1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549-1004
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission file number 1-13916
UNION PACIFIC RESOURCES GROUP INC.
(Exact name of registrant as specified in its charter)
UTAH 13-2647483
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
777 MAIN STREET, FORT WORTH, TEXAS
(Address of principal executive offices)
76102
(Zip Code)
(817) 321-6000
(Registrant's telephone number, including area code)
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
--- ---
As of October 31, 1998, there were 251,009,284 shares of the
registrant's common stock outstanding.
2
UNION PACIFIC RESOURCES GROUP INC.
INDEX
PART I. FINANCIAL INFORMATION
Page Number
-----------
ITEM 1: CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - For the Three
Months and Nine Months Ended September 30, 1998 and 1997................................. 2
CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION -
At September 30, 1998 and December 31, 1997............................................. 3 - 4
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - For the
Nine Months Ended September 30, 1998 and 1997............................................ 5
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS...................................... 6 - 11
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS.................................................. 12
ITEM 2: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS............................................................................. 13 - 28
ITEM 3: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK................................ 29 - 31
PART II. OTHER INFORMATION
ITEM 1: LEGAL PROCEEDINGS......................................................................... 32
ITEM 6: EXHIBITS AND REPORTS ON FORM 8-K.......................................................... 32
SIGNATURE.......................................................................................... 33
-1-
3
UNION PACIFIC RESOURCES GROUP INC.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months and Nine Months Ended September 30, 1998 and 1997
(Millions, except per share amounts)
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
------------- -------------
1998 1997 1998 1997
------ ------ ------ ------
Operating revenues:
Oil and gas operations:
Exploration and production............................ $ 390.2 $ 292.2 $ 1,193.0 $ 966.8
Gathering, processing and marketing................... 83.7 105.0 299.6 319.4
Other oil and gas revenues............................ 129.3 10.7 154.0 33.9
-------- -------- --------- --------
Total oil and gas operations....................... 603.2 407.9 1,646.6 1,320.1
Minerals................................................. 38.8 41.1 115.5 105.2
-------- -------- --------- --------
Total operating revenues.......................... 642.0 449.0 1,762.1 1,425.3
-------- -------- --------- --------
Operating expenses:
Production............................................... 113.1 71.8 336.1 216.7
Exploration, including exploratory dry holes............. 79.0 58.6 229.6 150.6
Gathering, processing and marketing...................... 64.6 66.3 193.2 195.6
Minerals................................................. 0.5 1.3 1.8 3.8
Depreciation, depletion and amortization................. 280.4 136.5 755.1 404.3
General and administrative............................... 23.7 20.0 69.4 58.4
-------- -------- --------- --------
Total operating expenses....................... 561.3 354.5 1,585.2 1,029.4
-------- -------- --------- --------
Operating income ............................................ 80.7 94.5 176.9 395.9
Other income (expense) - net (Note 7)........................ (48.2) 8.7 (32.8) 9.6
Interest expense ............................................ (77.8) (13.8) (195.3) (35.5)
-------- -------- --------- --------
Income (loss) before income taxes............................ (45.3) 89.4 (51.2) 370.0
Income tax benefit (expense)................................. 28.0 (22.2) 47.8 (111.2)
-------- -------- --------- --------
Net income (loss)............................................ $ (17.3) $ 67.2 $ (3.4) $ 258.8
======== ======== ========= ========
Other comprehensive income, net of tax:
Foreign currency translation adjustments................. (16.9) (0.2) (53.9) (1.0)
-------- -------- -------- --------
Comprehensive income (loss).................................. $ (34.2) $ 67.0 $ (57.3) $ 257.8
======== ======== ======== ========
Earnings (loss) per share - basic............................ $ (0.07) $ 0.27 $ (0.01) $ 1.03
Earnings (loss) per share - diluted.......................... $ (0.07) $ 0.27 $ (0.01) $ 1.03
Weighted average shares outstanding - diluted................ 247.8 251.0 247.7 251.0
Cash dividends per share..................................... $ 0.05 $ 0.05 $ 0.15 $ 0.15
See the notes to the condensed consolidated financial statements (unaudited).
-2-
4
UNION PACIFIC RESOURCES GROUP INC.
CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
At September 30, 1998 and December 31, 1997
(Millions of dollars)
September 30, December 31,
1998 1997
----------- -----------
(Unaudited)
ASSETS
Current assets:
Cash and temporary investments................................... $ 44.0 $ 70.6
Accounts receivable - net........................................ 420.4 385.4
Inventories...................................................... 120.2 53.1
Other current assets............................................. 64.2 67.7
----------- -----------
Total current assets....................................... 648.8 576.8
----------- -----------
Properties (successful efforts method): (Note 4)
Cost............................................................. 12,774.6 7,414.4
Accumulated depreciation, depletion and amortization............. (4,317.1) (3,749.0)
----------- -----------
Total properties - net..................................... 8,457.5 3,665.4
Intangible and other assets.......................................... 323.6 230.0
----------- -----------
Total assets......................................................... $ 9,429.9 $ 4,472.2
=========== ===========
See the notes to the condensed consolidated financial statements (unaudited).
-3-
5
UNION PACIFIC RESOURCES GROUP INC.
CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
At September 30, 1998 and December 31, 1997
(Millions of dollars)
September 30, December 31,
1998 1997
------------- ------------
(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable.................................................. $ 378.6 $ 426.7
Advance payment (Note 6).......................................... 250.0 --
Accrued taxes payable............................................. 156.3 59.3
Other current liabilities......................................... 169.7 71.7
----------- -----------
Total current liabilities.................................... 954.6 557.7
----------- -----------
Long-term debt (Note 4)................................................ 4,585.7 1,230.6
Deferred income taxes ................................................. 1,735.3 552.9
Other long-term liabilities (Note 8)................................... 498.5 370.3
Shareholders' equity:
Common stock, no par value;
Authorized shares--400,000,000
Issued shares--254,351,417 and 254,268,200...................... -- --
Paid-in surplus................................................... 992.6 991.2
Unearned employee stock ownership plan............................ (96.4) (102.0)
Retained earnings................................................. 916.9 957.4
Unearned compensation............................................. (7.1) (11.8)
Accumulated other comprehensive income:
Deferred foreign exchange adjustment.......................... (71.2) (17.3)
Minimum pension contra equity................................. (1.0) (1.0)
Treasury stock, at cost:
Shares--3,239,590 and 2,379,625 .............................. (78.0) (55.8)
----------- -----------
Total shareholders' equity................................... 1,655.8 1,760.7
----------- -----------
Total liabilities and shareholders' equity............................. