amount of $150 million.
The MMS, which has jurisdiction over certain offshore facilities and pipelines,
issued a final rule in August 1998 implementing OPA requirements. OPA also
requires offshore facilities and certain onshore facilities to prepare facility
response plans, which the Company has done, for responding to a "worst case
discharge" of oil. Failure to comply with these requirements or failure to
cooperate during a spill event may subject Responsible Parties to civil or
criminal enforcement actions and penalties.
Offshore Production. Offshore oil and gas operations are subject to
regulations of the United States Department of the Interior which currently
impose strict liability upon the lessee under a Federal lease for the cost of
clean-up of pollution resulting from the lessee's operations, and such lessee
could be subject to possible liability for pollution damages. In the event of a
serious incident of pollution, the Department of the Interior may require a
lessee under Federal leases to suspend or cease operations in the affected
areas.
Canadian Environmental Regulations. The oil and gas industry in Canada
currently is subject to environmental regulation pursuant to provincial and
Federal legislation. Environmental legislation provides for restrictions and
prohibitions on releases or emissions of various substances produced or utilized
in association with certain oil and gas industry operations. In addition,
legislation requires that well and facility sites be abandoned and reclaimed to
the satisfaction of provincial authorities. A breach of such legislation may
result in the imposition of fines and penalties. Federal legislation governing
environmental performance includes the Canadian Environmental Protection Act and
the Navigable Protection Act. In Alberta, environmental compliance is regulated
by the Environmental Protection and Enhancement Act. The Waste Management Act
established environmental standards in British Columbia. Similarly, the
Environmental Management Protection Act governs compliance in Saskatchewan.
International Environmental Regulations. All phases of the oil and gas
industry are subject to regulatory oversight by various agencies and regulatory
bodies within each country. These governmental bodies provide for the protection
of the environment covering such items as emissions control, discharges,
permits, cleanups and land use.
EMPLOYEES
The Company had 2,223 employees as of February 29, 2000, 21 of which were
not full-time. The Company believes that its relations with its employees are
good.
OTHER BUSINESS MATTERS
The Company's operations are subject to the usual hazards incident to the
drilling and operation of oil and gas wells, and the processing and
transportation of natural gas, crude oil and NGLs, such as cratering,
explosions, uncontrollable flows of oil, gas or well fluids, fire, pollution and
other environmental risks. In general, many of these risks increase when
drilling at greater depths under higher pressure conditions. In addition,
certain of the Company's operations are offshore and subject to the additional
hazards of marine operations, such as capsizing, collision and damage or loss
from severe weather. Other operations involve the production, handling,
processing and transportation of gas containing hydrogen sulfide and other
hazardous substances. These hazards can cause personal injury and loss of life,
severe damage to and destruction of property and equipment, environmental damage
and suspension of operations. Litigation arising from a catastrophic occurrence
in the future at one of the Company's locations could result in the Company
being named as a defendant in lawsuits asserting potentially large claims. In
accordance with customary industry practices, insurance is maintained for the
Company against some, but not all, of the consequences of these
9
<PAGE> 15
risks. Losses and liabilities arising from such events could reduce revenues and
increase costs to the Company to the extent not covered by insurance or
otherwise already reserved.
ITEM 2. PROPERTIES
PROVED RESERVES
The following table sets forth the proved developed and undeveloped
reserves of natural gas, NGLs and crude oil of the Company as of December 31,
1999. Reserve estimates as of December 31, 1999 were prepared by the Company's
engineers. Information set forth in the table is based on reserve estimates of
the Company, prepared in accordance with the rules and regulations of the
Securities and Exchange Commission ("SEC").
<TABLE>
<CAPTION>
RESERVES AS OF DECEMBER 31, 1999
---------------------------------------
NATURAL
NATURAL GAS
GAS LIQUIDS CRUDE OIL TOTAL
CATEGORY (BCF) (MMBBL) (MMBBL) (BCFE)
- -------- ------- ------- --------- -------
<S> <C> <C> <C> <C>
Proved developed....................................... 2,691.5 59.8 216.8 4,351.1
Proved undeveloped..................................... 599.3 3.2 122.3 1,352.3
------- ---- ----- -------
Total proved reserves........................ 3,290.8 63.0 339.1 5,703.4
======= ==== ===== =======
Percent of total............................. 58% 6% 36% 100%
</TABLE>
There are numerous uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond the control of the Company. The
reserve data set forth herein represent estimates only. Reservoir engineering is
a subjective process of estimating underground accumulations of crude oil and
natural gas that cannot be measured in an exact manner, and the accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment.
ACREAGE
Land Grant and Other Fee Minerals. The Company owns fee mineral acreage
totaling 9,421 (gross) or 8,474 (net) thousand acres as of December 31, 1999. Of
this amount, 7,912 (gross) or 7,722 (net) thousand acres are within the
Company's Land Grant area. The Company holds royalty interests of varying
percentages in the approximately one million gross acres of the Land Grant that
are subject to exploration and production agreements with third parties. The
Company's fee mineral acreage is primarily undeveloped.
Leasehold. The Company's leasehold acreage by operating area as of December
31, 1999 is set forth below.
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
ACRES ACRES TOTAL ACRES
------------- -------------- --------------
OPERATING AREA GROSS NET GROSS NET GROSS NET
- -------------- ----- ----- ------ ----- ------ -----
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
U. S. Onshore................................. 2,003 1,267 1,696 1,155 3,699 2,422
U. S. Offshore................................ 263 124 342 224 605 348
----- ----- ------ ----- ------ -----
Total United States................. 2,266 1,391 2,038 1,379 4,304 2,770
Canada........................................ 1,618 942 5,297 1,924 6,915 2,866
Guatemala..................................... 25 25 1,834 1,788 1,859 1,813
Venezuela..................................... 53 25 1,714 758 1,767 783
Other International........................... 476 85 2,229 656 2,705 741
----- ----- ------ ----- ------ -----
Total leasehold acreage............. 4,438 2,468 13,112 6,505 17,550 8,973
===== ===== ====== ===== ====== =====
</TABLE>
10
<PAGE> 16
Total Leasehold and Fee Mineral. The total leasehold and fee mineral
acreage by operating area as of December 31, 1999 is set forth below.
<TABLE>
<CAPTION>
TOTAL ACRES
---------------
OPERATING AREA GROSS NET
- -------------- ------ ------
(IN THOUSANDS)
<S> <C> <C>
U. S. Onshore............................................... 13,120 10,896
U. S. Offshore.............................................. 605 348
------ ------
Total United States............................... 13,725 11,244
Canada...................................................... 6,915 2,866
Guatemala................................................... 1,859 1,813
Venezuela................................................... 1,767 783
Other International......................................... 2,705 741
------ ------
Total leasehold and fee acreage................... 26,971 17,447
====== ======
</TABLE>
DRILLING ACTIVITY AND PRODUCING WELL SUMMARY
The table below summarizes the Company's drilling activity over the last
three years.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------------------
1999 1998 1997
------------- ------------- -------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Development wells:
Productive...................................... 553 413.1 511 357.8 685 478.6
Dry............................................. 23 18.1 39 27.2 59 46.2
Exploration wells:
Productive...................................... 47 43.1 64 46.1 35 19.1
Dry............................................. 20 15.1 22 18.0 38 22.1
--- ----- --- ----- --- -----
Total wells............................. 643 489.4 636 449.1 817 566.0
=== ===== === ===== === =====
</TABLE>
The number of wells drilled is not a valid measure or indicator of the
relative success or value of a drilling program because the significance of the
reserves and their economic potential may vary widely for each project. As of
December 31, 1999, the Company owned a working interest in 9,194 gross gas wells
(6,047 net) and 4,106 gross oil wells (2,468 net). Gross wells include 2,265
wells with multiple completions. The Company operated 66 percent of the gross
wells in which it owned an interest.
DELEVERAGING PROGRAM -- PROPERTY SALES
In 1998, following the Norcen Acquisition, the Company commenced a
deleveraging program designed to reduce the Company's debt. The Company sold
approximately $745 million of non-strategic properties and assets in 1998 and
1999. The majority of the proceeds from the property sales, along with the
Company's sale of its GPM business segment, were primarily used to retire debt.
As a result of the property sales, the Company's reserves were reduced by 704.1
Bcfe in 1998 and 128.5 Bcfe in 1999. A summary of properties that have been sold
is as follows:
<TABLE>
<CAPTION>
SALES PRICE
NON-STRATEGIC PROPERTIES OPERATING AREA (MILLION OF DOLLARS)
- ------------------------ -------------- --------------------
<S> <C> <C>
1998
Denver -- Julesburg Basin............................ U.S. Onshore $ 41
Matagorda Island Blocks.............................. U.S. Offshore 158
Rockies Package...................................... U.S. Onshore 46
Eugene Island Blocks................................. U.S. Offshore 8
Canadian Package..................................... Canada 145
Superior Propane..................................... Canada 48
----
Total...................................... $446
====
1999
Caroline -- Swan Hill................................ Canada $108
South Texas Package.................................. U.S. Onshore 138
Deadwood East Texas.................................. U.S. Onshore 18
Rockies Package...................................... U.S. Onshore 10
Project Orange....................................... Other 25
----
Total...................................... $299
====
</TABLE>
11
<PAGE> 17
ITEM 3. LEGAL PROCEEDINGS
GENERAL
The Company is a defendant in a number of lawsuits and is involved in
governmental proceedings arising in the ordinary course of business, including,
but not limited to, royalty claims, contract claims and environmental claims.
The Company has also been named as a defendant in various personal injury
claims, including numerous claims by employees of third-party contractors
alleging exposure to asbestos and asbestos-containing materials while working at
the Corpus Christi refinery, which the Company sold in segments in 1987 and
1989. While the Company's management cannot predict the outcome of such
litigation and other proceedings, management does not expect these matters to
have a materially adverse effect on the consolidated results of operations,
financial condition or cash flows of the Company. Discussed below are several
specific proceedings.
MINERAL RESERVATION LITIGATION
In August 1994, the surface owners (McCormick, et al.) of portions of five
sections of Colorado land that are subject to mineral reservations made by the
Company's predecessor in title brought suit against the Company in State
District Court, Weld County, Colorado, to quiet title to minerals, including
crude oil (in some of the lands) and natural gas. On June 23, 1997, the State
District Court granted the Company's motion for summary judgment, holding as a
matter of law that the mineral reservations at issue were unambiguous and
included all valuable non-surface substances, including oil and gas. The
Colorado Court of Appeals affirmed the decision of the State District Court in
granting the Company's motion for summary judgment on December 10, 1998 and then
denied the surface owners' motion for rehearing. The surface owners then filed a
Petition for Writ with the Colorado Supreme Court, which was granted in
September 1999. Oral arguments are expected to be heard during the first half of
2000.
ROYALTY LITIGATION
The Company is a defendant in a number of lawsuits in which plaintiffs
allege that the Company underpaid royalties to them on crude oil and natural gas
production. In addition, certain of such suits allege that the Company has
violated antitrust laws and other similar laws. None of this litigation
specifies the amount of damages being claimed. This litigation against the
Company and others in the oil and gas industry suggests that more suits of this
type will be filed against the Company, including, perhaps, suits by other types
of interest owners and suits in other jurisdictions. The Company intends to
vigorously defend against such litigation, as well as any similar lawsuits
subsequently brought against the Company. In the opinion of management of the
Company, the outcome of these matters should not have a material adverse effect
on the consolidated results of operations, financial condition or cash flows of
the Company.
A group of royalty owners purporting to represent all of the Company's gas
royalty owners in Texas (Neinast, et al.) was granted class action certification
in December 1999, by the 21st Judicial District Court of Washington County,
Texas, in connection with a gas royalty underpayment case against the Company.
This court did not review the merits of the claims being asserted. The pleadings
did not specify the damages being claimed and no evidence has been provided to
the Company with respect to the amount of damages being claimed. The Company
appealed this class certification decision to the Houston Court of Appeals -
First District. This appeal is on an expedited schedule, with the Company filing
its brief on March 13, 2000.
During 1999, the Company, together with other oil and gas company
defendants, agreed to settle several suits involving allegations of royalty
underpayments on crude oil production. These settlements were without any
admission of fault or wrongdoing on the part of the Company. The Company's
portion of the settlements did not have a material adverse effect on
consolidated results of operations, financial condition or cash flows of the
Company.
12
<PAGE> 18
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the
quarter ended December 31, 1999.
EXECUTIVE OFFICERS OF THE REGISTRANT
<TABLE>
<CAPTION>
NAME POSITION AGE
- ---- -------- ---
<S> <C> <C>
George Lindahl III (a).................... Chairman, President and Chief Executive Officer 53
Thomas R. Blank (b)....................... Vice President -- State, Regulatory and Public 47
Affairs
Kerry R. Brittain (c)..................... Vice President, General Counsel and Secretary 53
Anne M. Franklin (d)...................... Vice President -- People 43
Donald W. Niemiec (e)..................... Vice President -- Marketing and Corporate 53
Development
Morris B. Smith (f)....................... Vice President, Chief Financial Officer and 55
Treasurer
John B. Vering (g)........................ Vice President -- Canadian Operations 50
</TABLE>
- ---------------
(a) Mr. Lindahl has held his current position with the Company since July 1999.
He was President and Chief Operating Officer from October 1996 to July 1999.
He was Executive Vice President -- Operations of the Company from August
1995 to October 1996. Prior thereto, he was Vice President -- Operations for
UPRC.
(b) Mr. Blank has held his current position with the Company since August 1997.
He was Communications Director for the Speaker of the House of
Representatives for the United States from February 1997 to August 1997.
Prior thereto, he was President of Hager Sharp, Inc.
(c) Mr. Brittain has held his current position with the Company since March
2000. Prior thereto, he was an Assistant General Counsel of the Company.
(d) Ms. Franklin has held her current position with the Company since August
1995. Prior thereto, she was Director of Executive Leadership and
Development for Ameritech, Inc.
(e) Mr. Niemiec has held his current position with the Company since September
1999. He served as Vice President -- Marketing from August 1995 until
September 1999. He has been Vice President -- Marketing of UPRC since 1993
and President of Union Pacific Fuels, Inc. ("UP Fuels") from 1990 to March
1999.
(f) Mr. Smith has held his current position as Vice President and Chief
Financial Officer with the Company since June 1996 and assumed the role of
Treasurer in June 1999. From September 1995 until June 1996, he was Vice
President and Controller of Union Pacific Corporation ("UPC"). Prior
thereto, he was Vice President -- Finance of Union Pacific Railroad Company.
(g) Mr. Vering has held his current position with the Company since March 1998.
From October 1996 until March 1998 he was Vice President -- Exploration and
Production Services of the Company. Prior thereto, he was General
Manager -- Austin Chalk of the Company.
13
<PAGE> 19
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The common stock of the Company is traded on the New York Stock Exchange
under the symbol "UPR." Information with respect to the quarterly high and low
sales prices per share for the Company's common stock, as reported on the New
York Stock Exchange Composite Tape, as well as the dividends declared on such
stock, is set forth under Selected Quarterly Data on page 85. At February 29,
2000, there were 251,952,336 shares of outstanding common stock and
approximately 113,400 shareholders of record. At that date, the closing price of
the common stock on the New York Stock Exchange was $8.9375.
The Company has paid quarterly cash dividends of $0.05 per share since its
initial public offering in October 1995. The Company currently intends to
continue to pay quarterly cash dividends on its outstanding shares of common
stock. The determination of the amount of future cash dividends, if any, to be
declared and paid by the Company will depend upon, among other things, (i) the
Company's financial condition, (ii) funds from operations, (iii) the level of
its capital and exploratory expenditures, (iv) future business prospects and (v)
other factors deemed relevant by the Board of Directors. Accordingly, there can
be no assurance that dividends will be paid. The Company has no current plans to
increase or decrease its dividend.
ITEM 6. SELECTED FINANCIAL DATA
FIVE-YEAR FINANCIAL SUMMARY
<TABLE>
<CAPTION>
AS OF OR FOR THE YEARS ENDED DECEMBER 31,
-------------------------------------------------------------
1999 1998 1997 1996 1995
-------- --------- -------- -------- --------
(MILLIONS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Operating revenues................ $1,727.5 $ 1,841.0 $1,518.0 $1,369.2 $1,166.8(d)
Operating income (loss)........... 135.8 (1,193.2) 433.9 408.5 380.3
Income (loss) from continuing
operations...................... 89.2 (883.1) 303.1 253.7 294.2
Net income (loss)................. 225.8(a) (898.7)(b) 333.0 320.8 350.7
Per share:
Income (loss) from continuing
operations -- basic.......... 0.36 (3.57) 1.21 1.02 n/a(e)
Income (loss) from continuing
operations -- diluted........ 0.36 (3.57) 1.21 1.01 n/a(e)
Net income (loss) -- basic...... 0.91 (3.63) 1.33 1.29 n/a(e)
Net income (loss) -- diluted.... 0.91 (3.63) 1.33 1.28 n/a(e)
Dividends....................... 0.20 0.20 0.20 0.20 0.05(f)
FINANCIAL POSITION DATA:
Properties -- net................. $5,471.0 $ 6,093.3 $2,901.1 $2,404.7 $2,238.4
Total assets...................... 6,146.9 7,642.4 4,313.7 3,531.6 3,265.7
Total debt........................ 2,799.6 4,598.7 1,230.6 670.9 101.5
Shareholders' equity.............. 937.5 728.2 1,760.7 1,514.3 1,312.4
CASH FLOW DATA:
Capital and exploratory
expenditures.................... $ 428.2 $ 3,828.8(c) $1,188.4 $ 773.0 $ 603.0
Cash provided by operations....... 995.5 1,031.1 856.2 772.5 719.0
</TABLE>
- ---------------
(a) In 1999, the Company recorded a $157.0 million gain on the GPM Disposition,
net of tax and a $3.4 million net of tax extraordinary gain on the early
extinguishment of debt.
(b) In 1998, the Company recorded a $760 million after-tax charge related to
asset impairments in accordance with Statement of Financial Accounting
Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of" ("SFAS No. 121").
14
<PAGE> 20
(c) In March 1998, the Company acquired Norcen for $2.634 billion.
(d) In November 1995, the Company recorded a $122.5 million pretax ($78.5
million after-tax) gain resulting from the Columbia Gas Transmission Company
bankruptcy settlement.
(e) Earnings per share information prior to 1996 has been omitted as the Company
was a wholly-owned subsidiary of UPC until the Company's initial public
offering in October 1995. Therefore, net income per share is not applicable
for periods prior to the fourth quarter of 1995.
(f) Represents the dividend declared with respect to the fourth quarter of 1995.
Prior to October 1995, the Company was wholly owned by UPC; therefore,
dividends per share is not applicable for prior periods.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following information should be read in conjunction with the
information contained in the Consolidated Financial Statements and the notes
thereto included in Item 8 of this Annual Report. The Consolidated Statement of
Income for 1997 has been restated to present the Company's GPM business segment
as discontinued operations.
SIGNIFICANT EVENTS
NORCEN ACQUISITION
In March 1998, the Company acquired Norcen for an aggregate purchase price
of $2.634 billion, and also assumed long-term debt obligations of Norcen
totaling approximately $1 billion. The acquisition was accounted for as a
purchase effective March 3, 1998, and, therefore, Norcen's financial results are
reflected in the Company's results beginning in March 1998. See Note 2 to the
Consolidated Financial Statements.
PROPERTY SALES AND GPM DIVESTITURE
In 1998, following the Norcen Acquisition, the Company commenced a
deleveraging program designed to reduce the Company's debt. By December 31,
1998, the Company had sold over $400 million of properties. Properties sold
included the Denver-Julesburg Basin in the Rockies (the "DJ Basin"), the
Matagorda Island Block 623 Field and surrounding blocks (the "Matagorda
property") and other U.S. Offshore, Rockies and certain Canadian properties.
During 1999, the Company continued its deleveraging program. The property
sales in 1999 included properties located in Canada's Caroline-Swan Hill field,
South Texas, and various properties in East Texas and the Rockies. The Company
also monetized a gas co-generation project.
In addition, the Company's sale of the GPM business segment to Duke was
completed on March 31, 1999 for $1.36 billion. The GPM business segment was
presented as a discontinued operation in the Consolidated Financial Statements.
See Note 3 to the Consolidated Financial Statements.
CRUDE OIL AND NATURAL GAS SALES PRICE AND HEDGING LOSSES
During 1998, prices for oil and natural gas declined as a result of several
factors. These factors included, but were not limited to, high production levels
from members of the Organization of Petroleum Exporting Countries ("OPEC") and
other countries, generally mild weather conditions, the economic weakness in
several Asian countries and excessive natural gas storage levels. These prices
were 29 percent and 10 percent, respectively, below the corresponding price
strips on December 31, 1997.
During 1999, prices for crude oil and natural gas increased. Members of
OPEC and other countries lowered crude oil production levels and natural gas
storage levels declined. The Company was unable to take full advantage of the
price increases, primarily due to solvency-based oil hedges that were put into
place at an average price of $14.50 per barrel. Those hedges, which expired in
December 1999, lowered revenues and operating income by about $178.1 million
during 1999.
15
<PAGE> 21
IMPAIRMENT OF LONG-LIVED ASSETS
The Company recorded a pretax charge of $1.23 billion ($760.1 million after
tax) in the fourth quarter of 1998, as required by SFAS No. 121. The non-cash
asset impairment charge to earnings was recorded as DD&A expense of $1.17
billion and surrendered lease expense of $54.5 million in the Company's
Consolidated Statement of Income. Low hydrocarbon prices at the end of
1998 -- particularly their effect on the value of the Company's heavy oil
properties in Canada and Guatemala -- and reserve revisions following a
comprehensive review of reserves completed in December 1998, were the principal
factors contributing to the impairment. Most of the reserve revisions were
associated with properties in Canada and U.S. Offshore that were acquired by the
Company in 1998. The revisions also reflect disappointing well performance from
discoveries that were not on production at the time of the Norcen Acquisition.
In 1999, the Company recorded a pretax charge of $120.6 million for
impairment of assets. The non-cash asset impairment charges to earnings were
recorded as DD&A expense of $70.6 million and surrendered lease expense of $50
million in the Company's Consolidated Statement of Income. Reserve revisions
following a comprehensive review of reserves was the principal factor
contributing to $70.6 million impairment of producing properties. These
properties were primarily in the Gulf Coast Onshore area. Surrendered lease
expense of $50.0 million was recorded for the Delta Centro project in Venezuela
as a result of a $9.2 million dry hole drilled on the prospect in 1999.
CORPORATE REORGANIZATION AND REDUCTION IN FORCE
As a result of the low price environment in 1998 and the resulting
reduction in cash flows generated by the Company's operations, the Company
recorded a pretax charge in 1998 of $17 million to cover the cost of a workforce
reduction at its Fort Worth, Texas headquarters and other domestic locations,
and costs associated with an offshore rig commitment.
During the first quarter of 1999, the Company reorganized its operating
groups, announced workforce reductions for its Canadian and U.S. operations and
established an early retirement program. As a result of these actions, the
Company recorded a $14.5 million restructuring charge. The charge included $7.3
million for severance costs and excess office space commitments, an additional
$4.2 million liability for pension and other postretirement benefits in
connection with the early retirement program and a $3.0 million valuation
allowance for specialty drilling equipment and supplies no longer required for
cancelled drilling programs. The charge was partially offset by the $3.1 million
reversal of the 1998 charge associated with the offshore rig commitment.
16
<PAGE> 22
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1999 COMPARED TO DECEMBER 31, 1998
SUMMARY FINANCIAL DATA
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------
1999 1998
---------- -----------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Total operating revenues.................................... $1,727.5 $ 1,841.0
Total operating expenses.................................... 1,591.7 3,034.2
Operating income (loss)..................................... 135.8 (1,193.2)
Income (loss) from continuing operations.................... 89.2 (883.1)
Net income (loss)........................................... 225.8 (898.7)
</TABLE>
The Company recorded net income of $225.8 million ($0.91 per share) in
1999, compared to a net loss of $898.7 million ($3.63 per share) in 1998. The
improvement was largely due to the recording of a $1.23 billion ($760.1 million
after-tax) SFAS No. 121 asset impairment in 1998, and a $157.0 million after-tax
gain on the 1999 sale of the GPM business segment to Duke. In addition, higher
commodity prices combined with cost reduction programs contributed to improved
results from continuing operations. A $3.4 million after tax extraordinary gain
was also recorded in 1999 on the extinguishment of debt. Restructuring charges
related to corporate reorganization and reductions in force were included in the
results of both 1999 ($11.4 million) and 1998 ($17.0 million).
RESULTS OF CONTINUING OPERATIONS
The Company recorded income from continuing operations of $89.2 million for
1999 compared to a loss of $883.1 million last year, with earnings per share of
$0.36 in 1999 up from a loss of $3.57 per share a year ago. Included in 1998
results was a charge of $1.22 billion ($756.0 million after-tax) related to the
asset impairment. Higher prices contributed $132.4 million to income, while
significant cost reductions were achieved as a result of cost control programs,
property sales and workforce reductions. These reductions resulted in a $65.2
million decrease in lease operating costs and substantially lower overhead
costs. Interest costs declined by $31.1 million due to the debt reduction
resulting from the use of proceeds from the Company's aggressive deleveraging
program and the GPM Disposition. The Company also recorded $58.1 million after
tax income for tax settlements in the United States and Canada and $97.5 million
after tax in higher gains from foreign currency remeasurement. Offsetting these
benefits were the impacts of lower volumes of $196.5 million, lower minerals
income of $15.7 million, lower gains on assets sales of $49.5 million and a
$43.4 million charge for natural gas firm transportation obligations associated
with the GPM Disposition.
SUMMARY OF SEGMENT FINANCIAL DATA
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------
1999 1998
--------- -----------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Segment operating income (loss):
Exploration and production................................ $ 122.5 $(1,199.2)
Minerals.................................................. 117.8 133.5
Corporate ("General and Administrative").................. (104.5) (127.5)
------- ---------
Total............................................. $ 135.8 $(1,193.2)
======= =========
</TABLE>
Operating income increased by $1.33 billion to $135.8 million for the year.
Exploration and production operating income, excluding the $1.22 billion 1998
asset impairment charge, increased by $104.1 million to $122.5 million. Lower
volumes reduced operating income by $196.5 million, while gains on sales of
assets and
17
<PAGE> 23
investments decreased by $21.0 million largely due to the sale of the Matagorda
property in 1998. Price improvements added $132.4 million to revenues, while
exploration and production expenses decreased by $60.3 million, associated with
reduced capital spending, lower volumes, cost saving initiatives, and the
restructuring of the Company. DD&A expenses, excluding impairments declined by
$201.8 million, caused by both lower volumes ($121.8 million) and DD&A per unit
rates ($80.0 million).
Minerals operating income decreased by $15.7 million to $117.8 million.
Black Butte equity income was down by $7.3 million to $79.3 million, primarily
due to coal contract obligations which were delayed until 2000, offset by the
absence of a $14.3 million accrual for a legal settlement in 1998. Coal
royalties declined by $3.7 million due to lower volumes of coal extracted and
sold from Company property. (See "Outlook and Other Matters" regarding Black
Butte equity income and a coal contract that expires in 2000). In addition, soft
market conditions for soda ash resulted in lower prices and a $4.6 million
decline in equity income and soda ash royalties, while lower future uranium mine
reclamation costs provided a $4.0 million offsetting income benefit.
General and administrative ("G&A") expenses decreased by $23.0 million,
reflecting lower legal costs and cost savings related to the reductions in force
that occurred in late 1998 and early 1999. Restructuring charges affected both
years -- $11.4 million in 1999 and $17.0 million in 1998. The 1999 reduction in
G&A was partially offset by $11.2 million of payroll expense related to the
vesting of the January 1999 retention stock awards.
EXPLORATION AND PRODUCTION OPERATIONS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------
1999 1998
---------- -----------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Exploration and production revenues......................... $1,473.3 $ 1,537.4
Other oil and gas revenues................................ 133.7 162.5
-------- ---------
Total operating revenues.......................... 1,607.0 1,699.9
-------- ---------
Operating expenses:
Production................................................ 400.6 444.3
Exploration............................................... 267.9 339.0
Depreciation, depletion and amortization.................. 816.0 2,115.8
-------- ---------
Total operating expenses.......................... 1,484.5 2,899.1
-------- ---------
Operating income (loss)..................................... $ 122.5 $(1,199.2)
======== =========
</TABLE>
Operating Revenues
Exploration and production revenues decreased by $64.1 million (4%) to
$1,473.3 million for 1999, due to a $196.5 million reduction associated with
lower volumes, partly offset by a $132.4 million increase associated with higher
product prices. Other oil and gas revenues decreased by $28.8 million largely
due to $49.5 million in lower gains on property sales, offset by $28.5 million
of gains on the disposition of a gas co-generation project. Hedging positions in
both crude and natural gas products reduced revenues by $178.1 million for 1999
compared to a reduction of $9.0 million for 1998.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------
1999 1998 1999 1998
------- ------- ------ ------
(WITHOUT HEDGING) (WITH HEDGING)
<S> <C> <C> <C> <C>
Average price realizations:
Natural gas (per Mcf).................................... $ 1.94 $ 1.77 $ 1.83 $ 1.74
Natural gas liquids (per Bbl)............................ 10.95 7.88 10.95 7.88
Crude oil (per Bbl)...................................... 14.84 10.37 11.81 10.48
Average price (per Mcfe)................................. 2.10 1.72 1.88 1.71
</TABLE>
18
<PAGE> 24
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------
1999 1998
--------- ---------
<S> <C> <C>
Production volumes:
Natural gas (MMcfd)....................................... 1,278.8 1,441.1
Natural gas liquids (MBbld)............................... 28.4 33.1
Crude oil (MBbld)......................................... 117.1 137.9
Total (MMcfed)............................................ 2,151.6 2,467.0
</TABLE>
Exploration and production volumes of 2,151.6 MMcfed decreased by 315.4
MMcfed (13%) from 1998 results primarily due to property sales (approximately
153 MMcfed) and production declines related to reduced capital spending levels.
Results for 1998 include only ten months of results from properties acquired
through the Norcen Acquisition.
U.S. Onshore volumes decreased by 236.5 MMcfed, reflecting the decline in
capital spending and effects of property sales, which contributed 58 MMcfed to
the decrease. U.S. Offshore volumes decreased by 42.9 MMcfed as the impact of
property sales (approximately 35 MMcfed) and production declines offset the full
year of production from properties acquired through the Norcen Acquisition.
Canadian volumes decreased by 56.9 MMcfed primarily related to the impact of
property sales (approximately 60 MMcfed) that were partially offset by the full
year of production from properties acquired through the Norcen Acquisition.
Other International volumes improved 20.9 MMcfed over 1998, primarily due to the
inclusion of the full year of volumes in 1999 from properties acquired through
the Norcen Acquisition.
Natural gas volumes decreased by 162.3 MMcfd to 1,278.8 MMcfd during 1999,
principally reflecting reduced capital spending levels, property sales and
production declines for existing properties, offset by the inclusion of a full
year of volumes from properties acquired through the Norcen Acquisition. Total
United States volumes declined by 159.7 MMcfd, while Canada volumes decreased by
3.4 MMcfd.
Natural gas liquid volumes decreased by 4.7 MBbld to 28.4 MBbld. The
decline is largely related to the sales of the offshore Matagorda property in
the third quarter of 1998 and the South Texas and the Canadian Caroline-Swan
Hill properties in early 1999, as well as production declines resulting from
reduced capital spending levels. Partially countering the decline was ethane
recovery in the U.S. Onshore for most of 1999.
Crude oil volumes declined by 20.8 MBbld to 117.1 MBbld for 1999. The
decrease reflects property sales as well as production declines in U.S. Onshore
and Canada, offset by the full year of Norcen property volumes in 1999. U.S.
Onshore volumes declined by 15.8 MBbld, while Canada volumes decreased by 6.6
MBbld. Other International volumes improved 3.3 MBbld largely due to the
inclusion of the full year of production from properties acquired through the
Norcen Acquisition.
Operating Expenses
Production expenses, which include lease operating costs, production
severance and property taxes, and production overhead, were $400.6 million for
1999, down $43.7 million from last year. Production costs per unit increased
from $0.49 per Mcfe last year to $0.51 per Mcfe for 1999, reflecting the impacts
of production declines and higher production taxes caused by higher prices.
Total lease operating costs declined by $65.2 million primarily due to property
sales and cost reduction efforts initiated in late 1998. Included in the lease
operating cost decline were lower costs for personnel, workovers, maintenance
and repairs and salt water disposal. The reduction was significant as 1999
results include the full year of expenses related to the properties acquired
through the Norcen Acquisition. Lease operating expenses on a per unit basis
dropped from $0.34 per Mcfe in 1998 to $0.31 per Mcfe. Production severance and
property taxes increased by $23.8 million from last year, reflecting increased
product prices for U.S. Onshore and Guatemalan operations, as well as $8.2
million related to severance tax audit adjustments. Production overhead costs
decreased by $2.3 million from 1998, despite $3.6 million of production overhead
costs related to the vesting of the January 1999 retention stock awards. The
majority of the overhead savings in 1999 was the result of lower personnel and
related costs in connection with the reductions in work force.
19
<PAGE> 25
Exploration expenses of $267.9 million decreased by $71.1 million from last
year, primarily due to the Company's reduced capital spending program. Dry hole
expenses decreased by $17.2 million, geological and geophysical costs were $30.5
million lower and other surrendered lease costs dropped $13.4 million. Included
in 1999 dry hole expenses was $24.0 million related to a well that was
reclassified to an exploratory dry hole in the fourth quarter of 1999.
Exploration overhead costs declined by $6.2 million primarily from reductions in
personnel ($2.1 million) and computer costs ($2.9 million) caused by work force
reductions.
DD&A costs for exploration and production properties declined by $1.3
billion from last year to $816.0 million. Included in the 1999 results was $65.1
million, primarily related to the impairment of certain U.S. Onshore properties,
while 1998 results included $1,163.1 million related to producing property
impairments. Excluding the impairments, lower production volumes caused a $121.8
million reduction, while lower DD&A rates produced an $80.0 million decline.
DD&A per unit rates decreased from $1.06 per Mcfe last year to $0.96 per Mcfe in
1999 largely due to the asset impairment recorded by the Company in 1998.
MINERALS OPERATIONS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------
1999 1998
-------- --------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Operating Income
Coal...................................................... $ 91.1 $101.5
Soda ash.................................................. 26.3 35.5
Other..................................................... 0.4 (3.5)
------ ------
Total operating income............................ $117.8 $133.5
====== ======
</TABLE>
Operating income for minerals declined by $15.7 million from last year.
Equity income from the Black Butte joint venture declined by $7.3 million
reflecting lower volumes resulting from postponement of contract obligations
until 2000, partially offset by the absence of a $14.3 million accrual in 1998
for a legal settlement (See "Outlook and Other Matters" regarding the Black
Butte Contract expiration in 2000). Coal royalty income decreased by $3.7
million from lower volumes as mining operations focused on Federal sections, and
soda ash royalties decreased by $4.6 million reflecting soft conditions in the
soda ash market. Operating income at the Company's soda ash joint venture was
down $4.6 million, also related to the soft conditions in the soda ash market.
Results in 1999 also include a $4.0 million reserve release related to lower
reclamation requirements and a $5.5 million impairment charge, while results
from 1998 include a $2.0 million gain on the sale of industrial mineral
properties and a $4.0 million asset impairment charge.
GENERAL AND ADMINISTRATIVE AND OTHER INCOME/EXPENSE
General and administrative expenses (including DD&A) of $104.5 million
decreased by $23.0 million from 1998. Restructuring charges affected both
years -- $11.4 million in 1999 and $17.0 million in 1998 -- both related to a
corporate reorganization and reductions in work force. Included in 1999 general
and administrative expenses were $11.2 million of payroll expense related to the
vesting of the January 1999 retention stock awards. Contributing to lower costs
in 1999 were benefits in several cost categories reflecting savings from the
late 1998 and early 1999 reductions in force, early retirement programs and the
GPM Disposition. These savings contributed to declines of $5.2 million in
salaries and benefits, $4.2 million in computer costs, $3.0 million in
professional and temporary services and $1.7 million in rent expense. In
addition, legal costs decreased by $2.8 million and donations decreased by $2.1
million.
Other income/expense -- net increased by $77.0 million over 1998 to income
of $31.7 million for 1999. Causing the majority of the improvement was 1999
foreign currency gains of $44.2 million primarily related to the remeasurement
of U.S. dollar denominated debt in Canada, while 1998 results included a $46.5
million charge related to the same issue. Interest income increased by $19.4
million to $30.5 million in 1999, principally related to interest income from
the Canadian ($7.1 million) and UPC ($20.5 million) tax settlements. Also
included in 1999 results was a charge of $43.4 million for natural gas firm
transportation
20
<PAGE> 26
contract obligations. Results in 1998 included a $14.3 million charge related to
the expiration of interest rate lock contracts intended to hedge interest rates
for a contemplated bond issuance, and an $11.0 million gain on the closure of a
foreign exchange contract entered into in connection with the 1998 Norcen
Acquisition.
Interest expense declined by $31.1 million to $218.7 million in 1999,
reflecting reduced debt balances partly offset by higher interest rates on fixed
rate debt. The debt reduction is primarily the result of the use of proceeds
from the sale of the GPM business segment to pay down debt at the end of March
1999, as well as other actions taken to reduce debt since mid-1998 in connection
with the Company's deleveraging program. Interest expense in 1998 included only
ten months of interest on debt from the Norcen Acquisition, completed on March
3, 1998.
The income tax benefit from continuing operations declined by $464.8
million to $140.4 million for 1999. Lower pretax loss from continuing
operations, primarily due to the 1998 SFAS No. 121 asset impairment charge,
which had provided a tax benefit of $464.6 million in 1998. Included in 1999
results were benefits of $27.9 million related to a Canadian tax settlement and
$11.9 million related to a tax settlement with UPC (See Note 8). Also offsetting
the decline, was the recording of $28.1 million of favorable tax adjustments in
1999 primarily related to prior years and a $9.2 million reduction in state
taxes. Section 29 credits were $17.9 million in 1999 and $16.4 million in 1998,
while 1999 also included $29.3 million of foreign currency gains related to the
remeasurement of deferred tax liabilities in Guatemala and Venezuela, compared
to gains of $22.5 million included in 1998.
RESULTS OF DISCONTINUED OPERATIONS
Income from discontinued operations, net of taxes, was $133.2 million for
1999, an increase of $148.8 from 1998 results. The variance is due to the $157.0
million after-tax gain from the GPM Disposition. GPM business segment operating
loss for 1999 was $23.8 million after-tax primarily due to a $21.5 million
pretax charge related to firm transportation contracts that were marked to
market, as well as lower margins and product prices.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1998 COMPARED TO DECEMBER 31, 1997
SUMMARY FINANCIAL DATA
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------
1998 1997
---------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Total operating revenues.................................... $ 1,841.0 $1,518.0
Total operating expenses.................................... 3,034.2 1,084.1
Operating income (loss)..................................... (1,193.2) 433.9
Income (loss) from continuing operations.................... (883.1) 303.1
Net income (loss)........................................... (898.7) 333.0
</TABLE>
The Company recorded a net loss of $898.7 million in 1998, or a loss of
$3.63 per share, compared to net income of $333.0 million, or $1.33 per share,
in 1997. The decrease is primarily due to the impact of the SFAS No. 121 asset
impairment of $1.23 billion ($760.1 million after tax), the majority of which
affected continuing operations, and lower product prices.
21
<PAGE> 27
RESULTS OF CONTINUING OPERATIONS
In 1998, the Company reported a net loss from continuing operations of
$883.1 million, compared to income from continuing operations of $303.1 million
in 1997. Included in 1998 results was a charge of $1.22 billion ($756.0 million
after tax) for the asset impairment. The additional volumes from the Norcen
Acquisition added revenues of $456.7 million, while depressed product prices
reduced revenues from non-Norcen properties by more than $200 million as average
prices declined 22 percent. Additional factors that impacted income, primarily
driven by the Norcen Acquisition, were $273.9 million of higher production,
exploration and administrative expenses and $210.3 million of higher interest
expense. Included in administrative expenses was a restructuring charge of $17.0
million related to a reduction in force of the Company's domestic operations.
The Company realized a $140.0 million improvement to operating income as a
result of gains on the sale of various properties.
SUMMARY OF SEGMENT FINANCIAL DATA
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------
1998 1997
---------- -------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Segment operating income (loss):
Exploration and production................................ $(1,199.2) $373.4
Minerals.................................................. 133.5 135.5
Corporate ("General and Administrative").................. (127.5) (75.0)
--------- ------
Total............................................. $(1,193.2) $433.9
========= ======
</TABLE>
The operating loss was $1,193.2 million in 1998 compared to operating
income of $433.9 million in 1997. Exploration and production operating income,
excluding the asset impairment related to such properties, declined by $355.1
million to $18.3 million. These results reflect lower prices for all products
and increased operating, exploration and DD&A costs, which offset higher volumes
and the gains on the sale of various properties. Minerals operating income
dropped slightly to $133.5 million due to a $14.3 million accrual for a legal
settlement and a $4.0 million asset impairment but was partially offset by
increased operating income due to an amended coal supply agreement at Black
Butte. General and administrative expenses, excluding the restructuring charge,
increased by $35.5 million primarily due to increased administrative expenses
associated with expanded Canadian and Other International operations and an $8.2
million charge related to the settlement of various crude royalty and tax
issues.
EXPLORATION AND PRODUCTION OPERATIONS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------
1998 1997
--------- --------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Exploration and production revenues......................... $ 1,537.4 $1,293.5
Other oil and gas revenues.................................. 162.5 84.7
--------- --------
Total operating revenues.......................... 1,699.9 1,378.2
Production expense.......................................... 444.3 300.8
Exploration expense......................................... 339.0 204.7
Depreciation, depletion and amortization.................... 2,115.8 499.3
--------- --------
Total operating expenses.......................... 2,899.1 1,004.8
--------- --------
Operating income (loss)..................................... $(1,199.2) $ 373.4
========= ========
</TABLE>
Operating Revenues
Exploration and production revenues increased by $243.9 million (19%) to
$1,537.4 million, $456.7 million of which were associated with properties added
in the Norcen Acquisition. Excluding the Norcen
22
<PAGE> 28
Acquisition properties, volumes were essentially flat to 1997 production levels;
however, product price declines reduced revenues by $211.0 million. Other oil
and gas revenues increased by $77.8 million from higher gains on property sales,
principally the sales of the DJ Basin and the Matagorda property.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------
1998 1997 1998 1997
------- ------- ------ ------
(WITHOUT HEDGING) (WITH HEDGING)
<S> <C> <C> <C> <C>
Average price realizations:
Natural gas (per Mcf).................................... $ 1.77 $ 2.19 $ 1.74 $ 2.00
Natural gas liquids (per Bbl)............................ 7.88 11.23 7.88 11.23
Crude oil (per Bbl)...................................... 10.37 18.80 10.48 18.36
Average price (per Mcfe)................................. 1.72 2.34 1.71 2.19
</TABLE>
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------
1998 1997
-------- --------
<S> <C> <C>
Production volumes:
Natural gas (MMcfd)....................................... 1,441.1 1,108.5
Natural gas liquids (MBbld)............................... 33.1 31.7
Crude oil (MBbld)......................................... 137.9 52.9
Total (MMcfed).................................... 2,467.0 1,615.7
</TABLE>
Exploration and production volumes improved by 851.3 MMcfed to 2,467.0
MMcfed in 1998. Canada volumes were 481.0 MMcfed higher than last year, while
Other International volumes increased by 244.1 MMcfed, in both cases primarily
due to properties added in the Norcen Acquisition. Production from domestic
properties increased by 126.2 MMcfed including 97.2 MMcfed added in U.S.
Offshore largely from the Norcen Acquisition which offset the sale of the
Matagorda property. U.S. Onshore realized an increase of 54.5 MMcfed in 1998.
Natural gas volumes increased by 332.6 MMcfd (30%). Canada volumes
increased by 263.6 MMcfd and U.S. Offshore production was up 64.1 MMcf, largely
due to properties added in the Norcen Acquisition. U.S. Onshore production was
essentially flat due to declines in the Austin Chalk area that offset
improvements in all other areas.
Natural gas liquids volumes increased by 1.4 MBbld (4%) to 33.1 MBbld.
Production improvements included 2.5 MBbld in Canada largely due to the Norcen
Acquisition. This increase was partially offset by lower volumes from the U.S.
Onshore as a result of the decision to reject ethane and bypass gas due to low
NGL prices.
Crude oil volumes were 85.0 MBbld higher in 1998 primarily from properties
added in the Norcen Acquisition. Canada production was 33.7 MBbld higher for
1998, while additional production from Guatemala and Venezuela was 20.8 MBbld
and 16.7 MBbld, respectively. U.S. Onshore production was up 8.0 MBbld.
Operating Expenses
Production expenses increased by $143.5 million while production costs on a
per unit basis were $0.49 per Mcfe, 4 percent less than last year's $0.51 per
Mcfe. Total lease operating expenses rose by $141.3 million, of which $135.4
million was attributable to Norcen Acquisition properties. Lease operating
expenses on a per unit basis were up 22 percent to $0.34 per Mcfe which reflects
higher operating expenses associated with the production of heavy crude oil in
Guatemala, Venezuela and Canada. Production overhead costs were up $2.6 million
largely because of increased personnel costs due to the expanded international
operations.
Exploration expenses in 1998 increased by $134.3 million over 1997,
including $54.5 million of surrendered lease costs that were part of the SFAS
No. 121 asset impairment. Excluding the effect of the asset impairment, activity
related to properties added in the Norcen Acquisition contributed $72.8 million
to the increase. For domestic operations, exploration expenses were up 3 percent
to $210.8 million, excluding the surrendered lease asset impairment.
23
<PAGE> 29
DD&A increased by $1,616.5 million, including $1,163.1 million related to
the SFAS No. 121 asset impairment. On a per unit basis, DD&A expense, excluding
the asset impairment, rose $0.21 per Mcfe to $1.06 per Mcfe. Properties added in
the Norcen Acquisition contributed $377.4 million, excluding the asset
impairment. The remaining variance from non-Norcen Acquisition properties, $76.0
million, is associated with higher volumes that caused $11.3 million of the
total increase in DD&A, while a higher per unit rate added $64.7 million.
MINERALS OPERATIONS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------
1998 1997
-------- --------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Operating Income
Coal...................................................... $101.5 $ 83.3
Soda ash.................................................. 35.5 49.5
Other..................................................... (3.5) 2.7
------ ------
Total operating income............................ $133.5 $135.5
====== ======
</TABLE>
Minerals operating income decreased by $2.0 million. Contributing to the
decline was $14.0 million of lower operating income from soda ash operations,
reflecting lower royalties, lower equity income from the Company's soda ash
joint venture and the inclusion of a lease bonus in 1997 results. Also affecting
1998 performance was a $14.3 million accrual for a legal settlement and a $4.0
million asset impairment on certain industrial mineral and uranium properties.
Partly offsetting these items were $19.7 million of higher equity income from
Black Butte reflecting the amendment of a coal supply contract and a $2.0
million gain from a property sale.
GENERAL AND ADMINISTRATIVE AND OTHER INCOME/EXPENSE
General and administrative expenses increased by $52.5 million to $127.5
million, principally reflecting $21.1 million related to expanded international
operations and the $17.0 million restructuring charge. Also contributing to the
increase was an $8.2 million charge related to the settlement of various crude
royalty and tax issues, $3.3 million of additional rent expense, $2.4 million in
higher professional and temporary costs, and a $1.9 million rise in DD&A expense
for domestic overhead. On a per unit basis, excluding the restructuring charge,
G&A expenses were flat as compared to 1997 at $0.12 per Mcfe.
Other income/expense was $69.8 million lower than 1997 results. The
reduction reflects a $46.5 million foreign currency exchange rate loss and a
$14.3 million charge related to the expiration of interest rate lock contracts
intended to hedge such rates for a contemplated bond issuance. In addition, 1997
results included the benefit of a $23.0 million partial reduction of reserves
associated with the 1994 sale of the Wilmington, California oil field, due to
the reduction of environmental remediation exposure, a $7.2 million gain on the
sale of securities held for investment and $6.7 million of higher environmental
insurance settlements. Partly offsetting these declines were an $11.0 million
gain on the closure of a foreign exchange contract entered into in connection
with the Norcen Acquisition and the inclusion in 1997 of $17.8 million of costs
related to the unsuccessful bid to acquire Pennzoil Company.
Interest expense increased by $210.3 million to $249.8 million. This
increase reflects the borrowings made in connection with the Norcen Acquisition
and capital spending programs. Interest expense allocated to discontinued
operations was $21.1 million in 1998 and $13.6 million in 1997.
Income taxes declined by $721.0 million from 1997 to a benefit of $605.2
million, primarily the result of the pretax net loss in 1998. Included in 1998
results was a $22.5 million benefit due to foreign currency gains on deferred
tax liabilities in Venezuela and Guatemala. Section 29 tax credits in 1998 were
$16.4 million compared to $18.8 million in 1997. The effective tax rate in 1998
was 40.6 percent versus 28.6 percent in 1997 largely due to the effect of the
acquisition and expansion of operations outside the United States where higher
tax rates exist.
24
<PAGE> 30
RESULTS OF DISCONTINUED OPERATIONS
Results from discontinued operations generated a net loss of $15.6 million
for 1998, compared to income of $29.9 million in 1997. The segment reported an
operating loss of $1.0 million for 1998 versus operating income of $61.3 million
in 1997. Operating margins decreased by more than $45.0 million from 1997 due to
low product prices that were not offset by lower gas purchase prices. Operating
revenues decreased by $66.7 million from 1997 largely due to the $35.2 million
($23.0 million after tax) charge related to firm transportation contracts that
were marked to market in connection with the GPM Disposition, and lower product
prices. Volumes were up two percent while other benefits to income include the
$30.0 million pretax gain on the settlement of a gas supply agreement and lower
operating expenses that decreased by $17.9 million.
LIQUIDITY AND CAPITAL RESOURCES
The Company's primary sources of cash during 1999 were cash provided by
operations, long-term debt issuance and proceeds from the GPM Disposition and
other assets associated with the Company's deleveraging program. Cash outflows
for 1999 included the repayment of debt, capital and exploratory expenditures,
interest and dividends.
Cash from operations of $995.5 million was $35.6 million lower than in
1998. Higher prices provided $132.4 million, while lower volumes caused a
reduction of $196.5 million. Improvements were also achieved, primarily from tax
settlements ($65.9 million), lower lease operating costs ($65.2 million) and
interest expense ($31.1 million), as well as favorable results from the
Company's cost control programs. However, these improvements were offset by
lower minerals income, cash payments related to restructuring charges and
unfavorable changes in other working capital items.
Cash provided by investing activities was over $1.0 billion in 1999, up
from a usage of $3.3 billion last year. During 1999, the Company received
proceeds of $1.36 billion from the GPM Disposition, while 1998 included a $2.6
billion payment for the acquisition of Norcen. Proceeds from sales of assets and
other investments of $281.3 million were $203.7 million lower than 1998,
primarily reflecting higher 1998 property sales and asset monetizations in
connection with the Company's deleveraging program. Discontinued operations
required a use of cash of $203.6 million in 1999 compared to providing a $50.4
million source of cash in 1998.
Capital and exploratory expenditures from continuing operations (excluding
the Norcen Acquisition) decreased by $766.3 million from $1.2 billion in 1998 to
$428.2 million for 1999, reflecting the Company's effort to control capital
spending in light of depressed product prices early in 1999 and to achieve debt
reduction goals. The 1998 amounts set forth below include capital expenditures
for Norcen properties beginning in March.
25
<PAGE> 31
CAPITAL AND EXPLORATORY EXPENDITURES
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------
1999 1998
-------- ----------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Exploration and production
Exploration............................................... $ 78.1 $ 286.3
Production................................................ 329.7 764.9
Property purchases........................................ 15.3 110.7
------ --------
Total exploration and production.................. 423.1 1,161.9
Minerals, G&A and other..................................... 5.1 32.6
------ --------
Sub-total continuing operations........................... 428.2 1,194.5
Norcen purchase price....................................... -- 2,634.3
------ --------
Continuing operations............................. $428.2 $3,828.8
====== ========
Discontinued operations -- GPM.................... $ 32.9 $ 143.8
====== ========
</TABLE>
Exploration and production capital spending was down by $738.8 million to
$423.1 million, principally reflecting the effort to control capital spending in
light of depressed product prices early in 1999 and to achieve debt reduction
goals. The major categories of capital spending included development drilling
($232.6 million), other development capital ($97.2 million) and exploratory
drilling ($36.6 million). Exploration and development drilling by area included
$143.0 million in U.S. Onshore, $32.5 million in U.S. Offshore, $74.0 million in
Canada and $19.7 million in Other International, including $11.6 million in
Venezuela. Minerals, G&A and other capital was down $27.5 million to $5.1
million as spending in 1998 included costs related to the Fort Worth office
relocation.
As of December 31, 1999 and 1998, the total capitalization of the Company
was as follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------
1999 1998
--------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Long-term and short-term debt:
Commercial paper and other, net........................... $ 135.1 $2,351.9
Notes and debentures...................................... 2,630.5 2,225.0
Capital lease obligations................................. 16.0 17.4
(Discount) premium on notes and debentures -- net......... 18.0 4.4
-------- --------
Total debt........................................ 2,799.6 4,598.7
Shareholders' equity........................................ 937.5 728.2
-------- --------
Total capitalization.............................. $3,737.1 $5,326.9
======== ========
Debt to total capitalization.............................. 74.9% 86.3%
</TABLE>
At year-end 1998, the Company had three debt facilities totaling an
aggregate of U.S. $2.5 billion. These facilities were comprised of a $1.0
billion 364-Day Competitive Advance/Revolving Credit Agreement (the "Bridge
Facility"), a $750 million 364-Day Competitive Advance/Revolving Credit
Agreement and a $750 million Competitive Advance/Revolving Credit Agreement
("Long-Term Facility") expiring in October 2003.
In April 1999, the Company issued $500 million of notes and debentures
comprised of $200 million 7.3% Notes due April 2009 and $300 million 7.95%
Debentures due April 2029. The notes and debentures were issued under the
Company's existing $1.0 billion shelf registration statement, of which $500
million remains available.
During the first half of 1999, commercial paper, supported in part by the
Company's Bridge Facility, was repaid using proceeds from the Company's
deleveraging program and the GPM Disposition and the issuance
26
<PAGE> 32
of the long-term notes and debentures. The Bridge Facility was terminated in
April 1999. The $750 million 364-Day Competitive Advance/Revolving Credit
Agreement expired in October 1999, leaving the Company with the Long-Term
Facility at year-end 1999. The Long-Term Facility contains a covenant
stipulating that the ratio of consolidated debt to consolidated EBITDAX -- the
sum of operating income (before adjustments for income taxes, interest expense
or extraordinary gains or losses), depreciation, depletion and amortization and
exploration expenses -- cannot exceed 3.25:1.00. The Long-Term Facility also
places other restrictions on the Company regarding the creation of liens,
incurrence of additional indebtedness by subsidiaries, transactions with
affiliates, sales of stock of Union Pacific Resources Company (a wholly-owned
subsidiary of the Company) and certain mergers, consolidations and asset sales.
The Company was in compliance with the covenant provisions at year-end 1999 and
1998.
The 2005, 2008 and 2009 Notes and the 2018, 2028 and 2029 Debentures are
redeemable as a whole or in part, at the option of the Company at any time. The
redemption price is equal to the greater of (i) 100% of the principal amount of
the securities to be redeemed or (ii) the sum of the present values of the
remaining scheduled payments thereon, discounted to the redemption date on a
semi-annual basis at the Treasury Rate, plus a stated basis point spread and
accrued interest on the principal amount being redeemed to the redemption date.
There are no other notes or debentures redeemable prior to maturity. None of the
Company's notes and debentures is subject to a sinking fund requirement. At
December 31, 1999, the Company had an effective shelf registration statement on
file with the Securities and Exchange Commission that would permit the Company
or certain identified subsidiaries to offer up to $500 million in debt, equity
and/or other securities.
During 1999, the Company purchased on the open market and retired long-term
debt with a face value of $94.5 million at a discount prior to maturity. The
retirement of long-term debt due to the repurchases resulted in an extraordinary
gain of $3.4 million, net of $1.8 million of tax. The gain on the retirement was
classified as a gain from an extraordinary item on the Consolidated Statement of
Income. The Company may, at its discretion, make additional open market
purchases of debt prior to maturity.
At December 31, 1999, $135.1 million of commercial paper and bankers'
acceptances were classified as long-term. This classification reflects the
Company's intent and ability to maintain these borrowings on a long-term basis,
supported by the Long-Term Facility, through the issuance of additional
commercial paper and/or new term financings. Debt maturities through 2004,
excluding capital leases, are $135.1 million of bankers' acceptances due in 2000
and $250 million of debentures due July 2, 2002.
The fair value of the Company's long-term debt, excluding commercial paper
and bankers' acceptances, debt discount/premium and capital lease obligations
was approximately $2,467 million at December 31, 1999 and $2,088 million at
December 31, 1998. The fair value was estimated using quoted market prices.
These fair values were trading at a discount to their face value of 93.8% at
December 31, 1999 and 1998.
In April 1999, the Company's senior unsecured credit ratings were
downgraded by Standard & Poor's to BBB-, and by Moody's to Baa3. Its commercial
paper ratings were downgraded by Standard & Poor's to A3 and by Moody's to P3.
Fitch IBCA has continued to rate the Company's senior unsecured credit with a
BBB+ rating and its commercial paper with a F2 rating. The Company expects these
ratings to improve as debt is paid down.
The Company has guaranteed a portion of the OCI Wyoming, L.P. debt
facility. At December 31, 1999, OCI Wyoming, L.P. had an outstanding debt
facility balance of $30 million, of which the Company has guaranteed $14.7
million.
The Company utilizes letters of credit to support certain financing
instruments, performance contracts and insurance policies. The fair value of the
letters of credit at December 31, 1999 and 1998 was $41.3 million and $58.6
million, respectively.
During 1998, the Company purchased $26.7 million of its common stock.
During 1999, the Company paid quarterly cash dividends of $0.05 per share on its
outstanding common stock, and on October 21,1999, declared a $0.05 per share
dividend that was paid on January 2, 2000. The determination of the amount of
future cash dividends, if any, to be declared and paid by the Company will
depend upon, among other things,
27
<PAGE> 33
the Company's financial condition, funds from operations, the level of its
capital and exploratory expenditures, future business prospects and other facts
deemed relevant by the Board of Directors. Accordingly, there can be no
assurance that dividends will be paid.
OUTLOOK AND OTHER MATTERS
The Company expects its average oil and gas production to decline slightly
in 2000 compared to 1999. Production declines during the first part of 2000 are
expected to be reversed in the second half of 2000 and following years, as the
Company increases its capital spending and new projects are completed and placed
into service. The Company's proved reserves declined by about seven percent in
1999. The Company's ability to replace reserves in 1999 was impacted by the
postponement of the Mississippi Canyon Block 755 ("Gomez") deep-water offshore
prospect until 2000, together with the declines related to reduced capital
spending in 1999. The Company's reserve replacement costs were $0.91 per Mcfe,
which was below its five year average of $1.10 per Mcfe. In 2000, the Company
expects to modestly grow its reserves through development drilling programs and
to continue to pursue exploration opportunities.
Prices for crude oil, natural gas and NGLs in the first quarter of 2000
were higher than historic average hydrocarbon prices. NYMEX crude oil prices
have risen sharply from about $10 per barrel in early 1999 to over $30 per
barrel in early 2000, as the demand for crude oil has exceeded worldwide
production and inventory. Reduced crude oil production by members of OPEC and an
increase in consumption of crude oil in Asian countries resulting from their
improved economies have contributed to the greater demand for crude oil. The
increase in natural gas prices in the first quarter of 2000 reflects the tight
natural gas supplies compared to United States demand. Cold weather in early
2000 in the northeast United States, an increase in demand for the industrial
use of natural gas and lower production resulting from the decline in drilling
in prior years have contributed to the draw down in gas inventory supplies. The
Company expects prices to remain high in 2000; however, price fluctuations could
affect expected future net income, cash flows, capital spending and debt
reduction. For 2000, the Company has reduced some of its exposure to lower
prices by purchasing puts and fixed price contracts and limited some of the
upside of higher prices by selling calls and fixed price contracts. Slightly
more than one-half of the Company's estimated 2000 production was hedged in
early 2000.
The Company plans to increase its capital spending in 2000 from the $428
million spent in 1999 to approximately $650 million for exploration and
development projects. The Company plans an additional $100 million for select
property acquisitions. The capital program will be funded through cash provided
by operations. Almost 83 percent of the capital budget will be focused on the
development of fields which have already been proved and which are expected to
provide more immediate cash flow with low risk. The remainder of the Company's
budget will be for select exploration projects and other development drilling
that has the potential for long-term impact. Both the development and
exploration programs will employ the Company's ongoing strategy of applying its
expertise in advanced drilling and completion technologies. Approximately 38
percent of the capital budget will be invested in U.S. Onshore, 29 percent in
Canada, 14 percent in U.S. Offshore and 19 percent in Other International. The
Company may adjust its capital spending as commodity prices and cash flows
change. The extent and timing of capital spending may also be affected by
changes in business, financial and operating conditions as well as by the timing
and availability of suitable investment opportunities. See "Outlook and Other
Matters."
In U.S. Onshore, the Company plans to drill delineation wells in the
Etouffee discovery area in South Louisiana and a well in its Turtle Soup
prospect near the Etouffee discovery. Using its horizontal drilling expertise,
the Company plans to expand its success in the Frontier area of the Green River
Basin in the Land Grant. After its success in 1999 with the Rock Island 4H, the
Company made plans to drill four additional wells in the deep over-pressured
Frontier formation to further understand the formation's potential. These wells
include the Table Rock 115H, Sage Flat Unit 7H, Sidewinder 1H and Sidewinder 2H.
Although several of the wells drilled in early 2000 near the Rock Island 4H were
not successful, the formation's resources are large so the Company will continue
to test the Frontier formation during 2000 to further understand its potential.
In the U.S. Offshore, the Company plans to drill an exploration well at Garden
Banks Block 700 and a Green Canyon Block 281 exploration well. Additionally, the
Company plans to drill another well during 2000
28
<PAGE> 34
at its Gomez discovery. In Canada, the Company expects to start producing its
1999 Klua discovery well and is set to spud an adjacent well in the northeast
British Columbia territory. An exploratory well at the Sullivan Creek prospect
in southwestern Alberta is also planned during the second half of 2000. The
Company is continuing its Canadian heavy oil drilling program which began in the
fourth quarter 1999. In Guatemala, the Company plans to drill step-out wells in
the Xan area in addition to a high potential impact exploratory well at the
Libertad prospect in 2000. The Company plans to increase its spending and
drilling activity in Venezuela by drilling 24 wells in the Oritupano-Leona
concession area and increase its facility capacity.
The Company expects to continue to improve its balance sheet by reducing
debt by at least $200 million in 2000. The Company expects its cash from
operations to be approximately $1 billion for 2000, assuming a NYMEX price
forecast of $26 per barrel for crude oil and $2.70 per Mcf for natural gas. To
the extent that cash from operations is generated in excess of this forecast or
due to proceeds from the monetization of its minerals business or the sales of
assets, the additional cash could be used to further reduce debt and/or initiate
a common stock repurchase program if approved by the Board of Directors. The
Company expects to experience lower interest expense in its Consolidated
Statement of Income in future years as a result of its debt reduction program.
The Company will continue to focus on maximizing shareholder value during
2000 through debt reduction. In response to industry and market changes,
including industry consolidation, the Company considers from time to time
additional strategies to enhance shareholder value in light of such changes.
These include, among others, strategic alliances and joint ventures; spin-offs;
purchase, sale or merger transactions with other large companies; a
recapitalization of the Company and other similar transactions. In considering
any of these strategies, the Company evaluates the consequences of such
strategies including, among other things, the leverage that would result from
such a transaction, the tax effects of the transaction, and the accounting
consequences of the transaction. In addition, such strategies could have various
other significant consequences, including changes in the management, control or
operational or acquisition strategies of the Company. There can be no assurance
that any one of these strategies will be undertaken, or that, if undertaken, any
such strategy will be completed successfully.
Although the Company's deleveraging program was completed during 1999, the
Company will continue to evaluate its asset portfolio and may from time to time
sell, purchase or trade certain oil and gas properties to focus on its core
operating areas and generate additional value. Additionally, the potential
exists for gains to be recognized during 2000 related to properties sold in
1999. As some of the major oil and gas industry companies merge, the Company
expects some of these companies to divest properties in the Company's core
operating areas where it has expertise. The Company hopes to position itself to
enable it to purchase some of these properties. The Company is seeking to reduce
its capital exposure in the Gomez project by selling or transferring a portion
of its working interest. The Company is also planning to sell about $100 million
of Canadian assets, certain properties in south Louisiana and its properties in
Argentina.
The Company owns a non-operating 50 percent interest in Black Butte, a
partnership which operates a surface coal mine complex in southwestern Wyoming.
During 1999, Black Butte's sales to its largest customer under a coal supply
contract contributed $73.4 million to consolidated operating income. This
contract will terminate at the end of 2000. Operating income under the contract
is expected to be approximately $71.1 million in 2000. Although Black Butte
continues to seek new buyers for its low-sulfur coal, its mining costs are
considerably higher than the mining costs of its competition. The Company does
not expect to be able to replace the operating income it currently receives
under the contract with incremental coal sales after 2000.
During 1998 and 1999, the Company reported tax benefits due to operating
losses and tax settlements with governmental agencies and UPC. Additionally,
during the fourth quarter 1999, the Company implemented certain available tax
management strategies that caused a decrease in current tax liability for 1999.
The Company cannot predict with certainty when the tax will be paid.
In connection with the GPM Disposition, the Company entered into a
long-term sales agreement with Duke. The long-term sales agreement obligates the
Company to sell the majority of its domestic natural gas and existing NGL
production to Duke through March 2004. Natural gas volumes dedicated to the
agreement
29
<PAGE> 35
include existing and future production that is available at specific delivery
points identified in the agreement. Prices received for the natural gas and NGL
production will be tied to current market prices. Additionally, as a result of
the agreement, the Company and Duke agreed to keep one another whole on certain
gas transportation contracts for up to ten years. The Company will pay Duke if
transportation market values fall below the contract transportation rates, while
Duke will pay the Company if the market value exceeds the contract
transportation rates. The Company established a liability based on the estimated
fair value of these firm transportation contracts. The balance of the firm
transportation liability at December 31, 1999 was $125.6 million and was
included in other current and long-term liabilities on the Consolidated
Statement of Financial Position. The Company anticipates payments for the firm
transportation liability to be approximately $43.8 million during 2000.
The Company, through one of its affiliates, is a party to a lease agreement
("base lease") for the leveraged lease financing of the Corpus Christi West
Plant Refinery ("West Plant") with an initial term expiring December 31, 2003,
and successive renewal periods lasting through January 31, 2011. At the
conclusion of the initial term of the base lease, any renewal period or January
31, 2011, the Company has the right to purchase the West Plant at the fair
market sales value. In connection with the sale by the Company of its refining
business in 1987 and 1989, the West Plant was subleased to CITGO Petroleum
Corporation ("CITGO") with sublease payments during the initial term equal to
the Company's base lease payments and during any renewal period equal to the
lesser of the base lease rental, which will be tied to the fair market rental
value, or $5 million annually. Additionally, CITGO has the option under the
sublease to purchase the West Plant from the Company at the conclusion of the
initial term or any renewal term at the fair market sales value, or on January
31, 2011 at a nominal price. If the fair market rental value of the base lease
during any renewal term exceeds CITGO's maximum obligation under the sublease,
or if CITGO purchases the West Plant on January 31, 2011 and the fair market
sales value of the West Plant is greater than the purchase amount specified in
the sublease, the Company will be obligated to pay the excess amounts. The
Company is unable at this time to determine the fair market rental value or the
fair market sales value of the West Plant, but will periodically evaluate the
potential of the obligation.
The financial statements of the Company's Canadian subsidiary use the
Canadian dollar as its functional currency. Latin American subsidiaries
generally use the U.S. dollar as their functional currency. To the extent that
business transactions in these countries are not denominated in the functional
currency, the Company is exposed to foreign currency exchange rate risk. In
addition, in these subsidiaries, certain asset and liability balances are
denominated in currencies other than the subsidiary's functional currency. These
asset and liability balances must be remeasured in the preparation of the
subsidiary financial statements using a combination of current and historical
exchange rates, with any resulting remeasurement adjustments included in net
income. See "Item 7A. Qualitative and Quantitative Disclosure About Market
Risk -- Foreign Currency Risk".
YEAR 2000 ISSUE
The Company established a formal Year 2000 Readiness Program to address the
Company's issues related to the Year 2000. Program activities are directed by a
Program Management Office staffed with a Year 2000 Program Manager, several
senior Information Technology and engineering project managers and
representatives from key internal functions including exploration and
production, operations, purchasing, finance and legal. The Program Management
Office operated under the oversight of a Year 2000 Executive Steering Committee
and the Audit Committee of the Board of Directors.
As of February 29, 2000, the Company has not experienced any material
system issues from Year 2000 causes. Furthermore, there has been no indication
of third party Year 2000 issues that would materially affect the ongoing
operation or financial performance of the Company. Based on the evidence
available through February 29, 2000, the Company believes that any consequences
of Year 2000 issues will not have a material impact on the Company's
consolidated results of operations, cash flows or financial condition.
The total cost of the Company's Year 2000 Readiness Program was not
material to the Company's results of operations, cash flows or financial
position. Not including the cost of replacing its information systems
30
<PAGE> 36
between 1993 and 1997, the Company spent a total of $2.1 million during 1998 and
1999 for Year 2000 related modifications and testing. This estimate does not
include the cost of internal salaries for personnel involved with Year 2000
related activities. This estimate also does not include the Company's potential
share of Year 2000 costs that may be incurred by partnerships and joint ventures
in which the Company participates but is not the operator.
ENVIRONMENTAL COSTS
The Company has generated and disposed of hazardous and nonhazardous waste
in its current operations as well as its formerly owned operations and is
subject to increasingly stringent Federal, state, local, provincial and
international environmental regulations. The Company has identified seven sites
currently subject to environmental response actions or on the Superfund National
Priorities List or state superfund lists at which it is or may be liable for
remediation costs associated with alleged contamination or for violations of
environmental requirements. Certain Federal legislation imposes joint and
several liability for the remediation of various sites; consequently, the
Company's ultimate environmental liability may include costs relating to other
parties in addition to costs relating to its own activities at each site. In
addition, the Company is or may be liable for certain environmental remediation
matters involving existing or former facilities.
As of December 31, 1999, long-term and short-term liabilities totaling
$65.2 million had been accrued for future costs relating to all sites where the
Company's obligation is probable and where such costs can be reasonably
estimated; however, the ultimate cost could be lower or higher. This accrual
includes future costs for remediation and restoration of sites, as well as for
ongoing monitoring costs, but excludes any anticipated recoveries from third
parties. The accrual also includes $34.1 million for the obligation to
participate in the remediation of the Wilmington, California field properties.
Cost estimates were based on information available for each site, financial
viability of other Potentially Responsible Parties ("PRPs") and existing
technology, laws and regulations. The Company believes that it has accrued
adequately for its share of costs at sites subject to joint and several
liabilities. The ultimate liability for remediation is difficult to determine
with certainty because of the number of PRPs involved, site-specific cost
sharing arrangements with other PRPs, the degree of contamination by various
wastes, the scarcity and quality of volumetric data related to many of the sites
and the speculative nature of remediation costs.
The Company also is involved in reducing emissions, spills and migration of
hazardous materials. Remediation of identified sites and control and prevention
of environmental exposures required spending $11.6 million in 1999 and $17.0
million in 1998. In 2000, the Company anticipates spending a total of $19
million for remediation, control and prevention. Anticipated payments for
accrued environmental liability as of December 31, 1999, which will be funded by
cash generated from operations, are expected to be $17 million in 2000, $13.2
million in 2001, $12.5 million in 2002, $10 million in 2003, $8 million in 2004
and $4.5 million thereafter. Based on current rules and regulations, management
does not expect future environmental obligations to have a material impact on
the results of operations, financial condition or cash flows of the Company.
FORWARD-LOOKING INFORMATION
Certain information included in this report, and other materials filed or
to be filed by the Company with the SEC (as well as information included in oral
statements or other written statements made or to be made by the Company)
contain projections and forward-looking statements within the meaning of Section
21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the
Securities Act of 1933, as amended. Such forward-looking statements may be or
may concern, among other things, capital expenditures, drilling activity,
acquisitions and development activities, cost savings efforts, production
activities and sales volumes, oil, gas and NGL reserves and prices, hedging
activities and the results thereof, liquidity, debt repayment, regulatory
matters and competition. Such forward-looking statements generally are
accompanied by words such as "estimate," "expect," "predict," "anticipate,"
"goal," "should," "could," "assume," "believe" or other words that convey the
uncertainty of future events or outcomes.
31
<PAGE> 37
Such forward-looking information is based upon management's current plans,
expectations, estimates and assumptions and is subject to a number of risks and
uncertainties that could significantly affect current plans, anticipated
actions, the timing of such actions and the Company's financial condition, cash
flows and results of operations. As a consequence, actual results may differ
materially from expectations, estimates or assumptions expressed in or implied
by any forward-looking statements made by or on behalf of the Company. The risks
and uncertainties include generally the volatility of crude oil, natural gas and
hydrocarbon-based financial derivative prices; basis risk and counterparty
credit risk in executing hydrocarbon price risk management activities; economic,
political, judicial and regulatory developments; competition in the oil and gas
industry as well as competition from other sources of energy; the economics of
producing certain reserves; the oil and gas industry's consolidation activity;
demand and supply of oil and gas; the ability to find or acquire and develop
reserves of natural gas and crude oil; and the actions of customers and
competitors. Additionally, unpredictable or unknown factors not discussed herein
could have material adverse effects on actual results related to matters which
are the subject of forward-looking information.
With respect to expected capital expenditures and drilling activity,
additional factors such as crude oil and natural gas prices and the ability to
achieve debt repayment objectives, the extent of the Company's success in
acquiring oil and gas properties and in identifying prospects for drilling, the
availability of acquisition opportunities which meet the Company's objectives as
well as competition for such opportunities, exploration and operating risks, the
success of management's cost reduction efforts, the ability to find working
interest partners to share certain capital risks and the availability of
technology may affect the amount and timing of such capital expenditures and
drilling activity. With respect to expected growth in production and sales
volumes and estimated reserve quantities, factors such as the extent of the
Company's success in finding, developing and producing reserves, the timing of
capital spending, uncertainties inherent in estimating reserve quantities and
the availability of technology may affect such production sales volumes and
reserve estimates.
With respect to liquidity, factors such as the state of domestic capital
markets, credit availability from banks or other lenders and the Company's
results of operations may affect management's plans or ability to incur
additional indebtedness. With respect to cash flow and the ability to reduce
debt or to repurchase the Company's common stock, factors such as changes in
crude oil and natural gas prices, the Company's success in acquiring properties
or divesting or monetizing properties, environmental matters and other
contingencies, hedging activities and the Company's credit rating and debt
levels may affect the Company's ability to generate expected cash flows. With
respect to contingencies, factors such as changes in environmental and other
domestic and foreign governmental regulation, and uncertainties with respect to
legal matters may affect the Company's expectations regarding the potential
impact of contingencies on the operating results, cash flows or financial
condition of the Company. Certain factors, such as changes in crude oil and
natural gas prices and underlying demand and the extent of the Company's success
in exploiting its current reserves and acquiring or finding additional reserves
may have pervasive effects on many aspects of the Company's business in addition
to those outlined above.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET RISK
The Company has established policies and procedures for managing risk
within its organization, including internal controls and governance by a risk
management committee. The level of risk assumed by the Company is based on its
objectives and earnings, and its capacity to manage risk. Limits are established
for each major category of risk, with exposures monitored and managed by Company
management and reviewed by the risk management committee.
The Company's primary risk exposure is related to natural gas firm
transportation and commodity price risk. During 1999, while hydrocarbon prices
were near historic lows and the Company's debt balance was high, the Company
entered into hedging arrangements. These hedges were primarily solvency driven
in order to shield the Company from losses which may have resulted in a
violation of certain debt covenants. As prices recovered in the second half of
1999, the Company experienced higher prices and revenue at the well-head;
however, the higher well-head revenue was partially lowered by the $178.1
million in losses associated with the hedge positions that were entered into in
early 1999. The lower priced hedges expired at the end of 1999. For 2000, the
Company has reduced some of its exposure to lower prices by purchasing puts and
fixed price
32
<PAGE> 38
contracts and has limited some of the upside of higher prices by selling calls
and fixed price contracts. In early 2000, the Company hedged slightly more than
one-half of its estimated 2000 production with a combination of the fixed price
and option hedging strategies.
Below is a more comprehensive and quantitative disclosure of the Company's
market risks.
NON-TRADING ACTIVITIES
Commodity Price Risk. The Company uses derivative financial instruments for
non-trading purposes in the normal course of business to manage and reduce risks
associated with price volatility, contractual commitments and other market
variables. The Company's hedging approach is designed to respond to changing
market conditions where practicable, while at the same time permitting the
evaluation of the need to protect against significant commodity price
reductions. These financial instruments usually limit future gains from
favorable price movements. The volume of production hedged and the mix of
derivative instruments employed are regularly evaluated and adjusted in response
to changing market conditions and Company objectives.
Recognition of realized gains/losses and option premium payments/receipts
related to non-trading activities is deferred in the Consolidated Statement of
Income until the underlying physical product is sold. Unrealized gains/losses
are not recorded. Margin deposits, deferred gains/losses and net premiums are
included in other current assets or liabilities in the Consolidated Statement of
Financial Position. The cash flow impact is reflected in cash flows provided by
operations in the Consolidated Statement of Cash Flows.
Utilization of the Company's hedging program may result in the realization
on the crude oil and natural gas prices varying from market prices that the
Company receives from the sales of crude oil and natural gas. As a result of the
hedging programs, revenues in 1999, 1998 and 1997 were $178.1 million, $9
million and $86 million lower, respectively, than if the hedging program had not
been in effect. Since these transactions were hedges on production, these
impacts were also reflected in the average sales price of the associated
products. At December 31, 1999, the Company had margin deposits of $7.4 million
and a $26.6 million liability related to recorded hedging losses.
The following table summarizes the Company's open positions as of December
31, 1999 related to equity natural gas and crude oil production. Based on these
hedge positions, for each $1.00 increase in the price of a barrel of oil,
annualized oil revenues would be reduced by approximately $24.5 million, while
for every $0.10 per Mcf increase in the price of natural gas, annualized gas
revenues would be lower by approximately $23.1 million.
<TABLE>
<CAPTION>
WEIGHTED UNRECOGNIZED
CONTRACT AVG. PRICE PER FAIR VALUE GAIN/(LOSS)
PRODUCT TYPE TIME PERIOD VOLUME MCF OR BBL (MILLIONS OF DOLLARS) (MILLIONS OF DOLLARS)
- ------- -------------- --------------- ---------- -------------- --------------------- ---------------------
<S> <C> <C> <C> <C> <C> <C>
Gas Puts Purchased Feb -- Mar 2000 298 MMcfd $ 2.50 $ 5.8 $ 5.8
Gas Calls Sold Feb -- Mar 2000 298 MMcfd 3.11 (0.3) (0.3)
Gas Puts Purchased Apr -- Jul 2000 403 MMcfd 2.32 9.1 9.1
Gas Calls Sold Apr -- Jul 2000 403 MMcfd 2.72 (3.2) (3.2)
Gas Puts Purchased Aug -- Sep 2000 503 MMcfd 2.30 5.3 5.3
Gas Calls Sold Aug -- Sep 2000 503 MMcfd 2.69 (3.3) (3.3)
Gas Puts Purchased Oct -- 2000 253 MMcfd 2.35 1.7 1.7
Gas Calls Sold Oct -- 2000 253 MMcfd 2.72 (0.9) (0.9)
Gas Swaps Feb -- Mar 2000 290 MMcfd Var. (1.3) (1.3)
Gas Swaps Apr -- Oct 2000 175 MMcfd Var. (0.2) (0.2)
Gas Futures Feb -- Jul 2000 370 MMcfd 2.43 5.6 5.6
Gas Futures Aug -- Dec 2000 170 MMcfd 2.44 (1.6) (1.6)
Gas Fixed Price Jan -- Oct 2000 10 MMcfd 2.80 2.2 2.2
Gas Fixed Price Jan -- Dec 2000 10 MMcfd 1.54 (2.1) (2.1)
Gas Fixed Price Jan -- Oct 2001 10 MMcfd 1.54 (1.8) (1.8)
Gas Physical Calls Apr -- Oct 2000 10 MMcfd 2.17 (0.1) 0.2
Sold
Oil Puts Purchased Jan -- Dec 2000 34.5 Mbd 17.29 6.3 6.3
Oil Calls Sold Jan -- Dec 2000 34.5 Mbd 21.77 (29.2) (29.2)
</TABLE>
33
<PAGE> 39
<TABLE>
<CAPTION>
WEIGHTED UNRECOGNIZED
CONTRACT AVG. PRICE PER FAIR VALUE GAIN/(LOSS)
PRODUCT TYPE TIME PERIOD VOLUME MCF OR BBL (MILLIONS OF DOLLARS) (MILLIONS OF DOLLARS)
- ------- -------------- --------------- ---------- -------------- --------------------- ---------------------
<S> <C> <C> <C> <C> <C> <C>
Oil Swaps Jan 2000 26.4 Mbd 23.02 (1.9) (1.9)
Oil Swaps Feb -- Aug 2000 35 Mbd 20.31 (17.4) (17.4)
Oil Swaps Sep -- Dec 2000 30 Mbd 20.38 (0.6) (0.6)
Oil Swaps Jan -- Dec 2000 2 Mbd 17.35 (0.1) (0.1)
Oil Fixed Price Jan -- Feb 2000 2 Mbd 22.47 0.2 0.2
Oil Fixed Price Jan -- Oct 2000 2 Mbd 16.94 (0.1) (0.1)
Oil Fixed Price Jan -- Apr 2000 8 Mbd 20.89 1.5 1.5
Oil Fixed Price Jan -- Dec 2000 2 Mbd 18.30 0.4 0.4
------ ------
Totals: ($26.0) ($25.7)
====== ======
</TABLE>
Unrecognized mark-to-market gains and losses were determined based on
current market prices at December 30, 1999, as quoted by recognized dealers,
assuming round lot transactions and using a mid-market convention without regard
to market liquidity. The actual gains or losses ultimately realized by the
Company from such hedges may vary significantly from the foregoing amounts due
to the volatility of the commodity markets.
The following table summarizes the Company's closed positions at December
31, 1999 related to the Company's equity natural gas production:
<TABLE>
<CAPTION>
UNRECOGNIZED
GAIN/(LOSS)
PRODUCT TYPE TIME PERIOD (MILLIONS OF DOLLARS)
- ------- ------------- ---------------- ---------------------
<S> <C> <C> <C>
Gas Options Jan 2000 $2.5
Gas Futures/Swaps Jan 2000 2.3
----
Totals: $4.8
====
</TABLE>
The Company enters into financial contracts in conjunction with its
alliance with South Jersey Resources Group (the "Alliance"). The Company has a
50% ownership interest in the Alliance which provides natural gas storage and
customer service programs. The following table summarizes the Alliance's open
positions as of December 31, 1999:
<TABLE>
<CAPTION>
WEIGHTED AVG.
CONTRACT PRICE FAIR VALUE
PRODUCT TYPE TIME PERIOD VOLUME PER MCF (MILLIONS OF DOLLARS)
- ------- ----------------------- --------------- -------- ------------- ---------------------
<S> <C> <C> <C> <C> <C>
Gas Puts Purchased Feb -- Mar 2000 0.3 Bcf $ 2.88 $ 0.2
Gas Puts Sold Feb -- Mar 2000 0.9 Bcf 2.29 (0.1)
Calls Sold Feb -- June 0.9 Bcf 2.79 (0.1)
Gas 2000
Gas Futures/Swaps Purchased Feb -- Dec 2000 17.5 Bcf 2.78 (4.4)
Gas Futures/Swaps Purchased Jan -- Oct 2001 1.1 Bcf 3.37 --
Gas Futures/Swaps Purchased Feb -- Dec 2000 10.9 Bcf 2.79 2.6
Gas Futures/Swaps Purchased Jan -- Apr 2001 0.6 Bcf 2.48 --
-----
Totals: $(1.8)
=====
<CAPTION>
UNRECOGNIZED
GAIN/(LOSS)
PRODUCT (MILLIONS OF DOLLARS)
- ------- ---------------------
<S> <C>
Gas $ 0.2
Gas --
--
Gas
Gas (4.4)
Gas --
Gas 2.6
Gas --
-----
$(1.6)
=====
</TABLE>
Firm Transportation Price Risk. The Company was a party to several
long-term firm gas transportation agreements that supported the gas marketing
program within the GPM business segment which was sold to Duke. Most of the GPM
business segment's firm long-term transportation contracts were transferred to
Duke in the GPM Disposition. As part of the GPM Disposition, the Company and
Duke agreed that the Company will keep Duke whole on certain transportation
contracts ("keep-whole agreement"). The Company will pay Duke if transportation
market values fall below the contract transportation rates, while Duke agreed to
pay the Company if the market value exceeds the contract transportation rates.
This keep-whole agreement will be in effect until the earlier of (i) each
contract's expiration date, or (ii) March 2009. Transportation contracts
transferred to Duke in the GPM Disposition and included in the keep-whole
agreement with Duke relate to various pipelines. The significant contracts
covered by the keep-whole agreement include: (i) an agreement with Texas Gas
Transmission Corporation for a transportation rate of $0.331 per MMBtu for 90
MMBtud of
34
<PAGE> 40
gas from Carthage, Texas to Lebanon, Ohio expiring October 31, 2008; (ii) an
agreement with Pacific Gas Transmission ("PGT") for a transportation rate of
$0.328 per MMBtu for 25 MMBtud of gas from Kingsgate, British Columbia to the
California/Oregon border expiring October 31, 2023; and (iii) a second agreement
with PGT expiring October 31, 2023 for 106 MMBtud of which 47 MMBtud will expire
on October 31, 2007. The keep-whole agreement excludes 45 MMBtud of the PGT
amount through October 31, 2002 then 20 MMBtud through the end of the contract.
The Company retained a contract with Kern River Gas Transportation Company
("Kern River") which expires on May 31, 2007. Under the transportation
agreement, the Company has the right to transport 75 MMcfd of gas on the Kern
River system. The current transportation rate is $0.69 per Mcf. This rate can
change based on Kern River's cost of service and upon rate regulation policies
of the FERC. The Company is a party to an additional agreement under which it
may acquire in 2001, at its option, an additional 25 MMcfd of transportation
rights on the Kern River system beginning in 2002. As a result of the GPM
Disposition, the Company entered into an agreement whereby Duke would operate
and handle volume nominations related to the Company's contract with Kern River.
Currently, Duke is utilizing the Company's volume transportation rights under
the Kern River contract and paying the Company market rates.
The estimated fair value of the firm transportation contracts at December
31, 1999 was a loss of $125.6 million, which is included in other current
liabilities and other long-term liabilities on the Consolidated Statement of
Financial Position. The Company may adjust its reserve based on changes in
current quoted future market rates or estimated long-term rates. Such
adjustments could be significant. Management believes its reserves are adequate;
however, at December 31, 1999, if the Company had used quoted future market
rates at December 31, 1999 to estimate the long-term portion of the reserve
discounted at 10%, the Company would have recorded an additional reserve of
$41.3 million for the firm transportation commitment period. The estimated fair
value of the firm transportation liability is summarized as follows:
<TABLE>
<CAPTION>
YEAR UNDISCOUNTED DISCOUNTED
- ---- ------------ ----------
(MILLIONS OF DOLLARS)
<S> <C> <C>
2000........................................................ $ 43.8 $ 43.8
2001........................................................ 17.0 14.8
2002........................................................ 15.6 12.3
2003........................................................ 17.8 12.8
2004........................................................ 24.4 15.9
Thereafter.................................................. 50.0 26.0
------ ------
Total............................................. $168.6 $125.6
====== ======
</TABLE>
TRADING ACTIVITIES
The Company periodically enters into financial contracts in conjunction
with market-making or trading activities with the objective of achieving profits
through successful anticipation of movements in commodity prices and changes in
other market variables. Market-making positions are marked-to-market and gains
and losses are immediately included as revenue in the Consolidated Statement of
Income. In addition, the fair value of unsettled positions is immediately
included in the Consolidated Statement of Financial Position as a current asset
or current liability. The activity related to market-making or trading
activities did not have a significant effect on the Company's results of
operations for the year ended December 31, 1999. At December 31, 1999, the
Company's trading activity position did not have a material impact on the
results of operations or financial condition of the Company.
INTEREST RATE RISK AND INTEREST RATE SWAPS
The table below summarizes maturities for the Company's fixed-rate and
variable-rate debt. Variable rate debt consists of commercial paper and bankers'
acceptances that are generally tied to the London Interbank
35
<PAGE> 41
Offered Rate ("LIBOR"). If interest rates on the Company's variable rate debt
increase or decrease by one percentage point, the Company's annual pretax income
would decrease or increase by $1.4 million.
<TABLE>
<CAPTION>
MATURITY DATE
-------------------------------------------------
2000 2001 2002 2003 2004 THEREAFTER
------ ---- ------ ---- ---- ----------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C> <C> <C>
Variable-Rate................................. $135.1 $ -- $ -- $ -- $ -- $ --
Fixed-Rate.................................... 2.3 2.2 252.3 2.4 6.2 2,399.1
------ ---- ------ ---- ---- --------
Total............................... $137.4 $2.2 $252.3 $2.4 $6.2 $2,399.1
====== ==== ====== ==== ==== ========
</TABLE>
The Company periodically enters into rate swaps and contracts to hedge
certain interest rate transactions. As of December 31, 1999, the Company had no
interest rate swap positions open.
CREDIT RISK
Credit risk is the risk of loss as a result of non-performance by
counterparties of their contractual obligations. Because the loss can occur at
some point in the future, a potential exposure is added to the current
replacement value to arrive at a total expected credit exposure. The Company has
established methodologies to determine limits, monitor and report
creditworthiness and concentrations of credit to reduce such credit risk. At
December 31, 1999, the Company's largest credit risk associated with any single
financial counterparty, represented by the net fair value of open contracts, was
$7.1 million discounted.
In conjunction with the GPM Disposition, on March 31, 1999, the Company
entered into a swap transaction with Duke, which in effect transferred all
financial positions held by the GPM business segment to Duke. As a result, the
Company has eliminated all price/rate risk related to these positions and is
only subject to credit risk for amounts due from Duke or other counterparties
under the terms of the swap transactions with Duke or the underlying swap
transactions. At December 31, 1999, the Company's credit risk related to these
positions was immaterial.
Also in connection with the GPM Disposition, the Company entered into a
long-term sales agreement with Duke. The long-term sales agreement obligates the
Company to sell the majority of its domestic natural gas and existing NGL
production to Duke through March 2004. Prices received will be tied to the
current market price for each product. As a result, a significant portion of the
Company's credit risk will be with a single customer. Duke is currently
considered a good credit risk; however, periodic credit evaluations will
continue and be performed more often if circumstances dictate. The agreement
with Duke provides for a parental guaranty to cover its obligations under the
agreements and the Company has the right to demand a letter of credit and/or
other assurances under certain circumstances.
PERFORMANCE RISK
Performance risk results when a financial counterparty fails to fulfill its
contractual obligations such as commodity pricing or volume commitments.
Typically, such risk obligations are defined within the trading agreements. The
Company utilizes its credit risk methodology to manage performance risk.
FOREIGN OPERATIONS RISK
The Company's operations outside of the U.S. are subject to risks inherent
in foreign operations, including, without limitation, the loss of revenue,
property and equipment from hazards such as expropriation, nationalization, war,
insurrection and other political risks, increases in taxes and governmental
royalties, renegotiation of contracts with governmental entities, changes in
laws and policies governing operations of foreign-based companies, currency
restrictions and exchange rate fluctuations and other uncertainties arising out
of foreign government sovereignty over the Company's international operations.
Laws and policies of the U.S. affecting foreign trade and taxation may also
adversely affect the Company's international operations.
36
<PAGE> 42
FOREIGN CURRENCY RISK
The Company's Canadian subsidiary uses the Canadian dollar as its
functional currency, and the Latin American subsidiaries use the U.S. dollar as
their functional currency. To the extent that business transactions in these
countries are not denominated in the respective country's functional currency,
the Company is exposed to foreign currency exchange rate risk. In addition, in
these subsidiaries, certain asset and liability balances are denominated in
currencies other than the subsidiary's functional currency. These asset and
liability balances must be remeasured in the preparation of the subsidiary's
financial statements using a combination of current and historical exchange
rates, with any resulting remeasurement adjustments included in net income.
At December 31, 1999, the Company's Canadian subsidiary had outstanding
$650 million of fixed-rate notes and debentures denominated in U.S. dollars.
During 1999, the Company recognized a $38.0 million pretax non-cash gain
associated with remeasurement of this debt. The potential foreign currency
remeasurement impact on earnings from a five-percent change in the year-end
Canadian exchange rate would be approximately $32 million.
At December 31, 1999, Latin American subsidiaries had foreign deferred tax
liabilities denominated in the local currency, equivalent to $131.6 million in
Venezuela and $34.1 million in Guatemala. During 1999, the Company recognized
deferred tax benefits of $20.4 million and $8.9 million after tax, respectively,
associated with remeasurement of the Venezuelan and Guatemalan deferred tax
liabilities. The potential foreign currency remeasurement impact on net earnings
from a five percent change in the year-end Latin American exchange rates would
be approximately $9 million.
The Company periodically enters into foreign currency contracts to hedge
specific currency exposures from commercial transactions. The following table
summarizes the Company's open foreign currency positions at December 31, 1999:
<TABLE>
<CAPTION>
NOTIONAL AMOUNT FAIR VALUE
MATURITY YEAR (US$ MILLIONS) FORWARD RATE (US$ MILLIONS)
- ------------- --------------- ------------ --------------
<S> <C> <C> <C>
2000....................................... $ 8.0 C$1.3750 $(0.4)
2004....................................... 70.0 C$1.3630 (3.9)
----- -----
$78.0 $(4.3)
===== =====
</TABLE>
37
<PAGE> 43
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Responsibilities for Financial Statements................... 39
Reports of Independent Public Accountants................... 40
Consolidated Statements of Income and Comprehensive Income
for the Years Ended December 31, 1999, 1998 and 1997...... 42
Consolidated Statements of Financial Position as of December
31, 1999 and 1998......................................... 43
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1999, 1998 and 1997.......................... 44
Consolidated Statements of Changes in Shareholders' Equity
for the Years Ended December 31, 1999, 1998 and 1997...... 45
Business Segment Information as of and for the Years Ended
December 31, 1999, 1998 and 1997.......................... 46
Notes to Consolidated Financial Statements.................. 47
Supplementary Information (Unaudited)....................... 74
</TABLE>
Black Butte Coal Company, A Joint Venture, and R-K Leasing Company Combined
Financial Statements as of December 31, 1999 and December 26, 1998,
(incorporated herein by reference to Exhibit 99.1 to the Company's Annual
Report on Form 10-K for the period ended December 31, 1999).
Black Butte Coal Company, A Joint Venture, and R-K Leasing Company Combined
Financial Statements as of December 27, 1997 (incorporated herein by reference
to Exhibit 99.2 to the Company's Annual Report on Form 10-K for the period
ended December 31, 1999).
38
<PAGE> 44
RESPONSIBILITIES FOR FINANCIAL STATEMENTS
The accompanying financial statements, which consolidate the accounts of
Union Pacific Resources Group Inc. and its subsidiaries, have been prepared in
conformity with generally accepted accounting principles.
The integrity and objectivity of data in these financial statements and
accompanying notes, including estimates and judgments related to matters not
concluded by year-end, are the responsibility of management, as is all other
information in this report. Management devotes ongoing attention to the review
and appraisal of its system of internal controls. This system is designed to
provide reasonable assurance, at an appropriate cost, that the Company's assets
are protected, that transactions and events are recorded properly and that
financial reports are reliable. The system is augmented by a staff of internal
auditors, careful attention to the selection and development of qualified
financial personnel, programs to further timely communication and monitoring of
policies, standards and delegated authorities and evaluation by independent
auditors during their examinations of the annual financial statements.
The Audit Committee of the Board of Directors, composed of four
non-employee directors, meets regularly with financial management, the internal
auditors and the independent auditors to review financial reporting and
accounting and financial controls of the Company. Both the independent auditors
and the internal auditors have unrestricted access to the Audit Committee and
meet regularly with the Audit Committee, without financial management
representatives present, to discuss the results of their examinations and their
opinions on the adequacy of internal controls and quality of financial
reporting.
George Lindahl III
Chairman, President and Chief
Executive Officer
Morris B. Smith
Vice President, Chief Financial
Officer
and Treasurer
39
<PAGE> 45
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors
Union Pacific Resources Group Inc.
Fort Worth, Texas
We have audited the accompanying consolidated statements of financial
position of Union Pacific Resources Group Inc. (a Utah Corporation) and
subsidiaries ("the Company") as of December 31, 1999 and 1998, and the related
consolidated statements of income and comprehensive income, changes in
shareholders' equity and cash flows for the years then ended. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of the Company as of December
31, 1999 and 1998, and the results of its operations and its cash flows for the
years then ended in conformity with accounting principles generally accepted in
the United States.
We have also audited the adjustments related to discontinued operations
described in Note 3 that were applied to restate the 1997 financial statements.
In our opinion, such adjustments are appropriate and have been properly applied.
ARTHUR ANDERSEN LLP
Fort Worth, Texas
March 3, 2000
40
<PAGE> 46
INDEPENDENT AUDITORS' REPORT
To the Board of Directors
Union Pacific Resources Group Inc.
Fort Worth, Texas
We have audited the accompanying consolidated statements of income, changes
in shareholders' equity and cash flows of Union Pacific Resources Group Inc.
("the Company") for the year ended December 31, 1997, (which have been restated
and are no longer presented herein). These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the results of its operations and its cash flows for the
year ended December 31, 1997 in conformity with generally accepted accounting
principles.
DELOITTE & TOUCHE LLP
Fort Worth, Texas
January 26, 1998
41
<PAGE> 47
UNION PACIFIC RESOURCES GROUP INC.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
<TABLE>
<CAPTION>
1999 1998 1997
---------- ----------- ----------
(MILLIONS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C>
Operating revenues:
Producing properties...................................... $1,473.3 $ 1,537.4 $1,293.5
Other oil and gas revenues................................ 133.7 162.5 84.7
Minerals (Note 14)........................................ 120.5 141.1 139.8
-------- --------- --------
Total operating revenues.......................... 1,727.5 1,841.0 1,518.0
-------- --------- --------
Operating expenses:
Production................................................ 400.6 444.3 300.8
Exploration............................................... 267.9 339.0 204.7
Minerals (Note 14)........................................ (2.8) 3.5 3.4
Depreciation, depletion and amortization (Note 6)......... 827.7 2,125.6 504.0
General and administrative................................ 86.9 104.8 71.2
Restructuring charge (Note 4)............................. 11.4 17.0 --
-------- --------- --------
Total operating expenses.......................... 1,591.7 3,034.2 1,084.1
-------- --------- --------
Operating income (loss)..................................... 135.8 (1,193.2) 433.9
Other income (expense) -- net (Note 16)..................... 31.7 (45.3) 24.5
Interest expense (Notes 3 and 9)............................ (218.7) (249.8) (39.5)
-------- --------- --------
Income (loss) from continuing operations before income
taxes..................................................... (51.2) (1,488.3) 418.9
Income tax expense (benefit) (Note 8)....................... (140.4) (605.2) 115.8
-------- --------- --------
Income (loss) from continuing operations, before
extraordinary items....................................... 89.2 (883.1) 303.1
Gain on sale of discontinued operations -- net of tax....... 157.0 -- --
Income (loss) from discontinued operations -- net of tax.... (23.8) (15.6) 29.9
-------- --------- --------
Income (loss) from discontinued operations (Note 3)......... 133.2 (15.6) 29.9
Extraordinary gain from early extinguishment of debt -- net
of tax (Note 9)........................................... 3.4 -- --
-------- --------- --------
Net income (loss)........................................... $ 225.8 $ (898.7) $ 333.0
-------- --------- --------
Comprehensive income -- net of tax: (Note 15)
Foreign currency translation adjustments.................. $ 22.5 $ (67.1) $ (5.3)
Minimum pension liability................................. (6.0) (3.9) (1.0)
-------- --------- --------
Comprehensive income (loss)................................. $ 242.3 $ (969.7) $ 326.7
======== ========= ========
Earnings (loss) per share -- basic and diluted: (Note 15)
Continuing operations..................................... $ 0.36 $ (3.57) $ 1.21
Discontinued operations................................... 0.54 (0.06) 0.12
Extraordinary item........................................ 0.01 -- --
-------- --------- --------
Total............................................. $ 0.91 $ (3.63) $ 1.33
-------- --------- --------
Weighted average shares outstanding -- diluted.............. 249.2 247.7 250.9
Cash dividends per share.................................... $ 0.20 $ 0.20 $ 0.20
</TABLE>
The accompanying accounting policies and notes to the Consolidated Financial
Statements
are an integral part of these statements.
42
<PAGE> 48
UNION PACIFIC RESOURCES GROUP INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
AS OF DECEMBER 31, 1999 AND 1998
ASSETS
<TABLE>
<CAPTION>
1999 1998
--------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Current assets:
Cash and temporary investments............................ $ 123.7 $ 8.8
Accounts receivable (net of allowance for doubtful
accounts of $8.5 million in 1999 and $9.8 million in
1998).................................................. 304.4 261.0
Inventories............................................... 54.7 64.6
Other current assets...................................... 13.1 107.0
--------- ---------
Total current assets.............................. 495.9 441.4
--------- ---------
Properties: (Note 6)
Cost...................................................... 11,006.6 11,078.2
Accumulated depreciation, depletion and amortization...... (5,535.6) (4,984.9)
--------- ---------
Total properties.................................. 5,471.0 6,093.3
Intangible and other assets................................. 180.0 180.8
Net assets of discontinued operations (Note 3).............. -- 926.9
--------- ---------
Total assets...................................... $ 6,146.9 $ 7,642.4
========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable.......................................... $ 285.0 $ 270.5
Accrued taxes payable..................................... 68.6 64.9
Short-term debt (Note 9).................................. 2.3 853.8
Other current liabilities (Note 14)....................... 185.8 157.5
--------- ---------
Total current liabilities......................... 541.7 1,346.7
--------- ---------
Long-term debt (Note 9)..................................... 2,797.3 3,744.9
Deferred income taxes (Note 8).............................. 1,326.8 1,291.6
Retiree benefits obligations (Note 11)...................... 142.5 142.9
Other long-term liabilities (Notes 12, 13 and 14)........... 401.1 388.1
Shareholders' equity (see page 45).......................... 937.5 728.2
--------- ---------
Total liabilities and shareholders' equity........ $ 6,146.9 $ 7,642.4
========= =========
</TABLE>
The accompanying accounting policies and notes to the Consolidated Financial
Statements are an integral part of these statements.
43
<PAGE> 49
UNION PACIFIC RESOURCES GROUP INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
<TABLE>
<CAPTION>
1999 1998 1997
--------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Cash provided by operations:
Net income................................................ $ 225.8 $ (898.7) $ 333.0
(Income) loss from discontinued operations (Note 3)..... (133.2) 15.6 (29.9)
Gain on extinguishment of debt -- net of tax............ (3.4) -- --
--------- --------- ---------
Income (loss) from continuing operations.................. 89.2 (883.1) 303.1
Non-cash charges to income:
Depreciation, depletion and amortization................ 827.7 2,125.6 504.0
Deferred income tax (benefit) (Note 8).................. 1.4 (659.3) 110.9
Surrendered lease amortization.......................... 172.5 185.9 85.6
(Gains) losses on sales of assets -- net................ (148.0) (139.9) (18.8)
Other non-cash charges (credits) -- net................. (86.2) 194.7 (96.2)
Exploratory expenditures.................................. 44.1 115.2 76.9
Changes in current assets and liabilities................. 94.8 92.0 (109.3)
--------- --------- ---------
Cash provided by operations........................ 995.5 1,031.1 856.2
--------- --------- ---------
Investing activities:
Capital and exploratory expenditures (Note 7)............. (428.2) (1,194.5) (1,188.4)
Acquisition of Norcen (Note 2)............................ -- (2,634.3) --
Proceeds from sale of discontinued operations (Note 3).... 1,359.1 -- --
Proceeds from sales of assets (Note 3).................... 281.3 436.6 37.3
Proceeds from sale of investments......................... -- 48.4 --
Cash provided (used) by discontinued operations........... (203.6) 50.4 (221.8)
Other investing activities -- net......................... -- -- (17.7)
--------- --------- ---------
Cash provided (used) by investing activities....... 1,008.6 (3,293.4) (1,390.6)
--------- --------- ---------
Financing activities:
Dividends paid............................................ (49.6) (49.6) (50.0)
Repayment of debt......................................... (2,295.5) -- --
Proceeds from long-term debt issuance (Note 9)............ 500.0 1,025.0 --
Other debt financing -- net............................... -- 1,294.5 559.6
Repurchase of common stock................................ (12.6) (26.7) (52.3)
Reissuance of treasury stock.............................. 3.3 -- --
Other financings -- net (Note 9).......................... (34.8) (39.2) 30.4
--------- --------- ---------
Cash provided (used) by financing activities....... (1,889.2) 2,204.0 487.7
--------- --------- ---------
Net change in cash and temporary investments................ 114.9 (58.3) (46.7)
Balance at beginning of year................................ 8.8 67.1 113.8
--------- --------- ---------
Balance at end of year...................................... $ 123.7 $ 8.8 $ 67.1
========= ========= =========
Changes in current assets and liabilities:
Accounts receivable....................................... $ (37.2) $ 215.8 $ (33.2)
Inventories............................................... 9.9 (17.8) (1.5)
Other current assets...................................... 98.3 3.2 21.6
Accounts payable.......................................... 40.8 (153.4) (21.4)
Accrued taxes payable..................................... (55.2) 3.5 (73.4)
Other current liabilities................................. 38.2 40.7 (1.4)
--------- --------- ---------
Total.............................................. $ 94.8 $ 92.0 $ (109.3)
========= ========= =========
Supplemental cash flow disclosure:
Interest paid:
Continuing operations................................... $ 227.5 $ 216.0 $ 42.7
Discontinued operations................................. 7.4 21.1 13.6
Income taxes paid (recovered):
Continuing operations................................... (95.5) 81.0 121.0
Discontinued operations................................. -- (35.0) 8.7
</TABLE>
The accompanying accounting policies and notes to the Consolidated
Financial Statements are an integral part of these statements.
44
<PAGE> 50
UNION PACIFIC RESOURCES GROUP INC.
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
<TABLE>
<CAPTION>
1999 1998 1997
------ ------- --------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Common stock, no par value; authorized 400,000,000 shares:
251,951,140 shares issued and outstanding at December 31,
1999
250,685,204 shares issued and outstanding at December 31,
1998
251,888,575 shares issued and outstanding at December 31,
1997
Balance at beginning and end of year...................... $ -- $ -- $ --
------ ------- --------
Paid-in surplus (Note 15):
Balance at beginning of year.............................. 992.6 991.2 872.9
Conversion, award, forfeiture and appreciation of
retention shares........................................ 13.6 0.5 5.1
Issuance of ESOP shares................................... -- -- 107.3
Release of ESOP shares.................................... (11.8) -- --
Exercise of stock options................................. 3.3 0.6 5.5
Other..................................................... 1.1 0.3 0.4
------ ------- --------
Balance at end of year.................................... 998.8 992.6 991.2
------ ------- --------
Retained earnings:
Balance at beginning of year.............................. 9.1 957.4 674.4
Net income (loss)......................................... 225.8 (898.7) 333.0
------ ------- --------
Total.............................................. 234.9 58.7 1,007.4
Dividends declared on common stock........................ (49.6) (49.6) (50.0)
------ ------- --------
Balance at end of year.................................... 185.3 9.1 957.4
------ ------- --------
Unearned compensation (Note 15):
Balance at beginning of year.............................. (6.0) (11.8) (17.5)
Conversion, award, forfeiture and amortization of
retention shares -- net................................. 3.5 5.8 5.7
------ ------- --------
Balance at end of year.................................... (2.5) (6.0) (11.8)
------ ------- --------
ESOP (Note 15):
Balance at beginning of year.............................. (95.7) (102.0) --
Issuance of ESOP shares................................... -- -- (107.3)
Release of ESOP shares.................................... 16.2 6.3 5.3
------ ------- --------
Balance at end of year............................. (79.5) (95.7) (102.0)
------ ------- --------
Treasury stock (Note 15):
Balance at beginning of year.............................. (82.5) (55.8) (3.5)
Treasury stock repurchased or reissued, at cost -- net.... (9.3) (26.7) (52.3)
------ ------- --------
Balance at end of year: 4,276,989 shares at December 31,
1999
3,666,913 shares at December 31,
1998
2,379,625 shares at December 31,
1997.............................. (91.8) (82.5) (55.8)
------ ------- --------
Comprehensive income:
Deferred foreign exchange adjustment (Note 15):
Balance at beginning of year............................ (84.4) (17.3) (12.0)
Foreign currency translation adjustment................. 22.5 (67.1) (5.3)
------ ------- --------
Balance at end of year.................................. (61.9) (84.4) (17.3)
------ ------- --------
Minimum pension liability (Note 11)
Balance at beginning of year............................ (4.9) (1.0) --
Minimum pension liability adjustment.................... (6.0) (3.9) (1.0)
------ ------- --------
Balance at end of year.................................. (10.9) (4.9) (1.0)
------ ------- --------
Total Comprehensive income......................... (72.8) (89.3) (18.3)
------ ------- --------
Total shareholders' equity......................... $937.5 $ 728.2 $1,760.7
====== ======= ========
</TABLE>
The accompanying accounting policies and notes to the Consolidated
Financial Statements are an integral part of these statements.
45
<PAGE> 51
UNION PACIFIC RESOURCES GROUP INC.
BUSINESS SEGMENT INFORMATION
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
<TABLE>
<CAPTION>
1999 1998 1997
-------- --------- --------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Revenues(a):
Exploration and production................................ $1,607.0 $ 1,699.9 $1,378.2
Minerals.................................................. 120.5 141.1 139.8
-------- --------- --------
Total revenues.................................... $1,727.5 $ 1,841.0 $1,518.0
======== ========= ========
Depreciation, depletion and amortization:
Exploration and production................................ $ 816.0 $ 2,115.8 $ 499.3
Minerals.................................................. 5.5 4.1 0.9
Corporate................................................. 6.2 5.7 3.8
-------- --------- --------
Total depreciation, depletion and amortization.... $ 827.7 $ 2,125.6 $ 504.0
======== ========= ========
Operating income (loss):
Exploration and production................................ $ 122.5 $(1,199.2) $ 373.4
Minerals.................................................. 117.8 133.5 135.5
Corporate(b).............................................. (104.5) (127.5) (75.0)
-------- --------- --------
Total operating income (loss)..................... $ 135.8 $(1,193.2) $ 433.9
======== ========= ========
Fixed assets -- net:
Exploration and production................................ $5,367.4 $ 5,988.8 $2,827.1
Minerals.................................................. 7.4 10.2 14.1
Corporate................................................. 96.2 94.3 59.9
-------- --------- --------
Total fixed assets -- net......................... $5,471.0 $ 6,093.3 $2,901.1
======== ========= ========
Capital and exploratory expenditures:
Exploration and Production................................ $ 423.1 $ 3,796.2 $1,172.6
Minerals.................................................. -- 0.1 1.4
Corporate................................................. 5.1 32.5 14.4
-------- --------- --------
Total capital and exploratory expenditures........ $ 428.2 $ 3,828.8 $1,188.4
======== ========= ========
</TABLE>
GEOGRAPHIC INFORMATION
<TABLE>
<CAPTION>
1999 1998 1997
-------- --------- --------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Revenues(a):
United States............................................. $1,182.9 $ 1,455.9 $1,477.2
Canada.................................................... 332.1 259.0 28.9
Other international....................................... 212.5 126.1 11.9
-------- --------- --------
Total revenues.................................... $1,727.5 $ 1,841.0 $1,518.0
======== ========= ========
Fixed assets -- net:
United States............................................. $2,389.6 $ 2,965.2 $2,800.9
Canada.................................................... 1,918.8 1,854.0 89.8
Other international....................................... 1,162.6 1,274.1 10.4
-------- --------- --------
Total fixed assets -- net......................... $5,471.0 $ 6,093.3 $2,901.1
======== ========= ========
</TABLE>
- ---------------
(a) 1999, 1998 and 1997 revenues include income from equity affiliates of $78.5
million, $89.7 million and $74.4 million, respectively for the Minerals
segment.
(b) Segment operating loss for the Corporate segment consists primarily of
general and administrative expense and restructuring charge.
The Company's reportable segments are strategic business units or an
aggregation of business units with similar operations and management objectives.
The reportable segments are managed separately because each segment requires
different operational assets, technology and management strategies.
This information should be read in conjunction with the accompanying
accounting policies and notes to the Consolidated Financial Statements.
46
<PAGE> 52
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation. The Consolidated Financial Statements include
the accounts of Union Pacific Resources Group Inc. (a Utah Corporation) and
subsidiaries (collectively, the "Company"), including its principal operating
subsidiary Union Pacific Resources Company ("UPRC"). The Company accounts for
investments in affiliated companies (20% to 50% owned) on the equity method of
accounting. The Company also consolidates its pro-rata share of oil and gas
joint ventures. All significant intercompany transactions are eliminated. The
Consolidated Financial Statements for previous periods include certain
reclassifications that were made to conform to the current presentation. Such
reclassifications have no effect on previously reported net income. Refer to the
accompanying notes to the financial statements for additional disclosure of the
Company's significant accounting policies.
As a result of the disposition of the Company's gathering, processing and
marketing ("GPM") business segment, the GPM business segment has been accounted
for as a discontinued operation. GPM results of operations have been excluded
from continuing operations in the Consolidated Statements of Income and Cash
Flows. GPM net assets have been segregated from continuing operations in the
accompanying statements of financial position and reported as net assets of
discontinued operations (See Note 3).
Use of Estimates. The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of certain assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during each reporting period. Management believes its estimates and assumptions
are reasonable; however, such estimates and assumptions are subject to a number
of risks and uncertainties which may cause actual results to differ materially
from the Company's estimates. Significant estimates underlying these financial
statements include the estimated quantities of proved oil and gas reserves and
the related present value of estimated future net cash flows therefrom (see
Supplementary Information beginning on page 74).
Cash and Temporary Investments. Temporary investments are stated at cost
which approximates fair market value, and consist of investments with original
maturities of three months or less.
Inventories. Inventories consist primarily of hydrocarbon volumes and
materials and supplies, carried on a first-in first-out basis at the lower of
cost or market. At December 31, 1999 and 1998 hydrocarbon inventory was $13.5
million and $11.0 million, respectively, while materials and supplies inventory
was $41.1 million and $53.6 million, respectively.
Oil and Gas Properties. Oil and gas properties are accounted for using the
successful efforts method. Under this method, exploration costs (drilling costs
of unsuccessful exploration wells, geological and geophysical costs,
non-producing leasehold amortization and delay rentals) are charged to expense
when incurred. Costs to develop producing properties, including drilling costs
and applicable leasehold acquisition costs, are capitalized. Costs to drill
exploratory wells that result in additions to reserves are also capitalized.
Depreciation, depletion and amortization of producing properties, including
depreciation of well and support equipment and amortization of related lease
costs, are determined by using a unit of production method based upon estimated
proved reserves. Provisions for depreciation of property and equipment other
than producing properties are computed principally on the straight-line method
based on estimated service lives, which range from two to 15 years. Potential
impairment of producing properties is assessed annually on a field-by-field
basis. Significant unproved properties are not amortized, but are monitored for
impairment and assessed annually in detail. Aggregated acquisition costs of
individual insignificant unproved properties are amortized from the date of
acquisition on a composite basis, which considers past success experience and
average lease life (see Note 6).
47
<PAGE> 53
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Costs of future site restoration, dismantlement and abandonment for
producing properties are accrued as part of depreciation, depletion and
amortization expense for tangible equipment by assuming no salvage value in the
calculation of the unit of production rate. Additional costs are accrued for
offshore and Canadian wells based on internal engineering estimates using the
unit of production method with a charge to depreciation, depletion and
amortization expense. The balance of the abandonment accrual at December 31,
1999 and 1998 was $75.0 million and $62.1 million, respectively.
Gains or losses on retired, sold or abandoned properties that constitute
part of an amortization base are deferred by charging or crediting the
investment, net of proceeds, to accumulated depreciation, depletion and
amortization unless such non-recognition would significantly affect the unit of
production rate. Gains or losses from the disposition of other properties are
recognized currently. Gains and losses from the sale of operating assets are
recognized in other oil and gas revenues. Gains included in other oil and gas
revenues were $148.0 million, $139.9 million and $18.8 million in 1999, 1998 and
1997, respectively. Gains and losses from all other dispositions are recorded in
other income.
Goodwill. Intangible and other assets include goodwill of $68.6 million for
intangible value acquired from business combinations prior to 1971. Such
goodwill is not being amortized because it is considered to have continuing
value over an indefinite period. The value of goodwill is evaluated annually to
determine whether any potential impairment exists.
Revenue Recognition. Sales from producing wells are recognized on the
entitlement method of accounting which defers recognition of sales when, and to
the extent that, deliveries to customers exceed the Company's net revenue
interest in production. Similarly, when deliveries are below the Company's net
revenue interest in production, sales are recorded to reflect the full net
revenue interest. The Company's gas imbalance liability at December 31, 1999 and
1998 was $5.5 million and $5.2 million, respectively. Natural gas and crude oil
marketing revenue is included in other oil and gas revenue and recorded net of
the cost of product purchased.
Recently issued accounting standards. The Financial Accounting Standards
Board ("FASB") has issued Statement of Financial Accounting Standards ("SFAS")
No. 133, "Accounting for Derivative Instruments and Hedging Activities," and
SFAS No. 137, which defers the effective date of SFAS No. 133 to fiscal years
beginning after June 15, 2000. SFAS No. 133 requires that all derivatives be
recognized on the balance sheet and measured at fair value. If certain
conditions are met, a derivative may be specifically designated as a hedge and
be eligible for special accounting treatment. However, the special accounting
treatment afforded hedge transactions may delay the recognition of a portion of
the gain or loss on the derivative, which would later be recorded concurrent
with the gain or loss on the item being hedged. For derivatives not designated
as hedges, gains or losses are recognized in earnings in the period of change.
The impact of the statement on the Company will depend upon price volatility and
the level of open derivative positions at the end of a reporting period. The
Company plans to adopt SFAS No. 133 for the first quarter 2001 and is currently
evaluating the effects of this pronouncement. Adoption will require the Company
to begin recording unrealized gains and losses in the Consolidated Statement of
Financial Position and in the Consolidated Statement of Comprehensive Income.
1. NATURE OF OPERATIONS
The Company is an independent oil and gas company engaged primarily in the
exploration for and the development and production of natural gas and crude oil
in several major basins in the United States, Canada, Guatemala, Venezuela and
other international areas. The Company markets all of its crude oil production
together with significant volumes of crude oil produced by others. In 1998, the
Company marketed a substantial portion of its natural gas and natural gas
liquids ("NGLs"); however, in 1999 the Company entered into a long-term natural
gas sales agreement to sell a substantial portion of its domestic natural gas
and NGLs to Duke (hereinafter defined) (see Notes 3 and 5). The Company also
engages in the hard
48
<PAGE> 54
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
minerals business through non-operated joint ventures and royalty arrangements
in several coal, trona (natural soda ash) and industrial mineral mines.
The Company's results of operations are largely dependent on the difference
between the prices received for its hydrocarbon products and the cost to find,
develop, produce and market such resources. Hydrocarbon prices are subject to
fluctuations in response to changes in supply, market uncertainty and a variety
of factors beyond the control of the Company. These factors include worldwide
political instability, the foreign supply of crude oil and natural gas, the
price of foreign imports, the level of consumer demand and the price and
availability of alternative fuels. The Company manages a portion of the
operating risk relating to hydrocarbon price volatility through hedging
activities (see Note 5).
2. ACQUISITIONS
Norcen Energy Resources Limited. On January 25, 1998, the Company and Union
Pacific Resources Inc. ("UPRI"), an Alberta corporation and a wholly-owned
subsidiary of the Company, entered into a pre-acquisition agreement
("Pre-acquisition Agreement") with Norcen Energy Resources Limited ("Norcen").
Under the Pre-acquisition Agreement, the Company and UPRI agreed to make an
offer (the "Tender Offer") for up to 100% of the common shares of Norcen,
subject to certain conditions. On March 3, 1998, the Company announced the
closing of the Tender Offer. In total, 95.5% of the outstanding common shares of
Norcen were tendered at a purchase price of U.S. $13.65 per share.
On March 5, 1998, the Company and UPRI completed the compulsory acquisition
of the remaining common shares outstanding which were not tendered. (The closing
of the Tender Offer and completion of the compulsory acquisition is referred to
as the "Norcen Acquisition.") The aggregate cash purchase price for the Norcen
Acquisition, including non-recurring transaction costs of $28.1 million, was
$2.634 billion. In addition, UPRI assumed the long-term debt obligations of
Norcen.
Norcen operations primarily consisted of crude oil and natural gas
exploration and development operations in western Canada, the Gulf of Mexico,
Guatemala and Venezuela.
The Company funded the purchase price of the Norcen Acquisition through the
issuance of commercial paper, supported by a U.S. $2.7 billion 364-Day
Competitive Advance/Revolving Credit Agreement dated March 2, 1998. In
accordance with Accounting Principles Board Opinion No. 16, "Business
Combinations," the Norcen Acquisition was accounted for as a purchase effective
March 3, 1998.
The following table represents the allocation of the total purchase price
of the assets acquired and liabilities assumed, based upon their fair values on
the date of the Norcen Acquisition and pushed down to the acquired Company. In
accordance with SFAS No. 109 "Accounting for Income Taxes", a deferred tax
liability was recognized for the differences between the allocated values and
the tax bases of the acquired assets and liabilities.
<TABLE>
<CAPTION>
MARCH 1998
---------------------
(MILLIONS OF DOLLARS)
<S> <C>
Working capital............................................. $ 114.4
Property, plant and equipment............................... 4,931.2
Other assets................................................ 228.2
Long-term debt.............................................. (1,012.0)
Deferred taxes.............................................. (1,495.7)
Other non-current liabilities............................... (131.8)
---------
Total purchase price.............................. $ 2,634.3
=========
</TABLE>
49
<PAGE> 55
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table presents unaudited pro forma Condensed Consolidated
Statements of Income of the Company for the twelve months ended December 31,
1998 and 1997, as though the Norcen Acquisition had occurred on January 1, 1997.
Certain adjustments were made to the financial information to conform to the
accounting policies and financial statement presentation of the Company.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------
1998 1997
------------ -----------
(MILLIONS OF DOLLARS, EXCEPT
PER SHARE AMOUNTS)
<S> <C> <C>
Revenues.................................................... $ 1,940.8 $2,169.3
Costs and expenses.......................................... 3,165.2 1,810.4
--------- --------
Operating income (loss)..................................... (1,224.4) 358.9
Interest expense............................................ (284.3) (240.1)
Other income (expense) -- net............................... (45.3) 24.5
--------- --------
Income (loss) before income taxes........................... (1,554.0) 143.3
Income tax (benefit) expense................................ (629.4) (24.5)
--------- --------
Income (loss) from continuing operations.................... $ (924.6) $ 118.8
========= ========
Earnings (loss) per share -- basic and diluted Continuing
operations................................................ $ (3.73) $ 0.47
</TABLE>
The unaudited pro forma condensed consolidated information presented above
is not necessarily indicative of the results of operations which would have
occurred had the Norcen Acquisition been consummated on January 1, 1997, nor is
it necessarily indicative of future results of operations.
Norcen Summarized Financial Information. As a result of the Norcen
Acquisition, and the amalgamation of Norcen with UPRI, UPRI assumed the
obligations of Norcen, including the public debt obligations of Norcen (the
"Debt Securities"). The Debt Securities include 6.8% Debentures due July 2,
2002, in the aggregate principal amount of $250 million, 7 3/8% Debentures due
May 15, 2006, in the aggregate principal amount of $250 million, and 7.8%
Debentures due July 2, 2008, in the aggregate principal amount of $150 million,
each of which have been fully and unconditionally guaranteed by the Company.
The following table presents summarized financial information for UPRI (as
successor to Norcen) as of and for the year ended December 31, 1999 and the two
months ended February 28, 1998, and ten months ended December 31, 1998. This
summarized financial information is being provided pursuant to Section G of
Topic 1 of Staff Accounting Bulletin No. 53 -- "Financial Statement Requirements
in Filings Involving the Guarantee of Securities by a Parent." The Company will
continue to provide such summarized financial information for UPRI as long as
the Debt Securities remain outstanding.
<TABLE>
<CAPTION>
YEAR ENDED UNAUDITED
DECEMBER 31, TEN MONTHS TWO MONTHS
1999 ENDED ENDED
--------------------- DECEMBER 31, FEBRUARY 28,
1998(a) 1998(b)
-------------------- --------------------
(MILLIONS OF (MILLIONS OF (MILLIONS OF
DOLLARS) DOLLARS) DOLLARS)
<S> <C> <C> <C>
Summarized Statement of Income
Information:
Operating revenues................... $343.0 $ 357.2 $104.0
Operating income (loss).............. (13.0) (784.5) 4.0
Net income (loss).................... $ 12.0 $(508.3)(c) $(30.0)(d)
</TABLE>
50
<PAGE> 56
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
AT DECEMBER 31, 1999 AT DECEMBER 31, 1998
-------------------- --------------------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Summarized Statement of Financial Position Information:
Current assets........................................ $ 40.5 $ 53.7
Non-current assets.................................... 1,844.8 1,882.3
Current liabilities................................... 83.9 279.8
Non-current liabilities and equity.................... $1,801.4 $1,656.2
</TABLE>
- ---------------
(a) Results for UPRI as of and for the ten months ended December 31, 1998,
include adjustments to reflect U.S. GAAP and the successful efforts method
of accounting. Adjustments to reflect the application of the purchase method
of accounting for the Norcen Acquisition are included effective March 3,
1998.
(b) Results for Norcen as of and for the two months ended February 28, 1998 have
not been restated in accordance with U.S. generally accepted accounting
principles ("GAAP") and reflect the full cost method of accounting for oil
and gas operations.
(c) Results reflect the impairment and write-down of certain oil and gas
properties.
(d) Net loss includes $40 million in costs incurred by Norcen in connection with
the Norcen Acquisition which were not reimbursed by the Company.
3. DIVESTITURES
Deleveraging Program. In 1998, the Company commenced a deleveraging program
which was designed to reduce the Company's debt. The deleveraging program, which
was initiated following the completion of the Norcen Acquisition, included the
sale of non-strategic properties and assets. The completed sales undertaken as
part of the Company's deleveraging program include the following:
<TABLE>
<CAPTION>
NON-STRATEGIC PROPERTIES OPERATING AREA SALES PRICE
- ------------------------ -------------- ---------------------
(MILLIONS OF DOLLARS)
<S> <C> <C>
1998
Denver-Julesburg Basin...................................... U.S. Onshore $ 41
Matagorda Island Blocks..................................... U.S. Offshore 158
Rockies Package............................................. U.S. Onshore 46
Eugene Island Blocks........................................ U.S. Offshore 8
Canadian Package............................................ Canada 145
Superior Propane............................................ Canada 48
----
1998 Total................................................ $446
----
1999
Caroline -- Swan Hill....................................... Canada $108
South Texas Package(a)...................................... U.S. Onshore 138
East Texas Package.......................................... U.S. Onshore 18
Rockies Package............................................. U.S. Onshore 10
Project Orange.............................................. Other 25
----
1999 Total................................................ 299
----
Total............................................. $745
====
</TABLE>
- ---------------
(a) As a result of the sale of the South Texas Package, the Company recorded a
fully reserved $20.6 million note receivable included in other current
assets. If the note is collected, the Company will record $20.6 million in
additional proceeds and gain on the South Texas sale.
Discontinued Operations. In November 1998, the Company entered into a
Merger and Purchase Agreement ("Agreement") with Duke Energy Field Services,
Inc. ("Duke") to sell its GPM business segment for $1.36 billion in cash. On
March 31, 1999, the Company closed on the sale (the "GPM
51
<PAGE> 57
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Disposition"). The GPM Disposition consisted primarily of the Company's
pipelines, gathering systems, natural gas processing plants and natural gas and
NGL marketing assets and operations. These operations included interests in
nineteen natural gas processing plants (together with approximately 7,200 miles
of pipelines that support these processing plants), as well as two non-operated
NGL fractionation plants. The Company retained its crude oil marketing business.
The Company recorded a $157.0 million after-tax gain on the GPM Disposition,
including $108.3 million for accrued taxes payable.
Summarized information relating to discontinued results of operations,
excluding the after-tax gain on the GPM Disposition are as follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------
1999 1998 1997
------ ------- -------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Operating revenues....................................... $ 21.5 $ 340.0 $ 406.7
Operating expenses....................................... (29.7) (263.4) (281.3)
Depreciation depletion and amortization.................. (20.4) (77.6) (64.1)
------ ------- -------
Operating income (loss).................................. (28.6) (1.0) 61.3
Other income (expense) -- net............................ -- -- (0.2)
Interest expense (a)..................................... (8.0) (21.1) (13.6)
------ ------- -------
Income (loss) before taxes............................... (36.6) (22.1) 47.5
Income tax (benefit) expense............................. (12.8) (6.5) 17.6
------ ------- -------
Net income (loss) from discontinued operations........... $(23.8) $ (15.6) $ 29.9
====== ======= =======
</TABLE>
- ---------------
(a) The Company allocated interest expense to the GPM business segment based on
the ratio of net assets of discontinued operations to total Company net
assets, excluding $3.6 billion of debt associated with the Norcen
Acquisition.
Summarized information relating to net assets of discontinued operations
are as follows:
<TABLE>
<CAPTION>
AT DECEMBER 31, 1998
---------------------
(MILLIONS OF DOLLARS)
<S> <C>
Current Assets:
Cash and temporary investments............................ $ 5.7
Accounts receivable -- net................................ 152.8
Inventories............................................... 46.8
Other current assets...................................... 5.2
--------
Total current assets.............................. 210.5
Properties -- net of accumulated depreciation............. 851.3
Intangible and other assets............................... 154.8
--------
Total assets...................................... $1,216.6
========
Current Liabilities:
Accounts payable.......................................... $ 158.0
Advance payment(a)........................................ 126.7
Other current liabilities................................. 2.0
--------
Total current liabilities......................... 286.7
Other long-term liabilities............................... 3.0
--------
Total liabilities................................. $ 289.7
========
Net assets of discontinued operations............. $ 926.9
========
</TABLE>
52
<PAGE> 58
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
- ---------------
(a) In June 1998, the Company entered into a third-party forward sales
arrangement covering a total of 567 MMcf of gas per day. At the time of the
arrangement, the Company received $250 million and became obligated to
deliver gas from October 1998 through March 1999. The Company recorded the
obligation associated with this transaction as an advance payment included
in net assets of discontinued operations. This current liability was
amortized and recorded on the Consolidated Statement of Income as part of
discontinued operations, as the gas was delivered over the remaining term of
the contract.
4. RESTRUCTURING CHARGES
During the first quarter of 1999, the Company reorganized its operating
groups, announced workforce reductions for its Canadian and U.S. operations and
established an early retirement program. As a result of these actions, the
Company recorded a $14.5 million restructuring charge. The charge included $7.3
million for severance costs and excess office space commitments, an additional
$4.2 million liability for pension and other postretirement benefits in
connection with the early retirement program and a $3.0 million valuation
allowance for specialty drilling equipment and supplies no longer required for
cancelled drilling programs. Payments of $7.2 million were made for severance
and office lease costs. The pension and other postretirement liabilities are
included in the balance of the Company's liabilities for those items (see Note
11). The valuation allowance for specialty drilling equipment and supplies was
recorded to the inventory accounts.
During 1998, the Company announced a workforce reduction for its domestic
operations and implemented programs to reduce overhead and other costs. The
$17.0 million restructuring charge included $7.6 million for workforce
reductions of approximately 140 U.S. employees, $5.0 million for a drilling rig
commitment and $4.4 million for excess office space commitments. At December 31,
1998, $14.6 million of the reserve remained. During 1999, net payments of $8.1
million were made and $3.1 million of the rig commitment charge was reversed as
a result of favorable settlement negotiations. At December 31, 1999, the $3.4
million remaining reserve represents excess office space commitments net of
sublease rentals.
5. FINANCIAL INSTRUMENTS
Hedging. The Company has established policies and procedures for managing
risk within its organization, including internal controls and governance by a
risk management committee. The level of risk assumed by the Company is based on
its objectives and earnings, and its capacity to manage risk. Limits are
established for each major category of risk, with exposures monitored and
managed by Company management and reviewed semi-annually by the risk management
committee. Major categories of the Company's risk are defined as follows:
Commodity Price Risk -- Non-Trading Activities. The Company uses derivative
financial instruments for non-trading purposes in the normal course of business
to manage and reduce risks associated with contractual commitments, price
volatility and other market variables. These instruments are generally put in
place to limit risk of adverse price movements; however, these same instruments
usually limit future gains from favorable price movements. Risk management
activities are generally accomplished pursuant to exchange-traded contracts or
over-the-counter swaps and options.
Recognition of realized gains/losses and option premium payments/receipts
relating to non-trading activities are deferred in the Consolidated Statement of
Income until the underlying physical product is sold. Unrealized gains/losses
are not recorded. Margin deposits, deferred gains/losses and net premiums are
included in other current assets or liabilities in the Consolidated Statement of
Financial Position. The cash flow impact is reflected in cash flows provided by
operations in the Consolidated Statement of Cash Flows.
Utilization of the Company's hedging program may result in crude oil and
natural gas prices varying from market prices. As a result of the hedging
program, revenues in 1999, 1998 and 1997 were $178.1 million, $9 million and $86
million lower, respectively than if the hedging program had not been in effect.
Since these transactions were hedges on production, these impacts were also
reflected in the average sales price of the associated products.
53
<PAGE> 59
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Commodity Price Risk -- Trading Activities. The Company periodically enters
into financial contracts in conjunction with market-making or trading activities
with the objective of achieving profits through successful anticipation of
movements in commodity prices and changes in other market variables. Market-
making positions are marked-to-market and gains and losses are immediately
included as revenue in the Consolidated Statement of Income. In addition, the
fair value of unsettled positions is immediately included in the Consolidated
Statement of Financial Position as a current asset or current liability. As of
December 31, 1999 and 1998, there were no transactions in place which would
materially affect the results of operations or financial condition of the
Company.
Interest Rate Swaps. The Company periodically enters into rate swaps and
contracts to hedge certain interest rate transactions. As of December 31, 1999
and 1998, there were no interest rate contracts outstanding which would
materially affect the results of operations or financial condition of the
Company. During 1998, the Company entered into rate lock contracts to hedge
interest rates related to a contemplated bond issuance. The bonds were not
issued and the Company recognized a $14.3 million pre-tax loss in 1998
associated with these contracts.
Foreign Currency. The financial statements of foreign subsidiaries, except
those subsidiaries located in countries which have highly inflationary
economies, utilize the local currency as their functional currency. The
financial statements of foreign subsidiaries located in countries which have
highly inflationary economies utilize the U.S. dollar as their functional
currency. Monetary assets and liabilities denominated in a currency other than
the functional currency are remeasured into the functional currency with the
corresponding gains/ losses included in the Consolidated Statement of Income.
The financial statements of those foreign subsidiaries which do not utilize the
U.S. dollar as their functional currency are translated into the U.S. dollar.
Assets and liabilities are translated at the current exchange rate, while
revenues and expenses are translated at the average exchange rate for the
reporting period. Translation gains/losses are not included in the Consolidated
Statement of Income but are recorded in a separate section of shareholders'
equity. The Company's Canadian subsidiary's functional currency is the Canadian
dollar. Generally, the functional currency of the Company's other foreign
subsidiaries is the U.S. dollar.
At December 31, 1999, the Company's Canadian subsidiary had outstanding
$650 million of fixed-rate notes and debentures denominated in U.S. dollars.
During 1999, the Company recognized a $38.0 million pretax non-cash gain
associated with remeasurement of this debt and a $46.5 million pretax non-cash
loss during 1998. The potential foreign currency remeasurement impact on
earnings from a five percent change in the year-end Canadian exchange rate would
be approximately $32 million.
Two of the Company's Latin American subsidiaries had foreign deferred tax
liabilities denominated in the local currency. At December 31, 1999 and 1998,
Venezuela had a $131.6 million and $159.6 million liability, respectively and
Guatemala had a $34.1 million and $58.0 million liability, respectively. During
1999 and 1998, the Company recognized after-tax deferred tax benefits associated
with the remeasurement of the deferred tax liabilities of $20.4 million and
$15.2 million in Venezuela, and $8.9 million and $7.3 million in Guatemala,
respectively. The potential foreign currency remeasurement impact on net
earnings from a five percent change in the year-end Latin American exchange
rates would be approximately $9 million.
The Company may periodically enter into foreign currency contracts to hedge
specific currency exposures from commercial transactions. As a result of the
Norcen Acquisition, the Company acquired foreign currency forward exchange
contracts with maturities through October 2000, and recorded a $15.5 million
deferred liability representing the fair value of these contracts. These
contracts were deemed to be hedges of UPRI's future U.S. dollar denominated
hydrocarbon sales. This deferred liability will be amortized over the contract
terms. The unrecognized loss on foreign currency contracts at December 31, 1999,
excluding the $1.4 million remaining unamortized deferred liability, was $2.9
million.
54
<PAGE> 60
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Concentrations of Credit Risk. Credit risk is the risk of loss as a result
of non-performance by counterparties pursuant to the terms of their contractual
obligations. Because the loss can occur at some point in the future, a potential
exposure is added to the current replacement value to arrive at a total expected
credit exposure. The Company has established methodologies to establish limits,
monitor and report creditworthiness and concentrations of credit to reduce such
credit risk. At December 31, 1999, the Company's largest credit risk associated
with any single counterparty, represented by the net fair value of open
contracts with such counterparty, was $7.1 million.
Financial instruments which subject the Company to concentrations of credit
risk consist principally of trade receivables and short-term cash investments.
The Company places its temporary excess cash investments in high quality
short-term instruments through several high-credit-quality financial
institutions. A significant portion of the Company's trade receivables relate to
customers in the oil and gas industry, and, as such, the Company is directly
affected by the economy of that industry. The Company derives a substantial
portion of its revenues from international operations in Canada and Latin
America. With the exception of one large customer, described below, the credit
risk associated with trade receivables is minimized by the Company's large
customer base and ongoing procedures to monitor the creditworthiness of
customers. The Company generally requires no collateral from its customers.
Historically, the Company has not experienced significant losses on trade
receivables.
In connection with the GPM Disposition, the Company entered into a
long-term sales agreement with Duke. The long-term sales agreement obligates the
Company to sell the majority of its domestic natural gas and existing NGL
production to Duke through March 2004. Prices received for the natural gas and
NGLs will be tied to the current market price for each product. As a result, a
significant portion of the Company's credit risk will be with a single customer.
Duke is currently considered a good credit risk; however, periodic credit
evaluations will continue and will be performed more often if circumstances
dictate. The agreement with Duke provides for a parental guaranty to cover its
obligations under the agreements and the Company has the right to demand a
letter of credit and/or other assurances under certain circumstances. During
1999, sales to Duke accounted for 31% of the Company's consolidated revenues and
38% of United States revenues. Approximately 25% of the Company's trade
receivables outstanding at December 31, 1999 were due from Duke which exposes
the Company to a concentration of credit risk.
Performance Risk. Performance risk results when a counterparty fails to
fulfill its contractual obligations with respect to commodity pricing or volume
commitments. Typically, such risk obligations are defined within the trading
agreements. The Company utilizes its credit risk methodology to manage
performance risk.
6. PROPERTIES
Major property classifications were as follows:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
---------------------
1999 1998
--------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Producing properties........................................ $ 9,738.3 $ 9,429.9
Non-producing properties.................................... 983.3 1,241.5
Construction in progress.................................... 84.3 143.4
Other....................................................... 200.7 263.4
--------- ---------
Total............................................. $11,006.6 $11,078.2
========= =========
</TABLE>
55
<PAGE> 61
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Accumulated depreciation, depletion and amortization by major property
classifications were as follows:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
---------------------
1999 1998
--------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Producing properties........................................ $5,160.0 $4,642.1
Non-producing properties.................................... 273.2 233.1
Other....................................................... 102.4 109.7
-------- --------
Total............................................. $5,535.6 $4,984.9
======== ========
</TABLE>
Based upon the Company's analysis of expected future net cash flows from
its crude oil and natural gas properties, certain properties were deemed to be
impaired due to lower hydrocarbon prices and/or downward revisions in reserve
estimates. As a result of its analysis, the Company adjusted the net book value
of such properties to their fair value with a charge to depreciation, depletion
and amortization of $70.6 million in 1999 for exploration and production
properties primarily located in the U.S. Onshore area and uranium properties.
During 1998, the Company adjusted the net book value of properties with a $1.2
billion charge, primarily on properties acquired in the Norcen Acquisition.
Fixed asset additions included capitalized interest of $0.4 million and $0.9
million in 1999 and 1998, respectively.
7. CAPITAL AND EXPLORATORY EXPENDITURES
Capital and exploratory expenditures include the following:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
----------------------------------
1999 1998 1997
-------- ---------- ----------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Capital expenditures:
Producing properties.................................. $345.1 $3,056.9 $ 773.3
Non-producing properties.............................. 21.0 506.6 200.7
Exploratory drilling.................................. 12.9 117.5 121.7
Other................................................. 5.1 32.6 15.8
------ -------- --------
Total capital expenditures.................... 384.1 3,713.6 1,111.5
Exploratory expenditures:
Expensed geological and geophysical costs............. 19.5 63.1 35.2
Expensed dry hole costs............................... 24.6 52.1 41.7
------ -------- --------
Total exploratory expenditures................ 44.1 115.2 76.9
------ -------- --------
Total capital and exploratory expenditures.... $428.2 $3,828.8 $1,188.4
====== ======== ========
</TABLE>
8. INCOME TAXES
Deferred taxes are established for all temporary differences between the
book and tax bases of assets and liabilities. In addition, deferred tax balances
must be adjusted to reflect tax rates that will be in effect in the years in
which the temporary differences are expected to reverse. Non-U.S. subsidiaries
compute taxes at rates in effect in the various countries. Earnings of these
subsidiaries may also be subject to additional income and withholding taxes when
they are distributed as dividends. Deferred tax liabilities are not recognized
on profits that are expected to be permanently reinvested by the local
subsidiaries and thus not considered available for distribution to the parent
Company. The Company has undistributed earnings of its 100% owned foreign
subsidiaries that arose in 1999 and prior years.
56
<PAGE> 62
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Income (loss) from continuing operations before taxes is as follows:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
---------------------------------
1999 1998 1997
-------- ----------- --------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Domestic................................................. $(45.2) $ (239.7) $405.9
Foreign.................................................. (6.0) (1,248.6) 13.0
------ --------- ------
Total.......................................... $(51.2) $(1,488.3) $418.9
====== ========= ======
</TABLE>
Components of income tax expense (benefit), from continuing operations,
were as follows:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------
1999 1998 1997
--------- --------- --------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Current:
U.S. Federal........................................... $(151.4) $ 43.2 $ (0.4)
U.S. state............................................. 2.2 6.8 5.1
Foreign................................................ 7.4 4.1 0.2
------- ------- ------
Total current.................................. (141.8) 54.1 4.9
------- ------- ------
Deferred:
U.S. Federal........................................... 82.4 (155.7) 113.4
U.S. state............................................. (2.7) 3.4 (2.5)
Foreign................................................ (78.3) (507.0) --
------- ------- ------
Total deferred................................. 1.4 (659.3) 110.9
------- ------- ------
Total income tax expense (benefit)............. $(140.4) $(605.2) $115.8
======= ======= ======
</TABLE>
Deferred tax liabilities (assets), were as follows:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
---------------------
1999 1998
--------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Excess tax over book items, including depreciation and
exploration costs......................................... $1,369.0 $1,528.2
State taxes -- net.......................................... 12.1 (15.0)
Long-term liabilities....................................... 116.3 (19.6)
Alternative minimum tax..................................... (79.8) (72.6)
Pension and other retirement benefits....................... (47.2) (52.6)
Net operating losses........................................ (91.3) (93.1)
Other....................................................... 47.7 16.3
-------- --------
Net deferred tax liability........................ $1,326.8 $1,291.6
======== ========
</TABLE>
57
<PAGE> 63
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
A reconciliation between U.S. statutory and consolidated effective tax
rates is as follows:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED
DECEMBER 31,
-------------------
1999 1998 1997
----- ---- ----
<S> <C> <C> <C>
U.S. statutory Federal tax rate............................. 35.0% 35.0% 35.0%
Section 29 credits.......................................... 35.1 1.1 (4.3)
State taxes-- net........................................... (8.2) (0.4) 1.3
Foreign rate differentials.................................. -- 1.8 --
Foreign currency remeasurement.............................. 98.7 1.5 --
Non-tax effected foreign expense............................ (48.4) -- --
Non-taxable entity.......................................... 15.3 1.0 --
Tax settlements............................................. 78.3 -- (1.5)
Reserve adjustments......................................... 28.7 -- --
Tax return reconciliation adjustments....................... 34.1 -- --
Other....................................................... 7.0 0.6 (1.9)
----- ---- ----
Effective tax rate........................................ 275.6% 40.6% 28.6%
===== ==== ====
</TABLE>
The Company generates Section 29 tax credits from the sale of certain fuels
produced from non-conventional sources. Fuels qualifying for the credit must be
produced from a well drilled or a facility placed in service after December 31,
1979, and before January 1, 1993, and must be sold before January 1, 2003. The
Company generated $17.9 million, $16.4 million and $18.8 million of Section 29
tax credits in 1999, 1998 and 1997, respectively. The Federal tax law provides
for the use of these credits against regular Federal income tax liability.
Accordingly, the Company utilized $6.9 million of Section 29 tax credits on its
1998 tax return. It is anticipated that all of the 1999 Section 29 tax credits
along with some of the prior year credits will be recognized in the Company's
1999 tax return. The Company recognized favorable tax adjustments relating to
prior year Federal tax returns in the amount of $17.4 million for 1999 and $4
million for 1998.
While the operations of the Company in Guatemala are subject to local
income taxes, no liability has arisen in recent years since sufficient
unrecovered costs, carried forward from previous years, have been available to
offset current taxable income. Guatemalan tax benefits, which can be carried
forward indefinitely, were $57.6 million at December 31, 1999. Other domestic
subsidiary net operating losses in existence at the time of the Norcen
Acquisition were merged with the Company when those subsidiaries were dissolved.
The Company plans to utilize the losses in 2000 or a future year.
On September 1, 1999, the Company and its former parent, Union Pacific
Corporation ("UPC"), settled certain outstanding issues pertaining to the
allocation of all Federal and state tax liabilities, including interest, for the
tax years 1968 through 1982. This settlement was made pursuant to the Tax
Allocation Agreement entered into as of October 6, 1995, between the Company and
UPC. This settlement resulted in the receipt by the Company from UPC on
September 3, 1999, of $29 million (including $20.5 million of interest income
recorded in other income) in full and final settlement of all amounts owed to or
by UPR with respect to tax years 1968 through 1982. The tax settlement with UPC
enabled the Company to reevaluate its deferred tax reserves, and as a result,
the Company recorded $11.9 million of deferred tax benefits related to the tax
years covered by the settlement. The Company and UPC also agreed to suspend
settlement rights under the Tax Allocation Agreement with respect to post-1982
tax years until July 1, 2001. UPC has informed the Company that all material
deficiencies prior to 1986 have been settled with the Internal Revenue Service
("IRS"). UPC is negotiating with the IRS Appeals Office concerning 1986 through
1989. The IRS has completed its examination of the Company's returns for 1990
through 1994; however, their audit remains open until resolution of the UPC
issues. The IRS has initiated steps to begin the process of examining the
Company's
58
<PAGE> 64
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
records for 1995 through 1998. The Company believes it has adequately provided
for Federal and state income taxes.
In 1997, Norcen received a reassessment from Canadian tax authorities in
the amount of $81.1 million concerning the deductibility of certain expenses and
foreign exchange losses claimed for income tax purposes during the period 1989
through 1993. In spite of Norcen's disagreement and appeal, the reassessment was
fully funded in 1997. As a result of the Norcen Acquisition, the Company valued
this issue at $17.0 million, net of any valuation allowance, as part of the
purchase price allocation. On March 8, 1999, UPRI entered into an agreement with
Canadian tax authorities to settle these claims out of court. Under the terms of
the settlement, the Company received a refund of approximately $54.6 million
dollars. The Company recorded $7.1 million of interest to other income and a
$27.9 million deferred income tax benefit related to the refund.
9. DEBT
The total debt of the Company is summarized below:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
INTEREST ---------------------
RATE 1999 1998
-------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Commercial Paper and Bankers' Acceptances (Average of
5.55% and 5.98% at December 31, 1999 and 1998,
respectively)......................................... $ 135.1 $2,351.9
Debentures due July 2, 2002............................. 6.800% 250.0 250.0
Notes due May 15, 2005.................................. 6.500% 200.0 200.0
Debentures due May 15, 2006............................. 7.375% 250.0 250.0
Notes due October 15, 2006.............................. 7.000% 200.0 200.0
Notes due May 15, 2008.................................. 6.750% 169.5 200.0
Debentures due July 2, 2008............................. 7.800% 150.0 150.0
Notes due April 15, 2009................................ 7.300% 176.0 --
Debentures due May 15, 2018............................. 7.050% 200.0 200.0
Debentures due October 15, 2026......................... 7.500% 200.0 200.0
Debentures due May 15, 2028............................. 7.150% 395.0 425.0
Debentures due April 15, 2029........................... 7.950% 290.0 --
Debentures due November 1, 2096......................... 7.500% 150.0 150.0
Capital lease obligations (Note 10)..................... 16.0 17.4
(Discount) Premium on notes and debentures -- net....... 18.0 4.4
-------- --------
Total debt.................................... 2,799.6 4,598.7
Less: current portion......................... 2.3 853.8
-------- --------
Total long-term debt.......................... $2,797.3 $3,744.9
======== ========
</TABLE>
At year-end 1998, the Company had three debt facilities totaling an
aggregate of U.S. $2.5 billion. These facilities were comprised of a $1.0
billion 364-Day Competitive Advance/Revolving Credit Agreement (the "Bridge
Facility"), a $750 million 364-Day Competitive Advance/Revolving Credit
Agreement and a $750 million Competitive Advance/Revolving Credit Agreement
("Long-Term Facility") expiring in October 2003.
In April 1999, the Company issued $500 million of notes and debentures
comprised of $200 million 7.3% Notes due April 2009 and the $300 million 7.95%
Debentures due April 2029. The notes and debentures were issued under the
Company's existing $1.0 billion shelf registration statement, of which $500
million remains available.
59
<PAGE> 65
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
During the first half of 1999, commercial paper, supported in part by the
Company's Bridge Facility, was repaid using proceeds from property sales,
proceeds from the sale of the GPM business segment and the issuance of the
long-term notes and debentures. The Bridge Facility was terminated in April
1999. The $750 million 364-Day Competitive Advance/Revolving Credit Agreement
expired in October 1999, leaving the Company with the Long-Term Facility at
year-end 1999. The Long-Term Facility contains a covenant stipulating that the
ratio of consolidated debt to consolidated EBITDAX -- the sum of operating
income (before adjustments for income taxes, interest expense or extraordinary
gains or losses), depreciation, depletion and amortization and exploration
expenses -- cannot exceed 3.25:1.00. The Long-Term Facility also places other
restrictions on the Company regarding the creation of liens, incurrence of
additional indebtedness by subsidiaries, transactions with affiliates, sales of
stock of Union Pacific Resources Company (a wholly-owned subsidiary of the
Company) and certain mergers, consolidations and asset sales. The Company was in
compliance with the covenant provisions at year-end 1999 and 1998.
The 2005, 2008 and 2009 notes and the 2018, 2028 and 2029 debentures are
redeemable as a whole or in part, at the option of the Company at any time. The
redemption price is equal to the greater of (i) 100% of the principal amount of
the Debt Securities to be redeemed or (ii) the sum of the present values of the
remaining scheduled payments thereon, discounted to the redemption date on a
semi-annual basis at the Treasury Rate, plus a stated basis point spread and
accrued interest on the principal amount being redeemed to the redemption date.
There are no other notes or debentures redeemable prior to maturity. None of the
Company's notes and debentures are subject to a sinking fund requirement. At
December 31, 1999, the Company had an effective shelf registration statement on
file with the Securities and Exchange Commission that would permit the Company
or certain identified subsidiaries to offer up to $500 million in debt, equity
and/or other securities.
During 1999, the Company purchased on the open market and retired long-term
debt with a face value of $94.5 million at a discount prior to maturity. The
retirement of long-term debt due to the repurchases resulted in an extraordinary
gain of $3.4 million, net of $1.8 million of tax. The gain on the retirement was
classified as a gain from an extraordinary item on the Consolidated Statement of
Income.
At December 31, 1999, $135.1 million of commercial paper and bankers
acceptances was classified as long-term. This classification reflects the
Company's intent and ability to maintain these borrowings on a long-term basis,
supported by the Long-Term Facility through the issuance of additional
commercial paper and/or new term financings. Debt maturities through 2004,
excluding capital leases, are $135.1 million of bankers acceptances due in 2000
and $250 million of Debentures due July 2, 2002.
The fair value of the Company's long-term debt, excluding commercial paper
and bankers acceptances, debt discount/premium and capital lease obligations was
$2,467 million at December 31, 1999 and $2,088 million at December 31, 1998. The
fair value was estimated using quoted market prices. These fair values were
trading at a discount to the face value of 93.8% at both December 31, 1999 and
1998.
As a result of the Norcen Acquisition, the Company recorded a $31.5 million
debt premium, representing the excess of the fair value over the carrying value
of the debt acquired. The $25.2 million remaining debt premium, net of $7.2
million in debt discount related to prior debt issuances, are being amortized
over the life of the debt term.
The Company has guaranteed a portion of the OCI Wyoming, L.P debt facility.
At December 31, 1999, OCI Wyoming, L.P. had an outstanding debt facility balance
of $30 million, of which the Company has guaranteed $14.7 million. The Company's
portion of the debt is reflected in the balance for investment in affiliate on
the Consolidated Statement of Financial Position.
The Company utilizes letters of credit to support certain financing
instruments, performance contracts and insurance policies. The fair value of the
letters of credit at December 31, 1999 and 1998 was $41.3 million and $58.6
million, respectively.
60
<PAGE> 66
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10. LEASE COMMITMENTS
The Company leases several office buildings, certain production platforms
and other property under operating leases. The Company also maintains a capital
lease for furniture and walls in its Fort Worth offices. Future minimum lease
payments for operating and capital leases with initial non-cancelable lease
terms in excess of one year as of December 31, 1999, were as follows:
<TABLE>
<CAPTION>
AS OF DECEMBER 31, 1999
----------------------------
CAPITAL OPERATING
LEASES LEASES TOTAL
------- --------- ------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
2000...................................................... $ 2.8 $ 46.9 $ 49.7
2001...................................................... 2.9 44.4 47.3
2002...................................................... 2.9 42.6 45.5
2003...................................................... 2.9 32.2 35.1
2004...................................................... 6.6 3.9 10.5
Later years............................................... 0.8 6.9 7.7
----- ------ ------
Total future minimum lease payments....................... 18.9 $176.9 $195.8
====== ======
Less: amounts representing interest....................... (2.9)
-----
Present value of minimum capital lease obligations........ 16.0
-----
Less: Short-term portion of capital lease obligations..... (2.3)
-----
Long-term portion of capital lease obligations............ $13.7
=====
</TABLE>
Rent expense, net of sublease income, for operating leases with terms
exceeding one month was $60.2 million in 1999, $59.8 million in 1998, and $19.2
million in 1997. Sublease income for the next five years will be $30.5 million
in 2000, $29.8 million in 2001, $29.8 million in 2002, $28.5 million in 2003 and
$0.4 million in 2004. Capital leases included in corporate fixed assets were
$17.4 million and $18.1 million at December 31, 1998 and 1999, respectively.
11. RETIREMENT PLANS
The Company provides pension, health care and life insurance benefits to
all eligible retirees in the U.S. and pension benefits to all eligible retirees
in Canada. No such pension or other benefits are provided to employees of other
foreign subsidiaries.
U.S. Pension Benefits. Pension benefits for U.S. employees are based on
years of service and compensation during the last years of employment.
Contributions to the plans are calculated on the Projected Unit Credit actuarial
funding method and are not less than the minimum funding standards set forth in
the Employees Retirement Income Security Act of 1974, as amended. The portion of
the funded plan's assets held in fixed-income and short-term securities was
approximately 33% and 32% as of December 31, 1999 and 1998, respectively, with
the remainder primarily in equity securities.
Curtailments and Termination of Benefits. During 1999, the Company
announced reductions in force, a voluntary retirement incentive program ("VRIP")
and the sale of the GPM business segment. The separations due to these programs
triggered curtailment accounting and termination benefit accounting as a result
of the VRIP. The Company recognized curtailment gains of $11.4 million, offset
by costs of the termination of benefits of $10.5 million. These separations
caused a slight reduction in the Company's retiree benefits obligations due to
reduced expected future benefits for the employees affected by these programs.
Other U.S. Postretirement Benefits. Postretirement health and life
insurance benefits are provided to all eligible U.S. retirees. The Company does
not currently pre-fund health care and life insurance benefit costs.
61
<PAGE> 67
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Canadian Pension Benefits. Benefits provided under the Canadian defined
benefit plan are based on years of service and highest compensation over a
specified number of consecutive years. The provisions under the defined benefit
plan were modified to provide employees with a defined contribution plan option,
which has been retroactively elected by substantially all active employees.
Under the defined contribution plan, the Company matches a stated percentage of
employee contributions to the plan. Both the defined benefit payments and the
defined contribution Company match obligation are paid from assets held in
trust. The Company will make contributions to the plans, if necessary, to
maintain adequate assets in trust. Contributions are not expected to be
necessary for several years.
The following pension credits and funded status are based on historical
actuarial valuations.
<TABLE>
<CAPTION>
U.S. PENSION OTHER CANADIAN
BENEFITS U.S. BENEFITS PENSION BENEFITS
--------------- ------------- -----------------
1999 1998 1999 1998 1999 1998
------ ------ ----- ----- ------- -------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C> <C> <C>
Change in benefit obligation:
Benefit obligation at beginning of year..... $221.0 $202.6 $40.4 $42.9 $ 25.6 $ --
Acquisition................................. -- -- -- -- -- 26.1
Service cost................................ 5.1 6.1 0.7 1.0 -- 0.1
Interest cost............................... 15.3 14.3 2.8 3.0 1.8 1.4
Curtailments................................ (10.1) -- (1.3) -- -- --
Termination benefits........................ 9.5 -- 1.0 -- -- --
Plan amendments............................. 12.3 2.4 -- (5.4) -- --
Actuarial (gain) loss....................... (4.7) 12.6 (2.9) 0.1 0.2 (0.2)
Benefits paid............................... (19.4) (17.0) (2.7) (1.2) (2.7) (1.8)
------ ------ ----- ----- ------ ------
Benefit obligation at end of year........... $229.0 $221.0 $38.0 $40.4 $ 24.9 $ 25.6
====== ====== ===== ===== ====== ======
Change in plan assets:
Fair value of plan assets at beginning of
year...................................... $269.7 $240.9 $ -- $ -- $ 47.7 $ --
Acquisition................................. -- -- -- -- -- 50.3
Actual return on plan assets................ 32.4 40.0 -- -- 3.5 --
Employer contribution(a).................... 2.3 5.8 2.7 1.2 0.2 --
Benefits paid(b)............................ (19.4) (17.0) (2.7) (1.2) (3.6) (2.6)
Foreign currency exchange rate gain......... -- -- -- -- 2.9 --
------ ------ ----- ----- ------ ------
Fair value of plan assets at end of year.... $285.0 $269.7 $ -- $ -- $ 50.7 $ 47.7
====== ====== ===== ===== ====== ======
Plan assets (over) under benefit
obligation................................ $(56.0) $(48.7) $38.0 $40.4 $(25.8) $(22.1)
Unamortized net transition asset............ 13.2 15.8 -- -- -- --
Unrecognized prior service gain (cost)...... (18.9) (9.0) 6.0 8.0 -- --
Unrecognized net gain....................... 121.2 105.1 24.9 25.1 (3.2) (1.9)
------ ------ ----- ----- ------ ------
Net amount recognized....................... $ 59.5 $ 63.2 $68.9 $73.5 $(29.0) $(24.0)
====== ====== ===== ===== ====== ======
</TABLE>
- ---------------
(a) Represents payments relating to unfunded plans. In addition, the Company
periodically settles a portion of the unfunded supplemental pension plan
benefit obligations through the purchase of annuities.
(b) $0.9 million and $0.8 million of Canadian pension benefits paid in 1999 and
1998 respectively, represent payments to fund the defined contribution
Company match.
62
<PAGE> 68
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
U.S. PENSION U.S. OTHER CANADIAN
BENEFITS BENEFITS PENSION BENEFITS
-------------- ------------- -----------------
1999 1998 1999 1998 1999 1998
------ ----- ----- ----- ------- -------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C> <C> <C>
Amounts recognized in the Statement of
Financial Position consist of:
Prepaid benefit cost....................... $ -- $ -- $ -- $ -- $(29.0) $(24.0)
Accrued benefit liability.................. 76.0 72.0 68.9 73.5
Intangible asset........................... (5.6) (3.9) -- -- -- --
Accumulated other comprehensive income..... (10.9) (4.9) -- -- -- --
------ ----- ----- ----- ------ ------
Net amount recognized........................ $ 59.5 $63.2 $68.9 $73.5 $(29.0) $(24.0)
====== ===== ===== ===== ====== ======
Weighted-average assumptions as of December
31
Discount rate................................ 7.75% 7.0% 7.75% 7.0% 7.25% 6.5%
Expected return on plan assets............... 9.0% 9.0% -- -- 7.25% 6.5%
Rate of compensation increase................ 5.75% 5.0% -- -- 5.75% 5.0%
</TABLE>
For measurement purposes, a 7.2% annual rate of increase in the per capita
cost of covered health care benefits was assumed for 1999. The rate was assumed
to gradually decrease to 5% in 2005 and remain at that level thereafter.
<TABLE>
<CAPTION>
CANADIAN
U.S. PENSION BENEFITS U.S. OTHER BENEFITS PENSION
------------------------ ------------------- -------------
1999 1998 1997 1999 1988 1997 1999 1998
------ ------ ------ ----- ---- ---- ----- -----
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Service cost-benefits earned during the
period........................................ $ 5.1 $ 6.1 $ 5.5 $ 0.7 $1.0 $0.8 $ -- $ 0.1
Interest cost on the projected benefit
obligation.................................... 15.3 14.3 13.4 2.8 3.0 3.3 1.8 1.4
Expected return on plan assets.................. (19.0) (18.6) (17.1) -- -- -- (3.6) (2.7)
Amortization of net transition asset............ (2.6) (2.1) (2.0) -- -- -- -- --
Amortization of unrecognized prior service gain
(cost)........................................ 1.2 1.2 1.2 (0.6) (0.8) (0.8) -- --
Amortization of unrecognized net gain........... (2.3) (4.1) (4.9) (1.0) (1.7) (1.6) -- --
Settlement/curtailment/termination benefits..... 0.9 -- -- (3.7) -- -- -- --
------ ------ ------ ----- ---- ---- ----- -----
(Benefit) charge to operations................ $ (1.4) $ (3.2) $ (3.9) $(1.8) $1.5 $1.7 $(1.8) $(1.2)
====== ====== ====== ===== ==== ==== ===== =====
Other comprehensive income...................... $ 6.0 $ 3.9 $ 1.0 $ -- $-- $-- $ -- $ --
====== ====== ====== ===== ==== ==== ===== =====
</TABLE>
Assumed health care cost trend rates have a significant effect on the
amounts reported for the postretirement benefit plan. A one-percentage-point
change in assumed health care cost trend rates would have the following effects:
<TABLE>
<CAPTION>
1 PERCENTAGE 1 PERCENTAGE
POINT INCREASE POINT DECREASE
-------------- --------------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Effect on total of service and interest cost components.... $0.4 $(0.3)
Effect on postretirement benefit obligation................ 3.5 (3.1)
</TABLE>
12. ENVIRONMENTAL EXPOSURE
Environmental expenditures related to treatment or cleanup are expensed
when incurred, while environmental expenditures which extend the life of the
property or prevent future contamination are capitalized in accordance with
generally accepted accounting principles. Liabilities for these expenditures are
recorded when it is probable that obligations have been incurred and the amounts
can be reasonably estimated, based on
63
<PAGE> 69
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
current law and existing technologies. Environmental accruals are recorded at
undiscounted amounts and exclude claims for recoveries from insurance or other
third parties.
The Company generates and disposes of hazardous and non-hazardous waste in
its current operations as well as formerly owned operations and is subject to
increasingly stringent Federal, state, local, provincial and international
environmental regulations. The Company has identified seven sites currently
subject to environmental response actions or on the Superfund National
Priorities List or state superfund lists, at which it is or may be liable for
remediation costs associated with alleged contamination or for violation of
environmental requirements. Certain Federal legislation imposes joint and
several liability for the remediation of various sites; consequently, the
Company's ultimate environmental liability may include costs relating to other
parties in addition to costs relating to its own activities at each site. In
addition, the Company is or may be liable for certain environmental remediation
matters involving existing or former facilities.
In March 1994, the Company sold its interest in the Wilmington, California
field and the Harbor Cogeneration Plant to the Port of Long Beach, California.
As part of the Wilmington sales agreement, the Company agreed to participate
with the Port of Long Beach in funding environmental remediation and site
preparation, as specified by the Port of Long Beach, up to a maximum of $105.5
million. As a result, a provision of $50.5 million for future environmental
costs and $55.0 million for future site preparation costs was established ($87.8
million in total remaining at December 31, 1999) and is categorized as other
current liabilities and long-term liabilities (see Note 14).
As of December 31, 1999 and 1998, liabilities totaling $65.2 million and
$74.7 million, respectively, had been accrued for future costs of all sites
where the Company's obligation is probable and where such costs reasonably can
be estimated; however, the ultimate cost could be lower or higher. This accrual
includes future costs for remediation and restoration of sites, as well as for
ongoing monitoring costs, but excludes any anticipated recoveries from third
parties. The accrual also includes $34.1 million for the obligation to
participate in the remediation of the Wilmington field properties. Cost
estimates were based on information available for each site, financial viability
of other Potentially Responsible Parties ("PRPs") and existing technology, laws
and regulations. The Company believes that it has accrued adequately for its
share of costs at sites subject to joint and several liabilities. The ultimate
liability for remediation is difficult to determine with certainty because of
the number of PRPs involved, site-specific cost sharing arrangements with other
PRPs, the degree of contamination by various wastes, the scarcity and quality of
volumetric data related to many of the sites and the speculative nature of
remediation costs.
Anticipated payments of environmental liabilities at December 31, 1999,
which will be funded by cash generated by operations, are as follows:
<TABLE>
<CAPTION>
AT DECEMBER 31, 1999
---------------------
(MILLIONS OF DOLLARS)
<S> <C>
2000...................................................... $17.0
2001...................................................... 13.2
2002...................................................... 12.5
2003...................................................... 10.0
2004...................................................... 8.0
Thereafter................................................ 4.5
-----
Total........................................... $65.2
=====
</TABLE>
The Company also is involved in reducing emissions, spills and migration of
hazardous materials. Remediation of identified sites and control of
environmental exposures required spending of $11.6 million in 1999 and $17.0
million in 1998. In 2000, the Company anticipates spending a total of $19
million for remediation, control and prevention. Based on current rules and
regulations, management does not expect
64
<PAGE> 70
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
future environmental obligations to have a material impact on the results of
operations, cash flows or financial condition of the Company.
13. COMMITMENTS AND CONTINGENCIES
The Company was a party to several long-term firm gas transportation
agreements that supported the gas marketing program within the GPM business
segment which was sold to Duke. Most of the GPM business segment's firm
long-term transportation contracts were transferred to Duke in the GPM
Disposition. As part of the GPM Disposition, the Company and Duke agreed that
the Company will keep Duke whole on certain transportation contracts
("keep-whole agreement"). The Company will pay Duke if transportation market
values fall below the contract transportation rates, while Duke agreed to pay
the Company if the market value exceeds the contract transportation rates. This
keep-whole agreement will be in effect until the earlier of (i) each contract's
expiration date, or (ii) March 2009. Transportation contracts transferred to
Duke in the GPM Disposition and included in the keep-whole agreement with Duke
relate to various pipelines. The significant contracts covered by the keep-whole
agreement include: (i) an agreement with Texas Gas Transmission Corporation for
a transportation rate of $0.331 per MMBtu for 90 MMBtud of gas from Carthage,
Texas to Lebanon, Ohio expiring October 31, 2008; (ii) an agreement with Pacific
Gas Transmission ("PGT") for a transportation rate of $0.328 per MMBtu for 25
MMBtud of gas from Kingsgate, British Columbia to the California/Oregon border
expiring October 31, 2023; and (iii) a second agreement with PGT expiring
October 31, 2023 for 106 MMBtud of which 47 MMBtud will expire on October 31,
2007. The keep-whole agreement excludes 45 MMBtud of the PGT amount through
October 31, 2002 then 20 MMBtud through the end of the contract.
The Company retained a contract with Kern River Gas Transportation Company
("Kern River") which expires on May 31, 2007. Under the transportation
agreement, the Company has the right to transport 75 MMcfd of gas on the Kern
River system. The current transportation rate is $0.69 per Mcf. This rate can
change based on Kern River's cost of service and upon rate regulation policies
of the FERC. The Company is a party to an additional agreement under which it
may acquire in 2001, at its option, an additional 25 MMcfd of transportation
rights on the Kern River system beginning in 2002. As a result of the GPM
Disposition, the Company entered into an agreement whereby Duke would operate
and handle volume nominations related to the Company's contract with Kern River.
Currently, Duke is utilizing the Company's volume transportation rights under
the Kern River contract and paying the Company market rates.
Included in the Consolidated Statements of Financial Position of the
Company is a reserve for the estimated fair value of the difference between the
total rate under the firm transportation agreements and estimated market rates
through March 2009. The reserve, which is included in other current liabilities
and other long-term liabilities, was $43.8 million and $81.8 million at December
31, 1999 and $17.5 million and $71.2 million at December 31, 1998, respectively.
The Company may adjust its reserve based on changes in current quoted future
market rates or estimated long-term rates. Such adjustments could be
significant. Management believes its reserves are adequate; however, at December
31, 1999, if the Company had used quoted future market rates at December 31,
1999 to estimate the long-term portion of the reserve discounted at 10%, the
Company would have recorded an additional reserve of $41.3 million for the firm
transportation commitment period.
65
<PAGE> 71
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Anticipated discounted and undiscounted payments for firm transportation
commitment at December 31, 1999, which will be funded by cash generated by
operations, are as follows:
<TABLE>
<CAPTION>
UNDISCOUNTED DISCOUNTED
------------ ----------
(MILLIONS OF DOLLARS)
<S> <C> <C>
2000.................................................. $ 43.8 $ 43.8
2001.................................................. 17.0 14.8
2002.................................................. 15.6 12.3
2003.................................................. 17.8 12.8
2004.................................................. 24.4 15.9
Thereafter............................................ 50.0 26.0
------ ------
Total....................................... $168.6 $125.6
====== ======
</TABLE>
In February 2000, the Company entered into a $70 million contract with
Noble Drilling (U.S.) Inc. for the services of a semisubmersible drilling rig
designed for operations in water depths up to 5,000 feet. Under this agreement,
the Company has a commitment to use the rig for 15 months over a five-year
period commencing January 1, 2000.
In connection with the disposition of significant pipeline, refining and
producing property assets, the Company has made certain representations and
warranties relating to the assets sold (covering, among other matters, the
condition and capabilities of certain assets and compliance with environmental
and other laws) and provided certain indemnities with respect to liabilities
associated with such assets. The Company has been advised of possible claims
which may be asserted by the purchasers of certain disposed assets for alleged
breaches of representations and warranties and under certain indemnities.
Certain claims related to compliance with environmental laws remain pending. In
addition, as some of the representations, warranties, and indemnities related to
some of the disposed assets have not expired, further claims may be made against
the Company. While no assurance can be given as to the ultimate outcome of these
claims, the Company does not expect these matters to have a material adverse
effect on its results of operations, cash flows or consolidated financial
condition.
The Company, through one of its affiliates, is a party to a lease agreement
("base lease") for the leveraged lease financing of the Corpus Christi West
Plant Refinery ("West Plant") with an initial term expiring December 31, 2003,
and successive renewal periods lasting through January 31, 2011. At the
conclusion of the initial term of the base lease, any renewal period or January
31, 2011, the Company has the right to purchase the West Plant at the fair
market sales value. In connection with the sale by the Company of its refining
business in 1987 and 1989, the West Plant was subleased to CITGO Petroleum
Corporation ("CITGO") with sublease payments during the initial term equal to
the Company's base lease payments and during any renewal period equal to the
lesser of the base lease rental, which will be tied to the fair market rental
value, or $5 million annually. Additionally, CITGO has the option under the
sublease to purchase the West Plant from the Company at the conclusion of the
initial term or any renewal term at the fair market sales value, or on January
31, 2011 at a nominal price. If the fair market rental value of the base lease
during any renewal term exceeds CITGO's maximum obligation under the sublease,
or if CITGO purchases the West Plant on January 31, 2011 and the fair market
sales value of the West Plant is greater than the purchase amount specified in
the sublease, the Company will be obligated to pay the excess amounts. The
Company is unable at this time to determine the fair market rental value or the
fair market sales value of the West Plant, but will periodically evaluate the
potential effect of the obligation.
There are lawsuits pending against the Company and certain of its
subsidiaries which are described in Part I, Item 3 -- "Legal Proceedings" in
this Annual Report on Form 10-K. The Company intends to defend vigorously
against these lawsuits as well as any similar lawsuits. In the opinion of
management of the
66
<PAGE> 72
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Company, the outcome of these matters should not have a materially adverse
effect on results of operations, cash flows or consolidated financial condition.
The Company is a defendant in a number of lawsuits and is involved in
governmental proceedings arising in the ordinary course of business, including,
but not limited to, royalty claims, contract claims and environmental claims.
The Company has also been named as a defendant in various personal injury
claims, including numerous claims by employees of third party contractors
alleging exposure to asbestos and asbestos-containing materials while working at
the Corpus Christi refinery, which the Company sold in segments in 1987 and
1989. While the Company's management cannot predict the outcome of such
litigation and other proceedings, management does not expect these matters to
have a materially adverse effect on the consolidated results of operations,
financial condition or cash flows of the Company.
14. OTHER CURRENT AND LONG-TERM LIABILITIES
Other current liabilities include the following:
<TABLE>
<CAPTION>
AS OF DECEMBER 31
----------------------
1999 1998
--------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Interest payable............................................ $ 40.6 $ 35.7
Short-term firm transportation commitments (Note 13)........ 43.8 17.5
Environmental (Note 12)..................................... 16.9 17.7
Dividends................................................... 12.4 12.4
Other....................................................... 72.1 74.2
------ ------
Total other current liabilities................... $185.8 $157.5
====== ======
</TABLE>
Other long-term liabilities include the following:
<TABLE>
<CAPTION>
AS OF DECEMBER 31
----------------------
1999 1998
--------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Long-term firm transportation commitments (Note 13)......... $ 81.8 $ 71.2
Abandonment provision....................................... 70.7 58.1
Wilmington field site preparation........................... 53.7 53.7
Environmental (Note 12)..................................... 48.3 57.2
Equity investment -- Black Butte(a)......................... 38.6 37.8
Deferred compensation....................................... 19.6 25.9
Litigation and contingencies (Note 13)...................... 25.5 23.4
Deferred revenue............................................ 15.8 9.4
Other....................................................... 47.1 51.4
------ ------
Total other long-term liabilities................. $401.1 $388.1
====== ======
</TABLE>
- ---------------
(a) Black Butte
The Company has a 50% ownership interest in Black Butte Coal Company and
R-K Leasing Company ("Black Butte"), partnerships which operate a surface coal
mine complex in southwestern Wyoming. The
67
<PAGE> 73
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Company accounts for these partnerships under the equity method of accounting.
Summarized financial information for Black Butte is as follows:
<TABLE>
<CAPTION>
AS OF AND FOR YEARS ENDED
DECEMBER 31,
---------------------------
1999 1998 1997
------- ------- -------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Current assets............................................. $ 26.9 $ 30.4
Non-current assets......................................... 16.5 26.2
Current liabilities........................................ 18.4 21.0
Non-current liabilities and equity......................... 25.0 35.7
Sales...................................................... $216.1 $254.5 $159.7
Operating income........................................... 148.4 183.4 112.4
Partners' income........................................... 149.0 183.2 113.6
Cash distributions to partners -- net...................... 80.5 98.5 65.8
</TABLE>
During 1999 and 1998, Black Butte's sales to its largest customer under a
coal supply contract accounted for $73.4 million and $79.3 million of the
Company's consolidated operating income, respectively. This coal supply contract
will terminate by the end of 2000. Although Black Butte continues to seek new
buyers for its low-sulfur coal, its mining costs are considerably higher than
the mining costs for competing supplies. The Company does not expect to be able
to replace the operating income currently received under the contract with
incremental coal sales after 2000.
In addition, Black Butte provides an accrual for reclamation of mined
properties, based on the estimated cost of restoration of such properties in
compliance with laws governing strip mining. Accrued reclamation costs for Black
Butte as of December 31, 1999 and 1998 were $54.6 million and $52.0 million,
respectively, of which the Company's share is $27.3 million and $26 million,
respectively. Anticipated cash expenditures for this reclamation liability are
expected to be incurred in years beginning after 2004.
A supplier of coal to Black Butte has been assessed by the Minerals
Management Service of the United States Department of the Interior for
underpayment of royalties and the State of Montana Department of Revenue for
underpayment of production taxes related to coal previously sold to Black Butte.
The supplier is contesting these claims; however, should the claims be
successful, the supplier will claim reimbursement from Black Butte. In 1998, the
Courts ruled in favor of the State of Montana. The supplier is appealing to the
Montana State Supreme Court, however, the Company recorded $15.2 million as its
proportionate share of the Montana Department of Revenue assessment related to
coal production taxes. The Company's proportionate share of the liability for
underpaid royalties and interest to the Minerals Management Service of the
United States Department of the Interior, if any, could range from zero to $6.7
million.
15. SHAREHOLDERS' EQUITY
Stock Option and Retention Stock Plans. Pursuant to the Company's stock
option and retention stock plans, 11,062,582 and 5,999,439 shares of Common
Stock were available for grant to employees and directors at the end of December
31, 1999 and 1998, respectively. In May 1999, the Company's shareholders
approved a 7.5 million increase in the number of shares available for grants and
awards to employees and directors. Shares may either be granted as options to
purchase Common Stock or as awards of retention stock. Options to purchase
Common Stock under the plans are generally granted with an exercise price equal
to the fair market value at the date of grant and are exercisable for a period
of up to 10 years from grant date. Option grants have been made to directors,
officers and employees and vest over periods up to 10 years from the grant date.
Retention stock is awarded under the plans to eligible employees, subject to
forfeiture if employment
68
<PAGE> 74
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
terminates during the prescribed retention period, generally one to five years
from grant, subject to accelerated vesting in some situations.
In the first quarter of 1999, options covering 1,171,439 shares of Company
common stock were granted to directors, officers and certain non-officer
executives of the Company, each with an exercise price of $9.44 per share, a
one-year vesting period and a ten-year term. In addition, 1,474,439 shares of
retention stock were awarded to officers and certain non-officer executives with
a vesting schedule of one-third per year over a three-year period commencing on
the first anniversary of the award date, subject to accelerated vesting upon the
achievement of certain Company common stock price objectives. These stock price
objectives were achieved in April and May 1999, resulting in the acceleration of
vesting of all such shares of retention stock. Of the Company's $17.0 million
compensation expense in 1999 that was recorded for retention stock, $14.8
million was recorded in connection with the vesting of the January 1999
retention stock awards.
The status of the Company's stock-based compensation programs is as
follows:
<TABLE>
<CAPTION>
WEIGHTED
COMPANY AVERAGE
SHARES EXERCISE PRICE
---------- --------------
<S> <C> <C>
Stock options:
Balance at December 31, 1996................................ 5,216,074 $19.97
Granted................................................... 1,111,750 25.63
Exercised................................................. (351,723) 16.05
Expired/surrendered....................................... (91,615) 24.75
----------
Balance at December 31, 1997................................ 5,884,486 21.20
Granted................................................... 2,951,375 17.01
Exercised................................................. (57,487) 9.49
Expired/surrendered....................................... (207,635) 15.18
----------
Balance at December 31, 1998................................ 8,570,739 19.84
Granted................................................... 2,459,900 12.28
Exercised................................................. (271,999) 12.24
Expired/surrendered....................................... (1,818,375) 18.27
----------
Balance at December 31, 1999................................ 8,940,265 18.32
==========
Exercisable December 31:
1997...................................................... 3,853,035 $18.72
1998...................................................... 4,496,736 19.93
1999...................................................... 4,925,741 20.47
</TABLE>
<TABLE>
<CAPTION>
REGULAR
----------
<S> <C>
Retention stock:
Unvested at December 31, 1996............................... 1,204,562
Awarded................................................... 209,114
Vested.................................................... (376,295)
Forfeited, surrendered and other.......................... (34,693)
----------
Unvested at December 31, 1997............................... 1,002,688
Awarded................................................... 45,580
Vested.................................................... (531,951)
Forfeited, surrendered and other.......................... (19,200)
----------
Unvested at December 31, 1998............................... 497,117
Awarded................................................... 1,792,257
Vested.................................................... (1,764,776)
Forfeited, surrendered and other.......................... (188,194)
----------
Unvested at December 31, 1999............................... 336,404
==========
</TABLE>
69
<PAGE> 75
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Weighted-average fair value on the dates of option grants and retention
share awards:
<TABLE>
<CAPTION>
RETENTION
OPTIONS(a) SHARES(b)
---------- ---------
<S> <C> <C>
1997........................................................ $8.74 $25.63
1998........................................................ 7.00 17.01
1999........................................................ 7.05 10.09
</TABLE>
- ---------------
(a) Calculated in accordance with the Black-Scholes option pricing model, using
the following weighted average assumptions:
<TABLE>
<CAPTION>
1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
Expected volatility......................................... 61% 51% 28%
Expected dividend yield..................................... 1.59% 2.25% 0.8%
Expected weighted average option term....................... 8 years 5 years 4 years
Risk-free rate of return.................................... 6.4% 4.6% 5.7%
</TABLE>
(b) Represents market value on grant date.
Options to purchase Common Stock were as follows:
<TABLE>
<CAPTION>
AS OF DECEMBER 31, 1999
--------------------------------------------------------
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
--------------------------------- --------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
NUMBER OF YEARS TO EXERCISE NUMBER OF EXERCISE
RANGE OF EXERCISE PRICES SHARES EXPIRATION PRICE SHARES PRICE
- ------------------------ --------- ---------- -------- --------- --------
<S> <C> <C> <C> <C> <C>
$ 8.79 -- $15.78................. 3,687,117 5.9 $13.58 1,518,420 $14.97
$17.04 -- $20.94................. 2,936,389 3.4 17.74 1,612,450 18.32
$22.50 -- $29.44................. 2,316,759 6.1 26.62 1,794,871 27.06
--------- ---------
$ 8.79 -- $29.44................. 8,940,265 5.1 18.32 4,925,741 20.47
========= =========
</TABLE>
Since the Company applies the intrinsic value method in accounting for its
stock option and retention stock plans, it generally records no compensation
cost for its stock option plans. This method calculates compensation expense on
the measurement date (usually the date of grant or award) as the excess of the
current market price of the underlying common stock of the Company over the
amount the employee is required to pay for the shares, if any. The expense is
recognized over the vesting period of the grant or award. Compensation cost
recognized relating to retention stock was $17.0 million, $6.5 million and $11.6
million in 1999, 1998 and 1997, respectively. Approximately $14.8 million of the
$17.0 million 1999 compensation costs was related to the vesting of the January
1999 retention stock awards. If compensation cost for the Company's stock option
plan had been determined based on the fair value at the grant dates for awards
under the plan, the Company's net income would have been reduced by $26.7
million in 1999, $13.8 million in 1998 and $8.0 million in 1997. Basic and
diluted earnings per share would have been reduced by $0.11 per share in 1999,
$0.06 per share in 1998 and $0.03 per share in 1997.
70
<PAGE> 76
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Earnings Per Share. Basic earnings per share ("EPS") excludes dilution and
is computed by dividing income available to common shareholders by the
weighted-average number of common shares outstanding for the period. Diluted EPS
reflects the potential dilution that could occur if securities or other
contracts to issue common stock were exercised or converted into common stock.
The reconciliation between basic earnings per share and diluted earnings per
share is as follows:
<TABLE>
<CAPTION>
AVERAGE PER
INCOME SHARES SHARE
--------------------- ---------- ------
(MILLIONS OF DOLLARS) (MILLIONS)
<S> <C> <C> <C>
FOR THE YEAR ENDED DECEMBER 31, 1999
Basic EPS
Net income.................................... $ 225.8 249.0 $ 0.91
Less: Income from discontinued operations..... 133.2 -- 0.54
Income from extraordinary gain.......... 3.4 -- 0.01
------- ------
Income from continuing operations available to
common shareholders........................ 89.2 -- 0.36
Effect of dilutive options...................... -- 0.2 --
------- ----- ------
Diluted EPS
Income from continuing operations available to
Common shareholders plus assumed
conversion................................. $ 89.2 249.2 $ 0.36
======= ===== ======
FOR THE YEAR ENDED DECEMBER 31, 1998
Basic EPS
Net loss...................................... $(898.7) 247.7 $(3.63)
Less: Loss from discontinued operations....... (15.6) -- (0.06)
------- ------
Loss from continuing operations available to
common shareholders........................ (883.1) -- (3.57)
Effect of dilutive options (a).................. -- -- --
------- ----- ------
Diluted EPS
Loss from continuing operations available to
Common shareholders plus assumed
conversion................................. $(883.1) 247.7 $(3.57)
======= ===== ======
FOR THE YEAR ENDED DECEMBER 31, 1997
Basic EPS
Net Income.................................... $ 333.0 250.1 $ 1.33
Less: income from discontinued operations..... 29.9 -- 0.12
------- ------
Income from continuing operations available to
common shareholders........................ 303.1 -- 1.21
Effect of dilutive options...................... -- 0.8 --
------- ----- ------
Diluted EPS
Income from continuing operations available to
Common shareholders plus assumed
conversion................................. $ 303.1 250.9 $ 1.21
======= ===== ======
</TABLE>
- ---------------
(a) Options outstanding, as discussed above, have been excluded from the 1998
calculation of diluted earnings per share due to anti-dilution.
71
<PAGE> 77
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Employee Stock Ownership Plan. Effective January 2, 1997, the Company
instituted an employee stock ownership plan ("ESOP") for eligible U.S.
employees. The ESOP purchased 3.7 million shares or $107.3 million of newly
issued common stock (the "ESOP Shares") from the Company, to be used to fund the
Company's matching obligation under its 401(k) Thrift Plan. All domestic regular
employees of the Company are eligible to participate in the ESOP.
The ESOP Shares, which are held in trust, were purchased with the proceeds
from a 30-year loan from the Company. Such shares were pledged as collateral for
the loan. As loan payments are made, shares are released from collateral, based
on the proportion of debt service paid. Scheduled principal and interest
requirements are $5.9 million annually and will be funded with dividends paid on
the unallocated ESOP Shares and with cash contributions from the Company.
Principal or interest prepayments may be made to ensure that the Company's
minimum matching obligation is met.
Shares held by the ESOP are included in the computation of earnings per
share as such ESOP Shares are released from collateral. Releases of ESOP Shares
will be allocated to participants' accounts and will be charged to compensation
expense at the fair market value of the shares on the date of the employer
match. Dividends on allocated ESOP Shares will be recorded as a reduction of
retained earnings; dividends on unallocated ESOP Shares will be recorded as a
reduction of the principal or accrued interest on the loan.
As of December 31, 1999, allocated and unallocated shares in the ESOP were
958,472 and 2,741,528, respectively. As of December 31, 1998, allocated and
unallocated shares were 483,216 and 3,216,784, respectively. The fair value of
unallocated ESOP shares at December 31, 1999 and 1998 was $35.0 million and
$29.2 million, respectively. During 1999, 1998 and 1997, compensation cost
related to the allocation of ESOP shares to participants' accounts was $4.4
million, $6.3 million and $5.3 million, respectively.
Preferred Stock and Shareholder Rights. The Company has 100 million shares
of no-par-value preferred stock authorized, none of which are outstanding. On
October 28, 1996, the Company's Board of Directors designated 3,000,000 of the
authorized preferred shares as non-redeemable Series A Junior Participating
Preferred Shares (the "Series A Preferred Stock"). Upon issuance, each
one-hundredth of a share of the Series A Preferred Stock will have dividend and
voting rights approximately equal to those of one share of the Company's common
stock. In addition, on October 28, 1996, the Board of Directors adopted a
shareholder rights plan with a "flip-in" threshold of 15% to ensure that all
shareholders of the Company receive fair value for their Common Stock in the
event of any proposed takeover of the Company and to guard against the use of
coercive tactics to gain control of the Company without offering fair value to
the Company's shareholders ("Rights Agreement"). Under the Rights Agreement, the
Company declared a dividend of one right ("Right") for each outstanding share of
common stock to shareholders of record on November 7, 1996. Under certain
limited conditions as defined in the Rights Agreement, each Right entitles the
registered holder to purchase from the Company one one-hundredth of a share of
Series A Preferred Stock at $135 subject to adjustment. The Rights are not
exercisable until the Distribution Date (as defined in the Rights Agreement)
which will occur upon the earlier of (i) ten days following a public
announcement that an Acquiring Person (as defined in the Rights Agreement) has
acquired beneficial ownership of 15% or more of the Company's outstanding Common
Stock (the "Stock Acquisition Date") or (ii) ten business days following the
commencement of a tender offer or exchange offer that would result in a person
or group owning 15% or more of the Company's outstanding Common Stock.
The Rights have certain anti-takeover effects. The Rights will cause
substantial dilution to a person or group that attempts to acquire the Company
without conditioning the offer on a substantial number of Rights being redeemed.
In the event that at any time following the Stock Acquisition Date certain
events occur as defined in the Rights Agreement, each holder of a Right, except
the Acquiring Person, will thereafter have the right to receive, upon exercise,
Company Common Stock or common stock of the acquiring company, as the case may
be, having a value equal to two times the exercise price of the Right.
72
<PAGE> 78
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Rights should not interfere with any merger or other business
combination approved by the Company since the Board of Directors may, at its
option, at any time prior to the close of business on the earlier of the tenth
day following the Stock Acquisition Date or October 28, 2006, redeem all but not
less than all of the then outstanding Rights at $0.01 per Right. The Rights
expire on October 28, 2006, and do not have voting power or dividend privileges.
During 1999, the Company repurchased 869,681 shares at a cost of $12.6
million primarily in connection with the Company's retention stock program. Also
during 1999, the Company reissued 259,605 shares of repurchased stock for $3.3
million to settle deferred compensation liabilities for several former
executives. During 1998, the Company repurchased 837,500 shares at a cost of
$18.6 million and 449,788 shares at a cost of $8.1 million, in connection with
the Company's retention stock and options, respectively.
Other Comprehensive Income. The Company's other comprehensive income is as
follows:
<TABLE>
<CAPTION>
TAX
BEFORE-TAX BENEFIT NET-OF-TAX
AMOUNT (EXPENSE) AMOUNT
---------- ----------- ----------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
1999
Foreign currency translation adjustment................ $ 49.6 $(27.1) $ 22.5
Minimum pension liability adjustment................... (6.0) -- (6.0)
------- ------ ------
Other comprehensive income............................. $ 43.6 $(27.1) $ 16.5
======= ====== ======
1998
Foreign currency translation adjustment................ $(149.6) $ 82.5 $(67.1)
Minimum pension liability adjustment................... (3.9) -- (3.9)
------- ------ ------
Other comprehensive income (loss)...................... $(153.5) $ 82.5 $(71.0)
======= ====== ======
</TABLE>
16. OTHER INCOME -- NET
Other income (expense) -- net consists of the following:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED
DECEMBER 31,
------------------------
1999 1998 1997
------ ------ ------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Foreign currency gain (loss) -- net (Note 5)............... $ 44.2 $(35.5) $ --
Firm transportation contract valuation..................... (43.4) -- --
Interest income............................................ 30.5 11.1 4.4
Insurance settlement proceeds.............................. -- 3.3 10.0
Excess reserve releases.................................... -- -- 23.0
Gain (loss) on sales of investment......................... -- (1.4) 7.2
Pennzoil acquisition costs(a).............................. -- (2.0) (17.8)
Interest rate lock cost (Note 5)........................... -- (14.3) --
Other -- net............................................... 0.4 (6.5) (2.3)
------ ------ ------
Total other income -- net........................ $ 31.7 $(45.3) $ 24.5
====== ====== ======
</TABLE>
- ---------------
(a) Related to cost incurred with the unsuccessful takeover attempt of Pennzoil
Company.
73
<PAGE> 79
UNION PACIFIC RESOURCES GROUP INC.
SUPPLEMENTARY INFORMATION
(UNAUDITED)
A. PROVED RESERVES
The following table reflects estimated quantities of proved oil and gas
reserves, which have been prepared by the Company's petroleum engineers. The
Company considers such estimates to be reasonable; however, there are numerous
uncertainties inherent in estimating quantities of proved reserves, including
many factors beyond the control of the Company. Reserve engineering is a
subjective process which is dependent on the quality of available data and on
engineering and geological interpretation and judgment. Such reserve estimates
are subject to change over time as additional information becomes available.
<TABLE>
<CAPTION>
UNITED OTHER
STATES CANADA INTERNATIONAL WORLDWIDE
------- -------- ------------- ---------
<S> <C> <C> <C> <C>
NATURAL GAS (BCF)(a): 1997
Beginning of year........................... 2,300.8 77.6 -- 2,378.4
Revisions of previous estimates............. 13.4 (4.1) -- 9.3
Extensions, discoveries and other
additions................................ 574.5 13.8 -- 588.3
Purchases of reserves-in-place.............. 54.8 -- -- 54.8
Sales of reserves-in-place.................. (3.5) -- -- (3.5)
Production.................................. (400.8) (6.2) -- (407.0)
------- -------- ----- -------
Total proved, end of year........... 2,539.2 81.1 -- 2,620.3
======= ======== ===== =======
Proved developed reserves........... 2,156.5 60.5 -- 2,217.0
======= ======== ===== =======
NATURAL GAS (BCF): 1998
Beginning of year........................... 2,539.2 81.1 -- 2,620.3
Revisions of previous estimates............. 81.8 13.6 -- 95.4
Extensions, discoveries and other
additions................................ 276.7 100.7 10.0 387.4
Purchases of reserves-in-place.............. 210.4 998.3 37.2 1,245.9
Sales of reserves-in-place.................. (286.8) (97.3) -- (384.1)
Production.................................. (420.6) (102.6) (2.6) (525.8)
------- -------- ----- -------
Total proved, end of year........... 2,400.7 993.8 44.6 3,439.1
======= ======== ===== =======
Proved developed reserves........... 2,079.3 853.9 34.7 2,967.8
======= ======== ===== =======
NATURAL GAS (BCF): 1999
Beginning of year........................... 2,400.7 993.8 44.6 3,439.1
Revisions of previous estimates............. (45.1) (21.6) (13.3) (80.0)
Extensions, discoveries and other
additions................................ 280.5 147.2 5.5 433.2
Purchases of reserves-in-place.............. 11.8 1.5 -- 13.3
Sales of reserves-in-place.................. (13.4) (34.7) -- (48.1)
Production.................................. (362.5) (101.4) (2.8) (466.7)
------- -------- ----- -------
Total proved, end of year........... 2,272.0 984.8 34.0 3,290.8
======= ======== ===== =======
Proved developed reserves........... 1,890.7 770.9 29.9 2,691.5
======= ======== ===== =======
</TABLE>
74
<PAGE> 80
<TABLE>
<CAPTION>
UNITED OTHER
STATES CANADA INTERNATIONAL WORLDWIDE
------- -------- ------------- ---------
<S> <C> <C> <C> <C>
NATURAL GAS LIQUIDS (MMBBL)(a): 1997
Beginning of year........................... 100.6 6.9 -- 107.5
Revisions of previous estimates............. 1.1 0.8 -- 1.9
Extensions, discoveries and other
additions................................ 21.5 0.1 -- 21.6
Purchases of reserves-in-place.............. 0.9 -- -- 0.9
Sales of reserves-in-place.................. -- -- -- --
Production.................................. (13.2) (0.8) -- (14.0)
------- -------- ----- -------
Total proved, end of year........... 110.9 7.0 -- 117.9
======= ======== ===== =======
Proved developed reserves........... 96.3 7.0 -- 103.3
======= ======== ===== =======
NATURAL GAS LIQUIDS (MMBBL): 1998
Beginning of year........................... 110.9 7.0 -- 117.9
Revisions of previous estimates............. (10.1) 5.5 -- (4.6)
Extensions, discoveries and other
additions................................ 1.3 1.5 -- 2.8
Purchases of reserves-in-place.............. 2.7 18.2 -- 20.9
Sales of reserves-in-place.................. (29.6) (4.1) -- (33.7)
Production.................................. (10.4) (1.6) -- (12.0)
------- -------- ----- -------
Total proved, end of year........... 64.8 26.5 -- 91.3
======= ======== ===== =======
Proved developed reserves........... 54.9 24.0 -- 78.9
======= ======== ===== =======
NATURAL GAS LIQUIDS (MMBBL): 1999
Beginning of year........................... 64.8 26.5 -- 91.3
Revisions of previous estimates............. (2.4) (6.9) -- (9.3)
Extensions, discoveries and other
additions................................ 3.0 0.6 -- 3.6
Purchases of reserves-in-place.............. 0.4 -- -- 0.4
Sales of reserves-in-place.................. (0.4) (12.3) -- (12.7)
Production.................................. (9.6) (0.7) -- (10.3)
------- -------- ----- -------
Total proved, end of year........... 55.8 7.2 -- 63.0
======= ======== ===== =======
Proved developed reserves........... 53.6 6.2 -- 59.8
======= ======== ===== =======
CRUDE OIL, INCLUDING CONDENSATE (MMBBL): 1997
Beginning of year........................... 72.4 6.5 1.7 80.6
Revisions of previous estimates............. 4.9 0.2 -- 5.1
Extensions, discoveries and other
additions................................ 56.7 -- -- 56.7
Purchases of reserves-in-place.............. 5.8 -- -- 5.8
Sales of reserves-in-place.................. (0.1) -- -- (0.1)
Production.................................. (18.1) (0.6) (0.6) (19.3)
------- -------- ----- -------
Total proved, end of year........... 121.6 6.1 1.1 128.8
======= ======== ===== =======
Proved developed reserves........... 86.7 6.1 1.1 93.9
======= ======== ===== =======
CRUDE OIL, INCLUDING CONDENSATE (MMBBL): 1998
Beginning of year........................... 121.6 6.1 1.1 128.8
Revisions of previous estimates............. (6.7) (3.8) 1.8 (8.7)
Extensions, discoveries and other
additions................................ 12.6 4.9 16.7 34.2
Purchases of reserves-in-place.............. 14.3 114.9 142.6 271.8
Sales of reserves-in-place.................. (6.7) (12.9) -- (19.6)
Production.................................. (22.3) (12.9) (15.1) (50.3)
------- -------- ----- -------
Total proved, end of year........... 112.8 96.3 147.1 356.2
======= ======== ===== =======
Proved developed reserves........... 81.3 65.7 105.3 252.4
======= ======== ===== =======
</TABLE>
75
<PAGE> 81
<TABLE>
<CAPTION>
UNITED OTHER
STATES CANADA INTERNATIONAL WORLDWIDE
------- -------- ------------- ---------
<S> <C> <C> <C> <C>
CRUDE OIL, INCLUDING CONDENSATE (MMBBL): 1999
Beginning of year........................... 112.8 96.3 147.1 356.2
Revisions of previous estimates............. (10.7) (7.7) 16.9 (1.5)
Extensions, discoveries and other
additions................................ 8.7 15.0 2.0 25.7
Purchases of reserves-in-place.............. 0.1 -- 2.0 2.1
Sales of reserves-in-place.................. (0.4) (0.3) -- (0.7)
Production.................................. (15.9) (10.5) (16.3) (42.7)
------- -------- ----- -------
Total proved, end of year........... 94.6 92.8 151.7 339.1
======= ======== ===== =======
Proved developed reserves........... 64.6 60.1 92.1 216.8
======= ======== ===== =======
PROVED RESERVES EQUIVALENT, END OF 1997
(BCFE)(b)
Natural gas................................. 2,539.2 81.1 -- 2,620.3
Natural gas liquids......................... 665.4 42.0 -- 707.4
Crude oil, including condensate............. 729.6 36.6 6.6 772.8
------- -------- ----- -------
Total proved........................ 3,934.2 159.7 6.6 4,100.5
======= ======== ===== =======
Proved developed reserves........... 3,254.5 139.1 6.6 3,400.2
======= ======== ===== =======
PROVED RESERVES EQUIVALENT, END OF 1998
(BCFE)(b)
Natural gas................................. 2,400.7 993.8 44.6 3,439.1
Natural gas liquids......................... 388.8 159.0 -- 547.8
Crude oil, including condensate............. 676.8 577.8 882.6 2,137.2
------- -------- ----- -------
Total proved........................ 3,466.3 1,730.6 927.2 6,124.1
======= ======== ===== =======
Proved developed reserves........... 2,896.8 1,392.1 666.6 4,955.5
======= ======== ===== =======
PROVED RESERVES EQUIVALENT, END OF 1999
(BCFE)(B)
Natural gas................................. 2,272.0 984.8 34.0 3,290.8
Natural gas liquids......................... 334.8 43.2 -- 378.0
Crude oil, including condensate............. 567.6 556.8 910.2 2,034.6
------- -------- ----- -------
Total proved........................ 3,174.4 1,584.8 944.2 5,703.4
======= ======== ===== =======
Proved developed reserves........... 2,599.9 1,168.7 582.5 4,351.1
======= ======== ===== =======
</TABLE>
- ---------------
(a) Reserves at the end of 1997 include the plant share of equity gas processed
(natural gas and natural gas liquids, as appropriate, earned by gas
processing facilities through the processing of the Company's equity
production.
(b) Calculated using the ratio of one Bbl to six Mcf.
76
<PAGE> 82
B. DRILLING ACTIVITY
Drilling activity is summarized as follows:
<TABLE>
<CAPTION>
OTHER
UNITED STATES CANADA INTERNATIONAL WORLDWIDE
------------- ------ ------------- ---------
<S> <C> <C> <C> <C>
FOR THE YEAR ENDED DECEMBER 31, 1999(a)
Gross wells............................... 182 448 13 643
Gross productive wells.................... 163 430 7 600
Net wells:
Exploration............................. 7 49 2 58
Development............................. 97 330 4 431
--- --- -- ---
Total net wells................. 104 379 6 489
=== === == ===
Net productive wells:
Exploration............................. 2 41 -- 43
Development............................. 89 321 3 413
--- --- -- ---
Total net productive wells...... 91 362 3 456
=== === == ===
FOR THE YEAR ENDED DECEMBER 31, 1998
Gross wells............................... 318 273 45 636
Gross productive wells.................... 290 243 42 575
Net wells:
Exploration............................. 18 45 1 64
Development............................. 248 115 22 385
--- --- -- ---
Total net wells................. 266 160 23 449
=== === == ===
Net productive wells:
Exploration............................. 13 32 1 46
Development............................. 232 106 20 358
--- --- -- ---
Total net productive wells...... 245 138 21 404
=== === == ===
FOR THE YEAR ENDED DECEMBER 31, 1997
Gross wells............................... 811 6 -- 817
Gross productive wells.................... 714 6 -- 720
Net wells:
Exploration............................. 41 -- -- 41
Development............................. 521 4 -- 525
--- --- -- ---
Total net wells................. 562 4 -- 566
=== === == ===
Net productive wells:
Exploration............................. 19 -- -- 19
Development............................. 475 4 -- 479
--- --- -- ---
Total net productive wells...... 494 4 -- 498
=== === == ===
</TABLE>
- ---------------
(a) In addition, at December 31, 1999, 26 gross wells (17 net wells) were in
the process of being drilled.
77
<PAGE> 83
C. AVERAGE SALES PRICE AND COST
The average producing properties sales prices, after hedging results and
costs are set forth below:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED
DECEMBER 31,
------------------------
1999 1998 1997
------ ------ ------
<S> <C> <C> <C>
Natural gas sales price (per Mcf)
United States............................................ $ 1.90 $ 1.84 $ 2.01
Canada................................................... 1.62 1.35 1.58
Other international...................................... 1.09 1.39 --
Total.................................................... 1.83 1.74 2.00
Natural gas liquids sales price (per Bbl)
United States............................................ $11.02 $ 8.14 $11.57
Canada................................................... 10.07 6.12 5.41
Other international...................................... -- -- --
Total.................................................... 10.95 7.88 11.23
Crude oil sales price (per Bbl)
United States............................................ $12.56 $13.23 $18.37
Canada................................................... 9.21 8.55 19.85
Other international...................................... 12.76 8.09 16.90
Total.................................................... 11.81 10.48 18.36
Production cost (per Mcf)
United States............................................ $ 0.46 $ 0.51 $ 0.51
Canada................................................... 0.48 0.41 0.29
Other international...................................... 0.79 0.54 0.77
Total production cost.................................... 0.51 0.49 0.51
</TABLE>
78
<PAGE> 84
D. AVERAGE DAILY PRODUCTION AND SALES VOLUME
The average producing properties daily production and sales volume are set
forth below:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED
DECEMBER 31,
---------------------------
1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
Natural gas (MMcfd)
United States........................................... 993.1 1,152.8 1,090.9
Canada.................................................. 277.8 281.2 17.6
Other international..................................... 7.9 7.1 --
------- ------- -------
Total natural gas....................................... 1,278.8 1,441.1 1,108.5
======= ======= =======
Natural gas liquids (MBBld)
United States........................................... 26.4 28.8 30.0
Canada.................................................. 2.0 4.3 1.7
Other international..................................... -- -- --
------- ------- -------
Total natural gas liquids............................... 28.4 33.1 31.7
======= ======= =======
Crude oil (MBBld)
United States........................................... 43.5 61.0 49.2
Canada.................................................. 28.8 35.4 1.7
Other international..................................... 44.8 41.5 2.0
------- ------- -------
Total crude oil......................................... 117.1 137.9 52.9
======= ======= =======
Total producing properties (MMcfed)
United States........................................... 1,412.6 1,692.0 1,565.8
Canada.................................................. 462.4 519.3 38.3
Other international..................................... 276.6 255.7 11.6
------- ------- -------
Total producing properties.............................. 2,151.6 2,467.0 1,615.7
======= ======= =======
</TABLE>
E. ACREAGE AND WELLS
Oil and gas leasehold acreage is as follows(a):
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
--------------------------------------------------
OTHER
UNITED STATES CANADA INTERNATIONAL WORLDWIDE
------------- ------ ------------- ---------
(THOUSANDS OF ACRES)
<S> <C> <C> <C> <C>
1999
Gross developed........................... 2,266 1,618 554 4,438
Net developed............................. 1,391 942 135 2,468
Gross undeveloped......................... 2,038 5,297 5,777 13,112
Net undeveloped........................... 1,379 1,924 3,202 6,505
1998
Gross developed........................... 2,460 1,657 548 4,665
Net developed............................. 1,493 958 135 2,586
Gross undeveloped......................... 3,629 5,613 5,771 15,013
Net undeveloped........................... 2,469 2,185 3,194 7,848
</TABLE>
79
<PAGE> 85
Productive oil and gas wells are as follows:
<TABLE>
<CAPTION>
AS OF
DECEMBER 31,
1999
-------------
OIL GAS
----- -----
(WELLS)
<S> <C> <C>
Gross(b).................................................... 4,106 9,194
Net......................................................... 2,468 6,047
</TABLE>
- ---------------
(a) In addition, the Company has fee mineral ownership of approximately 9.4
million gross acres (8.5 million net acres), including 7.9 million gross
acres (7.7 million net acres) acquired through 19th century Congressional
Land Grant Acts. Substantial portions of this acreage are undeveloped and
are considered prospective for oil and gas.
(b) Approximately 2,265 are multiple completions, 2,011 of which are gas wells.
F. CAPITALIZED EXPLORATION AND PRODUCTION COSTS
Capitalized exploration and production costs are as follows(a):
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
-----------------------------------------------------
OTHER
UNITED STATES CANADA INTERNATIONAL WORLDWIDE
------------- --------- ------------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C>
1999
Proved properties..................... $ 1,243.3 $ 2,427.3 $1,100.5 $ 4,771.1
Unproved properties................... 257.1 271.6 454.6 983.3
Wells and related equipment........... 4,391.0 359.0 217.2 4,967.2
Uncompleted wells and equipment....... 75.6 3.4 -- 79.0
--------- --------- -------- ---------
Gross capitalized costs............. 5,967.0 3,061.3 1,772.3 10,800.6
Accumulated depreciation, depletion
and amortization.................... (3,676.8) (1,146.7) (609.7) (5,443.2)
--------- --------- -------- ---------
Net capitalized costs............... $ 2,290.2 $ 1,914.6 $1,162.6 $ 5,367.4
========= ========= ======== =========
1998
Proved properties..................... $ 1,103.3 $ 2,068.5 $1,047.6 $ 4,219.4
Unproved properties................... 396.8 389.2 455.5 1,241.5
Wells and related equipment........... 4,821.1 229.8 209.5 5,260.4
Uncompleted wells and equipment....... 142.7 -- -- 142.7
--------- --------- -------- ---------
Gross capitalized costs............. 6,463.9 2,687.5 1,712.6 10,864.0
Accumulated depreciation, depletion
and amortization.................... (3,603.2) (833.5) (438.5) (4,875.2)
--------- --------- -------- ---------
Net capitalized costs............... $ 2,860.7 $ 1,854.0 $1,274.1 $ 5,988.8
========= ========= ======== =========
</TABLE>
80
<PAGE> 86
G. COSTS INCURRED IN EXPLORATION AND DEVELOPMENT
Costs incurred (whether capitalized or expensed) in oil and gas property
acquisition, exploration and development activities are as follows:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
----------------------------------------------------
OTHER
UNITED STATES CANADA INTERNATIONAL WORLDWIDE
------------- -------- ------------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C>
1999
Costs incurred:
Proved acreage........................ $ 12.0 $ 0.8 $ 2.5 $ 15.3
Unproved acreage...................... 12.9 7.7 0.5 21.1
Exploration costs(a).................. 46.6 7.9 28.7 83.2
Development costs..................... 180.9 106.1 42.8 329.8
-------- -------- -------- --------
Total costs incurred(b)....... $ 252.4 $ 122.5 $ 74.5 $ 449.4
======== ======== ======== ========
1998
Costs incurred:
Proved acreage........................ $ 424.4 $1,733.7 $ 744.7 $2,902.8
Unproved acreage...................... 45.5 279.1 312.2 636.8
Exploration costs(a).................. 195.9 43.8 29.5 269.2
Development costs..................... 506.3 136.5 107.8 750.6
-------- -------- -------- --------
Total costs incurred(b)....... $1,172.1 $2,193.1 $1,194.2 $4,559.4
======== ======== ======== ========
1997
Costs incurred:
Proved acreage........................ $ 130.6 $ -- $ -- $ 130.6
Unproved acreage...................... 199.7 1.0 -- 200.7
Exploration costs(a).................. 231.9 5.0 -- 236.9
Development costs..................... 617.8 4.0 -- 621.8
-------- -------- -------- --------
Total costs incurred(b)....... $1,180.0 $ 10.0 $ -- $1,190.0
======== ======== ======== ========
</TABLE>
- ---------------
(a) Includes allocated exploration overhead costs of $17.9 million in 1999,
$24.2 million in 1998 and $23.5 million in 1997 and delay rentals of $8.3
million in 1999, $12.3 million in 1998 and $14.8 million in 1997.
(b) Excludes capital expenditures relating to discontinued operations of $33.7
million in 1999, $143.8 million in 1998 and $343.3 million in 1997.
81
<PAGE> 87
H. RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES(a)
The results of operations for producing activities is set forth below:
<TABLE>
<CAPTION>
OTHER
UNITED STATES CANADA INTERNATIONAL WORLDWIDE
------------- --------- ------------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C>
FOR THE YEAR ENDED DECEMBER 31, 1999
Revenues.............................. $ 1,062.4 $ 332.1 $ 212.5 $ 1,607.0
Production costs...................... (239.6) (81.7) (79.3) (400.6)
Exploration expenses.................. (148.7) (16.8) (102.4) (267.9)
Depreciation, depletion and
amortization........................ (558.0) (171.8) (86.2) (816.0)
--------- --------- ------- ---------
Total costs................. (946.3) (270.3) (267.9) (1,484.5)
--------- --------- ------- ---------
Pre-tax results....................... 116.1 61.8 (55.4) 122.5
Income taxes (benefit)................ 25.1 30.4 (18.4) 37.1
--------- --------- ------- ---------
Results of operations....... $ 91.0 $ 31.4 $ (37.0) $ 85.4
========= ========= ======= =========
FOR THE YEAR ENDED DECEMBER 31, 1998
Revenues.............................. $ 1,314.6 $ 259.2 $ 126.1 $ 1,699.9
Production costs...................... (317.0) (77.3) (50.0) (444.3)
Exploration expenses.................. (267.4) (25.3) (46.3) (339.0)
Depreciation, depletion and
amortization........................ (816.2) (915.3) (384.3) (2,115.8)
--------- --------- ------- ---------
Total costs................. (1,400.6) (1,017.9) (480.6) (2,899.1)
--------- --------- ------- ---------
Pre-tax results....................... (86.0) (758.7) (354.5) (1,199.2)
Income taxes (benefit)................ (48.3) (337.7) (95.0) (481.0)
--------- --------- ------- ---------
Results of operations....... $ (37.7) $ (421.0) $(259.5) $ (718.2)
========= ========= ======= =========
FOR THE YEAR ENDED DECEMBER 31, 1997
Revenues.............................. $ 1,337.3 $ 28.9 $ 12.0 $ 1,378.2
Production costs...................... (293.4) (4.1) (3.3) (300.8)
Exploration expenses.................. (197.6) (4.4) (2.7) (204.7)
Depreciation, depletion and
amortization........................ (481.7) (10.2) (7.4) (499.3)
--------- --------- ------- ---------
Total costs................. (972.7) (18.7) (13.4) (1,004.8)
--------- --------- ------- ---------
Pre-tax results....................... 364.6 10.2 (1.4) 373.4
Income taxes.......................... 108.9 -- -- 108.9
--------- --------- ------- ---------
Results of operations....... $ 255.7 $ 10.2 $ (1.4) $ 264.5
========= ========= ======= =========
</TABLE>
- ---------------
(a) General and administrative expenses, other income/expense and interest costs
have been excluded in computing these results of operations. Revenues
include net gains from sales of assets of $148.0 million in 1999, $139.6
million in 1998 and $18.3 million in 1997. Depreciation, depletion and
amortization includes asset impairments of $65.1 million in 1999, $1.2
billion in 1998 and $20.2 million in 1997.
82
<PAGE> 88
I. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATES TO PROVED
OIL AND GAS RESERVES
The standardized measure of discounted cash flows relating to oil and gas
reserves are set forth below:
<TABLE>
<CAPTION>
UNITED OTHER
STATES CANADA INTERNATIONAL TOTAL
------- ------- ------------- -------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C>
AS OF DECEMBER 31, 1999
Future cash inflows from sales of oil and
gas........................................ $ 7,897 $ 3,970 $2,314 $14,181
Future production and development costs...... (1,461) (1,189) (756) (3,406)
Future income taxes.......................... (1,872) (1,096) (302) (3,270)
------- ------- ------ -------
Future net cash flows........................ 4,564 1,685 1,256 7,505
10% annual discount.......................... (1,748) (668) (430) (2,846)
------- ------- ------ -------
Standardized measure of discounted future net
cash flows................................. $ 2,816 $ 1,017 $ 826 $ 4,659
======= ======= ====== =======
AS OF DECEMBER 31, 1998
Future cash inflows from sales of oil and
gas........................................ $ 6,210 $ 2,642 $1,128 $ 9,980
Future production and development costs...... (1,619) (998) (641) (3,258)
Future income taxes.......................... (942) (536) (55) (1,533)
------- ------- ------ -------
Future net cash flows........................ 3,649 1,108 432 5,189
10% annual discount.......................... (1,394) (405) (165) (1,964)
------- ------- ------ -------
Standardized measure of discounted future net
cash flows................................. $ 2,255 $ 703 $ 267 $ 3,225
======= ======= ====== =======
AS OF DECEMBER 31, 1997
Future cash inflows from sales of oil and
gas........................................ $ 8,822 $ 355 $ 15 $ 9,192
Future production and development costs...... (2,032) (55) (4) (2,091)
Future income taxes.......................... (1,953) (86) (4) (2,043)
------- ------- ------ -------
Future net cash flows........................ 4,837 214 7 5,058
10% annual discount.......................... (1,926) (85) (1) (2,012)
------- ------- ------ -------
Standardized measure of discounted future net
cash flows................................. $ 2,911 $ 129 $ 6 $ 3,046
======= ======= ====== =======
</TABLE>
83
<PAGE> 89
An analysis of changes in the standardized measure of discounted future net
cash flows follows:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
---------------------------------
1999 1998 1997
--------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Beginning of year....................................... $ 3,225 $ 3,046 $ 4,239
Changes due to current year operations:
Additions and discoveries less related production and
other costs........................................ 544 438 1,000
Sales of oil and gas -- net of production costs....... (1,146) (1,160) (1,078)
Development costs..................................... 330 751 622
Purchases of reserves-in-place........................ 37 1,712 125
Sales of reserves-in-place............................ (136) (245) (4)
Changes due to revisions in:
Price................................................. 2,772 (1,110) (2,452)
Development costs..................................... (97) (911) (427)
Quantity estimates.................................... (249) 34 87
Income taxes.......................................... (1,118) 232 639
Other................................................. 102 38 (289)
Discount accretion...................................... 395 400 584
------- ------- -------
End of year............................................. $ 4,659 $ 3,225 $ 3,046
======= ======= =======
</TABLE>
Future oil and gas sales and production and development costs have been
estimated using prices and costs in effect as of each year-end. Prices used to
estimate future oil and gas sales represent the closing price for trading in
December on the New York Mercantile Exchange adjusted for appropriate regional
price differentials. Such weighted average prices for 1999, 1998 and 1997 were
$2.50 per Mcfe, $1.63 per Mcfe and $2.24 per Mcfe, respectively. Future
production hedged as of year-end is included in future net revenues at the
hedged price. Such prices may vary significantly from actual prices realized by
the Company for its future production. Future net revenues were discounted to
present value at 10%, a uniform rate set by the Financial Accounting Standards
Board. Income taxes represent the tax effect (at statutory rates) of the
difference between the standardized measure values and tax bases of the
underlying properties at the end of the year.
Changes in the supply and demand for crude oil, natural gas and NGLs,
hydrocarbon price volatility, inflation, timing of production, reserve revisions
and other factors make these estimates inherently imprecise and subject to
substantial revision. As a result, these measures are not the Company's estimate
of future cash flows nor do these measures serve as an estimate of current
market value.
84
<PAGE> 90
J. SELECTED QUARTERLY DATA
Selected unaudited quarterly data are as follows:
<TABLE>
<CAPTION>
FOR THE 1999 QUARTERS ENDED(a)
-----------------------------------------------------------------------
MARCH 31, 1999 JUNE 30, 1999 SEPTEMBER 30, 1999 DECEMBER 31, 1999
-------------- ------------- ------------------ -----------------
(MILLIONS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
Operating revenues............... $ 415.1 $386.7 $ 463.1 $ 462.6
Operating income................. 59.3 23.8 38.6 14.1
Income from continuing
operations..................... 42.3 15.3 20.7 10.9
Net income....................... 175.5 15.3 20.7 14.3
Per share:
Net income -- continuing
operations.................. $ 0.17 $ 0.06 $ 0.08 $ 0.04
Net income -- discontinued
operations.................. 0.54 -- -- --
Dividends...................... 0.05 0.05 0.05 0.05
Common stock price:
High........................... 12.1875 17.0 19.375 16.1250
Low............................ 7.6875 10.75 14.4375 10.9375
</TABLE>
<TABLE>
<CAPTION>
MARCH 31, 1999 JUNE 30, 1999 SEPTEMBER 30, 1999 DECEMBER 31, 1999
-------------- ------------- ------------------ -----------------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C>
Current assets................... $ 632.9 $ 507.2 $ 565.0 $ 495.9
Properties....................... 5,882.8 5,761.4 5,615.8 5,471.0
Intangible and other assets...... 169.5 174.2 177.1 180.0
-------- -------- -------- --------
Total assets..................... $6,685.2 $6,442.8 $6,357.9 $6,146.9
======== ======== ======== ========
Current liabilities.............. $1,252.7 $ 785.5 $ 732.7 $ 541.7
Deferred income taxes(c)......... 1,198.5 1,213.2 1,210.4 1,326.8
Long-term debt................... 2,755.4 3,029.7 2,966.1 2,797.3
Other long-term liabilities...... 600.4 526.8 528.6 543.6
Shareholders' equity(c).......... 878.2 887.6 920.1 937.5
-------- -------- -------- --------
Total liabilities and
shareholders' equity........... $6,685.2 $6,442.8 $6,357.9 $6,146.9
======== ======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
FOR THE 1998 QUARTERS ENDED(b)
-----------------------------------------------------------------------
MARCH 31, 1998 JUNE 30, 1998 SEPTEMBER 30, 1998 DECEMBER 31, 1998
-------------- ------------- ------------------ -----------------
(MILLIONS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
Operating revenues............... $ 408.0 $ 501.7 $ 558.4 $ 372.9
Operating income (loss).......... 61.2 (13.2) 81.2 (1,322.4)
Income (loss) from continuing
operations..................... 24.7 (33.8) (13.1) (860.9)
Net income (loss)................ 31.2 (17.3) (17.3) (895.4)
Per share:
Net income (loss) -- continuing
operations.................. $ 0.10 $ (0.13) $ (0.06) $ (3.48)
Net income (loss).............. 0.13 (0.07) (0.07) (3.61)
Dividends...................... 0.05 0.05 0.05 0.05
Common stock price:
High........................... 24.5 25.25 18.5625 14.5
Low............................ 20.875 16.5625 8.3125 8.25
</TABLE>
85
<PAGE> 91
<TABLE>
<CAPTION>
MARCH 31, 1998(d) JUNE 30, 1998(d) SEPTEMBER 30, 1998(d) DECEMBER 31, 1998
----------------- ---------------- --------------------- -----------------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C>
Current assets............ $ 654.7 $ 525.0 $ 457.7 $ 441.4
Properties................ 8,094.2 8,056.3 7,612.5 6,093.3
Net assets from
discontinued
operations.............. 979.9 743.7 825.0 926.9
Intangible and other
assets.................. 236.8 160.7 165.8 180.8
-------- -------- -------- --------
Total assets.............. $9,965.6 $9,485.7 $9,061.0 $7,642.4
======== ======== ======== ========
Current liabilities....... $ 957.8 $ 610.5 $ 588.7 $1,346.7
Deferred income taxes..... 2,063.4 1,930.4 1,735.3 1,291.6
Long-term debt............ 4,708.7 4,751.9 4,585.7 3,744.9
Other long-term
liabilities............. 470.7 494.7 495.5 531.0
Shareholders' equity...... 1,765.0 1,698.2 1,655.8 728.2
-------- -------- -------- --------
Total liabilities and
shareholders' equity.... $9,965.6 $9,485.7 $9,061.0 $7,642.4
======== ======== ======== ========
</TABLE>
- ---------------
(a) First quarter 1999 net income reflects the sale of the Company's GPM
business segment for $157.0 million after-tax gain and an after-tax loss of
$23.8 million on discontinued operations.
(b) Second quarter 1998 results reflect the impact of purchase of the Norcen
Acquisition. Fourth quarter 1998 results reflect the decrease in hydrocarbon
prices and a $1.2 billion impairment of certain oil and gas assets.
(c) Certain amounts have been restated from amounts previously reported in the
Company's SEC Form 10-Q for the periods ended March 31, 1999, June 30, 1999
and September 30, 1999.
(d) Certain amounts have been restated for discontinued operations from amounts
previously reported in the Company's SEC Form 10-Q for the periods ended
March 31, 1998, June 30, 1998 and September 30, 1998 (See Note 3).
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
(a) Directors of Registrant.
Information as to the names, ages, positions and offices with the Company,
terms of office, periods of service, business experience during the past five
years and certain other directorships held by each director or person nominated
to become a director is set forth in the Election of Directors segment of the
Proxy Statement and is incorporated herein by reference.
(b) Executive Officers of Registrant.
Information concerning executive officers is presented in Part I of this
report under Executive Officers of the Registrant.
86
<PAGE> 92
(c) Section 16(a) Compliance.
Information concerning compliance with Section 16(a) of the Securities
Exchange Act of 1934 is set forth in the Reports of Beneficial
Ownership -- Section 16(a) Reporting Compliance segment of the Proxy Statement
and is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
Information concerning remuneration received by executive officers and
directors is presented in the Compensation of Outside Directors and Executive
Compensation segments of the Proxy Statement and is incorporated herein by
reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information as to the number of shares of equity securities beneficially
owned as of March 17, 2000, by each director and nominee for director, the five
most highly compensated current executive officers, a former chief executive
officer, a former executive officer, and directors and current executive
officers as a group is set forth in the Security Ownership of Certain Executive
Officers, Directors and Certain Beneficial Owners segment of the Proxy Statement
and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a)(1) and (2) Financial Statements and Schedules.
See "Index to Consolidated Financial Statements" set forth in Item 8 of
this Form 10-K.
No schedules are required to be filed because of the absence of conditions
under which they would be required or because the required information is set
forth in the financial statements referred to above.
(a)(3) Exhibits.
Exhibits not incorporated herein by reference to a prior filing are
designated by an asterisk (*) and are filed herewith; all exhibits not so
designated are incorporated herein by reference to the Company's Form S-1
Registration Statement, Registration No. 33-95398, filed on October 10, 1995
("Form S-1") or as otherwise indicated. Management contracts or compensatory
plans, contracts or arrangements with directors and executive officers of the
Company are listed in Exhibits 10.3 through 10.14(b).
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
<C> <S>
2.1 -- Pre-acquisition agreement between Union Pacific Resources
Group Inc., Union Pacific Resources Inc. and Norcen
Energy Resources Limited, dated January 25, 1998
(incorporated herein by reference to Exhibit 2.1 to the
Company's Current Report on Form 8-K, filed on March 17,
1998)
3.1 -- Amended and Restated Articles of Incorporation of Union
Pacific Resources Group Inc. (Exhibit 3.1 to Form S-1 and
Exhibit 3.2 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1996)
*3.2 -- Amended and Restated Bylaws of Union Pacific Resources
Group Inc.
4.1 -- Specimen of Certificate evidencing the Common Stock
(Exhibit 4 to Form S-1)
</TABLE>
87
<PAGE> 93
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
<C> <S>
4.2 -- Amended and Restated Rights Agreement, dated as of
December 1, 1998, between Union Pacific Resources Group
Inc. and Harris Trust and Savings Bank, as rights agent
(incorporated herein by reference to the Exhibit to the
Company's Report on Form 8-A12G/A filed on February 5,
1999)
4.3 -- Indenture, dated as of March 27, 1996, between Union
Pacific Resources Group Inc. and Texas Commerce Bank
National Association, as trustee (incorporated herein by
reference to Exhibit 4.1 to the Company's Form S-3
Registration Statement, Registration No. 333-2984, dated
May 23, 1996)
4.4(a) -- Terms Agreement, dated as of October 10, 1996, for
$200,000,000 7 1/2% Debentures due October 15, 2026
(incorporated herein by reference to Exhibit 4.4 to the
Company's Current Report on Form 8-K filed on March 17,
1998)
4.4(b) -- Form of 7 1/2% Rate Debenture due October 15, 2026
(incorporated herein by reference to Exhibit 4.7 to the
Company's Current Report on Form 8-K filed on March 17,
1998)
4.5(a) -- Terms Agreement, dated as of October 10, 1996, for
$200,000,000 7% Notes due October 15, 2006 (incorporated
herein by reference to Exhibit 4.5 to the Company's
Current Report on Form 8-K filed on March 17, 1998)
4.5(b) -- Form of 7% Rate Note due October 15, 2006 (incorporated
herein by reference to Exhibit 4.8 to the Company's
Current Report on Form 8-K filed on March 17, 1998)
4.6(a) -- Terms Agreement, dated as of October 31, 1996, for
$150,000,000 7 1/2% Debentures due November 1, 2096
(incorporated herein by reference to Exhibit 4.6 to the
Company's Current Report on Form 8-K filed on March 17,
1998)
4.6(b) -- Form of 7 1/2% Rate Note due November 1, 2096
(incorporated herein by reference to Exhibit 4.9 to the
Company's Current Report on Form 8-K filed on March 17,
1998)
4.7 -- Trust Indenture, dated as of May 7, 1996, providing for
the issue of Debt Securities in unlimited principal
amount, between Norcen Energy Resources Limited and
Montreal Trust Company of Canada, as trustee
(incorporated herein by reference to Exhibit 4.10 to the
Company's Current Report on Form 8-K filed on March 17,
1998)
4.8 -- First Supplemental Indenture, dated as of May 22, 1996,
to Trust Indenture dated as of May 7, 1996, providing for
the issue of 7 3/8% Debentures due May 15, 2006, in
aggregate principal amount of U.S. $250,000,000 between
Norcen Energy Resources Limited and Montreal Trust
Company of Canada, as trustee (incorporated herein by
reference to Exhibit 4.11 to the Company's Current Report
on Form 8-K filed on March 17, 1998)
4.9 -- Second Supplemental Indenture, dated as of June 26, 1996,
to Trust Indenture dated as of May 7, 1996, providing for
the issue of 7.8% Debentures due July 2, 2008, in
aggregate principal amount of U.S. $150,000,000 between
Norcen Energy Resources Limited and Montreal Trust
Company of Canada, as trustee (incorporated herein by
reference to Exhibit 4.12 to the Company's Current Report
on Form 8-K filed on March 17, 1998)
4.10 -- Third Supplemental Indenture, dated as of June 26, 1996,
to Trust Indenture dated as of May 7, 1996, providing for
the issue of 6.8% Debentures due July 2, 2002, in
aggregate principal amount of U.S. $250,000,000 between
Norcen Energy Resources Limited and Montreal Trust
Company of Canada, as trustee (incorporated herein by
reference to Exhibit 4.13 to the Company's Current Report
on Form 8-K filed on March 17, 1998)
</TABLE>
88
<PAGE> 94
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
<C> <S>
4.11 -- Fourth Supplemental Indenture, dated as of February 27,
1998, to Trust Indenture dated as of May 7, 1996,
providing for the Guarantee of all Securities Issued or
Previously Issued under the Trust Indenture between
Norcen Energy Resources Limited, Union Pacific Resources
Group Inc., as guarantor, and Montreal Trust Company of
Canada, as trustee (incorporated herein by reference to
Exhibit 4.14 to the Company's Current Report on Form 8-K
filed on March 17, 1998)
4.12(a) -- Terms Agreement for $200,000,000 6.50% Notes due May 15,
2005 (incorporated herein by reference to Exhibit 4.1 to
the Company's Current Report on Form 8-K filed on May 26,
1998)
4.12(b) -- Form of 6.50% Note due May 15, 2005 (incorporated herein
by reference to Exhibit 4.5 to the Company's Current
Report on Form 8-K filed on May 26, 1998)
4.13(a) -- Terms Agreement for $200,000,000 6.75% Notes due May 15,
2008 (incorporated herein by reference to Exhibit 4.2 to
the Company's Current Report on Form 8-K filed on May 26,
1998)
4.13(b) -- Form of 6.75% Note due May 15, 2008 (incorporated herein
by reference to Exhibit 4.6 to the Company's Current
Report on Form 8-K filed on May 26, 1998)
4.14(a) -- Terms Agreement for $200,000,000 7.05% Notes due May 15,
2018 (incorporated herein by reference to Exhibit 4.3 to
the Company's Current Report on Form 8-K filed on May 26,
1998)
4.14(b) -- Form of 7.05% Debenture due May 15, 2018 (incorporated
herein by reference to Exhibit 4.7 to the Company's
Current Report on Form 8-K filed on May 26, 1998)
4.15(a) -- Terms Agreement for $425,000,000 7.15% Notes due May 15,
2028 (incorporated herein by reference to Exhibit 4.4 to
the Company's Current Report on Form 8-K filed on May 26,
1998)
4.15(b) -- Form of 7.15% Debenture due May 15, 2028 (incorporated
herein by reference to Exhibit 4.8 to the Company's
Current Report on Form 8-K filed on May 26, 1998)
4.16(a) -- Terms Agreement for $200,000,000 7.30% Notes due April
15, 2009 (incorporated herein by reference to Exhibit 1.2
to the Company's Current Report on Form 8-K filed on
April 12, 1999)
4.16(b) -- Form of 7.30% Note due April 15, 2009 (incorporated
herein by reference to Exhibit 4.2 to the Company's
Current Report on Form 8-K filed on April 14, 1999)
4.17(a) -- Terms Agreement for $300,000.000 7.95% Debentures due
April 15, 2029 (incorporated herein by reference to
Exhibit 1.2 to the Company's Current Report on Form 8-K
filed on April 12, 1999)
4.17(b) -- Form of 7.95% Debenture due April 15, 2029 ($200 million)
(incorporated herein by reference to Exhibit 4.3 to the
Company's Current Report on Form 8-K filed on April 14,
1999)
4.17(c) -- Form of 7.95% Debenture due April 15, 2029 ($100 million)
(incorporated herein by reference to Exhibit 4.4 to the
Company's Current Report on Form 8-K filed on April 14,
1999)
4.18 -- Indenture, dated as of April 13, 1999, between Union
Pacific Resources Group Inc., Union Pacific Resources
Inc., UPR Capital Company and The Bank of New York as
trustee (incorporated herein by reference to Exhibit 4.1
to the Company's Current Report on Form 8-K filed on
April 14, 1999)
10.1 -- Tax Allocation Agreement, dated October 6, 1995 (Exhibit
10.3 to Form S-1)
10.2 -- Indemnification Agreement, dated October 1, 1995 (Exhibit
10.4 to Form S-1)
10.3 -- Pension Plan Agreement, dated October 1, 1995, by and
between Union Pacific Corporation and Union Pacific
Resources Group Inc. (Exhibit 10.7 to Form S-1)
</TABLE>
89
<PAGE> 95
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
<C> <S>
10.4 -- The Supplemental Pension Plan for Officers and Managers
of Union Pacific Corporation and Affiliates, with
amendments (incorporated herein by reference to Exhibit
10.11 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1995)
10.5 -- The Supplemental Pension Plan for Exempt Salaried
Employees of Union Pacific Resources Company and
Affiliates, with amendments (incorporated herein by
reference to Exhibit 10.12 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1995)
10.6 -- Executive Incentive Plan of Union Pacific Resources Group
Inc. as amended and restated June 1, 1997 (incorporated
herein by reference to Exhibit 10.2 to the Company's
Quarterly Report on Form 10-Q for the period ended March
31, 1997)
*10.7 -- 1995 Stock Option and Retention Stock Plan of Union
Pacific Resources Group Inc. as amended and restated,
effective December 7, 1999.
10.8(a) -- 1995 Directors Stock Incentive Plan, as amended and
restated, effective July 14, 1998 (incorporated herein by
reference to Exhibit 10.8(a) to the Company's Annual
Report on Form 10-K for the year ended December 31, 1998)
10.8(b) -- First Amendment, effective January 21, 1999, to 1995
Directors Stock Incentive Plan, as amended and restated,
effective July 14, 1998 (incorporated herein by reference
to Exhibit 10.8(b) to the Company's Annual Report on Form
10-K for the year ended December 31, 1998)
10.8(c) -- Second Amendment, effective May 18, 1999, to 1995
Directors Stock Incentive Plan, as amended and restated,
effective July 14, 1998 (incorporated by reference to
Exhibit 10.2 to the Company's Quarterly Report on Form
10-Q for the period ended June 30, 1999)
10.9 -- Union Pacific Resources Group Inc. Deferred Compensation
Plan for the Board of Directors, as amended and restated,
effective September 5, 1997 (incorporated herein by
reference to Exhibit 99.2 to the Company's Registration
Statement on Form S-8, dated September 15, 1997)
10.10 -- Union Pacific Resources Group Inc. Executive Deferred
Compensation Plan, effective September 5, 1997
(incorporated herein by reference to Exhibit 99.1 to the
Company's Registration Statement on Form S-8, dated
September 15, 1997)
10.11(a) -- Union Pacific Resources Group Inc. Executive Life
Insurance Plan, adopted February 26, 1997 (incorporated
herein by reference to Exhibit 10.16 to the Company's
Annual Report on Form 10-K for the year ended December
31, 1996)
*10.11(b) -- Description of Amendment, adopted December 6, 1999, to
the Union Pacific Resources Group Inc. Executive Life
Insurance Plan, adopted February 26, 1997.
10.12(a) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and George
Lindahl III dated October 21, 1999, superseding and
replacing the agreement dated February 4, 1997
(incorporated herein by reference to Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the period
ended September 30, 1999)
10.12(b) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and each of
Anne M. Franklin, Donald W. Niemiec, Morris B. Smith,
John B. Vering and Joseph A. LaSala, Jr., dated February
4, 1997 (incorporated herein by reference to Exhibit
10.17(c) to the Company's Annual Report on Form 10-K for
the year ended December 31, 1996)
10.12(c) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and Thomas R.
Blank, dated July 13, 1998 (incorporated herein by
reference to Exhibit 10.4 to the Company's Quarterly
Report on Form 10-Q/A filed November 12, 1998)
</TABLE>
90
<PAGE> 96
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
<C> <S>
10.12(d) -- Form of Amendment, dated as of January 21, 1999, to
Change in Control Agreements between Union Pacific
Resources Group Inc. and Anne M. Franklin, Donald W.
Niemiec, Morris B. Smith, John B. Vering, Jack L.
Messman, V. Richard Eales and Joseph A. LaSala, Jr., all
dated February 4, 1997, and between Union Pacific
Resources Group Inc. and Thomas R. Blank dated July 13,
1998 (incorporated herein by reference to Exhibit
10.13(e) to the Company's Annual Report on Form 10-K for
the year ended December 31, 1998)
*10.12(e) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and Kerry R.
Brittain, dated March 18, 1999.
*10.12(f) -- Form of Amendment, dated as of March 30, 1999, to Change
in Control Agreement between Union Pacific Resources
Group Inc. and Kerry R. Brittain, dated March 18, 1999.
10.12(g) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and Jack L.
Messman, dated February 4, 1997 (incorporated herein by
reference to Exhibit 10.17(a) to the Company's Annual
Report on Form 10-K for the year ended December 31, 1996)
10.12(h) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and V. Richard
Eales, dated February 7, 1997 (incorporated herein by
reference to Exhibit 10.17(b) to the Company's Annual
Report on From 10-K for the year ended December 31, 1996)
10.13 -- Settlement and Release Agreement by and between Union
Pacific Resources Group Inc. and V. Richard Eales,
effective September 1, 1999 (incorporated herein by
reference to Exhibit 10.2 to the Company's Quarterly
Report on Form 10-Q for the period ended September 30,
1999)
10.14(a) -- Conversion Agreement (Exhibit 10.13(a) to Form S-1)
10.14(b) -- Conversion Agreement for Drew Lewis (Exhibit 10.13(b) to
Form S-1)
10.15(a) -- Amended and Restated 1976 Coal Purchase Contract, dated
as of January 1, 1993, between Commonwealth Edison
Company and Black Butte Coal Company (Exhibit 10.19 to
Form S-1)
10.15(b) -- Amendment No. 1 to Amended and Restated 1976 Coal
Purchase Contract between Commonwealth Edison Company and
Black Butte Coal Company, effective as of January 1, 1996
(incorporated herein by reference to Exhibit 10.35 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1997)
10.15(c) -- Amendment No. 2 to Amended and Restated 1976 Coal
Purchase Contract between Commonwealth Edison Company and
Black Butte Coal Company, effective as of January 1, 1997
(incorporated herein by reference to Exhibit 10.36 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1997)
10.16(a) -- Transportation Agreement, dated December 15, 1989, by and
between Kern River Gas Transmission Company and Union
Pacific Fuels, Inc. (Exhibit 10.21 to Form S-1)
10.16(b) -- Amendments to Transportation Agreement, dated December
15, 1989, by and between Kern River Gas Transmission
Company and Union Pacific Fuels, Inc. (incorporated
herein by reference to Exhibit 10.16 to the Company's
Annual Report on Form 10-K for the year ended December
31, 1997)
*10.16(c) -- Assignment, dated March 1, 1999 by and between Kern River
Gas Transmission Company, Union Pacific Fuels, Inc. and
Union Pacific Resources Company assigning Transportation
Agreement, dated December 15, 1989, by and between Kern
River Gas Transmission Company and Union Pacific Fuels,
Inc. to Union Pacific Resources Company
</TABLE>
91
<PAGE> 97
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
<C> <S>
10.17 -- Gas Transportation Agreement, dated June 18, 1997, by and
between Union Pacific Fuels, Inc. and Texas Gas
Transmission Corporation (incorporated herein by
reference to Exhibit 10.17 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1997)
10.19 -- Registration Rights Agreement, dated as of August 3,
1995, among Union Pacific Resources Group Inc., The
Anschutz Corporation and Anschutz Foundation
(incorporated herein by reference to Exhibit 10.19 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1995)
10.20(a) -- Agreement, dated as of August 3, 1995, by and among Union
Pacific Resources Group Inc., The Anschutz Corporation,
Anschutz Foundation and Mr. Philip F. Anschutz (the
"Anschutz Agreement") (incorporated herein by reference
to Exhibit 10.20 to the Company's Annual Report on Form
10-K for the year ended December 31, 1995)
10.20(b) -- Letter agreement, dated as of January 20, 1997, amending
the Anschutz Agreement (incorporated herein by reference
to Exhibit 10.25 to the Company's Annual Report on Form
10-K for the year ended December 31, 1996)
10.21(a) -- U.S. $750,000,000 Five-Year Competitive Advance/Revolving
Credit Agreement, dated as of October 27, 1998, among
Union Pacific Resources Group Inc. and Chase Bank of
Texas, N.A., as administrative agent, The Chase Manhattan
Bank of Canada, as Canadian sub-agent and the banks named
therein (incorporated herein by reference to Exhibit 10.3
to the Company's Quarterly Report on Form 10-Q/A filed
November 12, 1998)
10.21(b) -- U.S. $25,000,000 Revolving Loan Agreement, dated July 14,
1997, between Basic Petroleum International Limited and
Royal Bank of Canada (incorporated herein by reference to
Exhibit 10.33 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1997)
10.21(c) -- U.S. $1,000,000,000 364-day Competitive Advance/Revolving
Credit Agreement, dated as of October 27, 1998, among
Union Pacific Resources Group Inc. and Chase Bank of
Texas, N.A., as administrative agent and the banks named
therein (incorporated herein by reference to Exhibit 10.1
to the Company's Quarterly Report on Form 10-Q/A filed
November 12, 1998)
10.21(d) -- U.S. $750,000,000 364-day Competitive Advance/Revolving
Credit Agreement, dated as of October 27, 1998, among
Union Pacific Resources Group Inc. and Chase Bank of
Texas, N.A., as administrative agent and the banks named
therein (incorporated herein by reference to Exhibit 10.2
to the Company's Quarterly Report on Form 10-Q/A filed
November 12, 1998)
10.22(a) -- Merger and Purchase Agreement, dated November 20, 1998,
among Union Pacific Resources Company, Union Pacific
Fuels, Inc., Duke Energy Field Services, Inc. and DEFS
Merger Sub Corp. (incorporated herein by reference to
Exhibit 10.23(a) to the Company's Annual Report on Form
10-K for the year ended December 31, 1998)
10.22(b) -- Amendment, No. 1, dated February 1, 1999, to Merger and
Purchase Agreement, dated November 20, 1998, among Union
Pacific Resources Company, Union Pacific Fuels, Inc.,
Duke Energy Field Services, Inc. and DEFS Merger Sub
Corp. (incorporated herein by reference to Exhibit
10.23(b) to the Company's Annual Report on Form 10-K for
the year ended December 31, 1998)
</TABLE>
92
<PAGE> 98
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
<C> <S>
10.22(c) -- Amendment No. 2, dated March 5, 1999, to Merger and
Purchase Agreement, dated November 20, 1998, among Union
Pacific Resources Company, Union Pacific Fuels, Inc.,
Duke Energy Services, Inc. and DEFS Merger Sub Corp.
(incorporated herein by reference to Exhibit 10.2 to the
Company's Current Report on Form 8-K filed April 12,
1999)
10.22(d) -- Amendment No. 3, dated March 30, 1999, to Merger and
Purchase Agreement, dated November 20, 1998, among Union
Pacific Resources Company, Union Pacific Fuels, Inc. Duke
Energy Field Services, Inc. and DEFS Merger Sub Corp.
(incorporated herein by reference to Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the period
ended March 31, 1999)
10.22(e) -- Amendment No. 4, dated March 30, 1999, to Merger and
Purchase Agreement, dated November 20, 1998, among Union
Pacific Resources Company, Union Pacific Fuels, Inc.,
Duke Energy Field Services, Inc. and DEFS Merger Sub
Corp. (incorporated herein by reference to Exhibit 10.1
to the Company's Quarterly Report on Form 10-Q) for the
period ended March 31, 1999)
*10.22(f) -- Amendment No. 5, dated May 21, 1999, to Merger and
Purchase Agreement, dated November 20, 1998, among Union
Pacific Resources Company, Union Pacific Fuels, Inc.,
Duke Energy Field Services, Inc. and DEFS Merger Sub
Corp.
*10.22(g) -- Amendment No. 6, dated February 16, 2000, to Merger and
Purchase Agreement, dated November 20, 1998, among Union
Pacific Resources Company, Union Pacific Fuels, Inc.,
Duke Energy Field Services, Inc. and DEFS Merger Sub
Corp.
*10.22(h) -- Master Natural Gas Liquids Purchase Agreement between
Union Pacific Resources Company and Union Pacific Fuels,
Inc., effective January 1, 1999.
*10.22(i) -- Natural Gas Purchase and Sale Agreement between Union
Pacific Resources Company and Union Pacific Fuels, Inc.,
effective January 1, 1999.
*12 -- Computation of ratio of earnings to fixed charges
*21 -- List of subsidiaries
*23.1 -- Consent of Arthur Andersen LLP dated as of March 23,
2000.
*23.2 -- Consent of Deloitte & Touche LLP dated as of March 23,
2000.
*23.3 -- Consent of Arthur Andersen LLP dated as of March 23, 2000
(Black Butte Coal Company Combined Financials Statements)
*24 -- Powers of Attorney for Directors
*27 -- Financial data schedules
*99.1 -- Black Butte Coal Company, A Joint Venture, and R-K
Leasing Company Combined Financial Statements as of
December 31, 1999 and December 26, 1998.
*99.2 -- Black Butte Coal Company, A Joint Venture, and R-K
Leasing Company Combined Financial Statements as of
December 27, 1997.
</TABLE>
(b) Reports on Form 8-K.
On January 28, 2000, the Company filed a Current Report on Form 8-K
announcing the Company's 1999 annual operating results, net income and certain
other financial and statistical information.
On February 17, 2000, the Company filed a Current Report on Form 8-K
updating its January 25, 2000 press release and the January 28, 2000 Current
Report on Form 8-K to include information with respect to reserves at year-end
1999 and finding and development costs for 1999.
93
<PAGE> 99
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned; thereunto duly authorized, on this 27th day of
March, 2000.
UNION PACIFIC RESOURCES GROUP INC.
By: /s/ MORRIS B. SMITH
---------------------------------------
Morris B. Smith,
Vice President, Chief Financial Officer
and Treasurer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below, on this 27th day of March, 2000, by the following
persons on behalf of the registrant and in the capacities indicated.
<TABLE>
<S> <C>
/s/ GEORGE LINDAHL III Chairman, Chief Executive Officer and Director
- ----------------------------------------------------- (Principal Executive Officer)
George Lindahl III
/s/ MORRIS B. SMITH Vice President and Chief Financial Officer
- ----------------------------------------------------- (Principal Accounting and Financial Officer)
Morris B. Smith
* Director
- -----------------------------------------------------
H. Jesse Arnelle
* Director
- -----------------------------------------------------
Lynne V. Cheney
* Director
- -----------------------------------------------------
Preston M. Geren III
* Director
- -----------------------------------------------------
Lawrence M. Jones
* Director
- -----------------------------------------------------
Drew Lewis
* Director
- -----------------------------------------------------
Claudine B. Malone
* Director
- -----------------------------------------------------
John W. Poduska, Sr., Ph.D.
* Director
- -----------------------------------------------------
Michael E. Rossi
* Director
- -----------------------------------------------------
Jeff Sandefer
* Director
- -----------------------------------------------------
Samuel K. Skinner
* Director
- -----------------------------------------------------
James R. Thompson
*By: /s/ KATHY L. COX
-----------------------------------------------
(Kathy L. Cox, as attorney-in-fact)
</TABLE>
94
<PAGE> 100
<TABLE>
<S> <C> <C>
BOARD OF DIRECTORS EXECUTIVE OFFICERS COMMON STOCK PRICES AND
DIVIDENDS
H. JESSE ARNELLE GEORGE LINDAHL III
Of Counsel Chairman, President and The range of New York Stock
Womble, Carlyle, Chief Executive Officer Exchange trading prices for UPR
Sandridge & Rice common stock and dividends
Law THOMAS R. BLANK declared per share during 1999
Vice President-State, Regulatory was as follows:
LYNNE V. CHENEY and Public Affairs
Distinguished Fellow
American Enterprise Institute KERRY R. BRITTAIN
Public Policy Research Vice President, General Counsel Quarter High Low Last
and Secretary Dividends
PRESTON M. "PETE" GEREN III Ended
Attorney-at-Law ANNE M. FRANKLIN
Law Vice President-People Mar. 31 12 3/16 7 11/16 11 7/8 $0.05
June 30 17 10 3/4 16 5/16 $0.05
LAWRENCE M. JONES DONALD W. NIEMIEC Sept. 30 19 3/8 14 7/16 16 1/4 $0.05
Retired Chairman and Vice President-Marketing and Dec. 31 16 1/8 10 15/16 12 3/4 $0.05
Chief Executive Officer Corporate Development
The Coleman Company, Inc.
Home and Recreational MORRIS B. SMITH COMMON STOCK LISTING
Products Vice President,
Chief Financial Officer New York Stock Exchange
DREW LEWIS and Treasurer Ticker Symbol: UPR
Retired Chairman and
Chief Executive Officer JOHN B. VERING SHAREHOLDERS
Union Pacific Corporation Vice President-Canadian
Transportation Operations As of February 29, 2000, the
number of shareholders of Union
GEORGE LINDAHL III Pacific Resources Group Inc.
Chairman, President and common stock was
Chief Executive Officer BOARD COMMITTEES approximately 113,400.
Union Pacific Resources
Group Inc. Audit Committee TRANSFER AGENT AND REGISTRAR
Oil and Gas Samuel K. Skinner, Chair OF STOCK
H. Jesse Arnelle
CLAUDINE B. MALONE Lynne V. Cheney Harris Trust & Savings Bank
President Claudine B. Malone Attn: Shareholder Services
Financial & Management P.O. Box A3504
Consulting, Inc. Compensation Committee Chicago, Illinois 60690-3504
Management Consulting John W. Poduska, Sr., Ph.D., Chair Internet: www.harrisbank.com
Preston M. "Pete" Geren III
JOHN W. PODUSKA, SR., Ph.D. Michael E. Rossi COMPANY CONTACTS
Chairman James R. Thompson
Advanced Visual Systems, Inc. Investor Relations:
Visualization Software Corporate Governance and Patrick Mooney
Nominating Committee Vice President-Investor Relations
MICHAEL E. ROSSI Lawrence M. Jones, Chair (817) 321-7169
Chairman John W. Poduska, Sr., Ph.D.
Shorestein Realty Services Michael E. Rossi Media Relations:
Real Estate Samuel K. Skinner Dan Sullivan
Director of Public Affairs
JEFF SANDEFER Executive Committee (817) 321-6527
President Drew Lewis, Chair
Sandefer Capital Partners, L.P. Lawrence M. Jones
Oil and Gas Investments George Lindahl III
Michael E. Rossi
SAMUEL K. SKINNER James R. Thompson
Co-Chairman and Partner
Hopkins and Sutter Finance Committee
Law Michael E. Rossi, Chair
Lawrence M. Jones
JAMES R. THOMPSON Drew Lewis
Chairman, Chairman of the George Lindahl III
Executive Committee and Jeff Sandefer
Partner Samuel K. Skinner
Winston & Strawn
Law
</TABLE>
INFORMATION SOURCES
For prompt assistance with shareholder change of address, consolidation of
multiple accounts or related matters, please contact the Shareholder Services
Division, Harris Trust & Savings Bank, at (800) 335-6918 on weekdays between
8:30 a.m. and 5:00 p.m. (Central Standard Time).
Additional copies of this 1999 Annual Report, including the Company's Annual
Report on Form 10-K for the year ended December 31, 1999 filed with the
Securities and Exchange Commission, may be obtained, without charge, from UPR's
Investor Relations department. Copies of any exhibits to the Annual Report on
Form 10-K may be obtained, without charge, upon specific request.
Statements in this Annual Report, other than historical financial information,
include forward-looking statements regarding possible transactions, budgeted
capital expenditures, estimated reserves, expected drilling activity and
construction, expected production and other matters subject to a number of risks
and uncertainties, which are detailed herein.
The proposed merger transaction involving UPR and Anadarko Petroleum Corporation
will be submitted to each company's shareholders. All shareholders should read
the joint proxy statement/prospectus concerning the merger that will be filed
with the SEC and mailed to shareholders. The joint proxy statement/prospectus
will contain important information that shareholders should consider before
making any decision regarding the merger. Shareholders will be able to obtain
the joint proxy statement/prospectus, as well as other filings containing
information about UPR and Anadarko, without charge, at the SEC's Internet site
(http://www.sec.gov). Copies of the joint proxy statement/ prospectus and the
SEC filings that will be incorporated by reference in the joint proxy
statement/prospectus can also be obtained, without charge, from the Corporate
Secretary of the appropriate company. Information regarding the participants in
the solicitation, and a description of their direct and indirect interests, by
security holdings or otherwise, are contained in UPR's filing with the SEC on
Schedule 14A under Rule 14a-12 on April 7, 2000, and in Anadarko's filing of its
press release with the SEC under Rule 425 on April 3, 2000.
Union Pacific Resources
Group Inc.
777 Main Street
Fort Worth, Texas 76102
(817) 321-6000
Internet: www.upr.com
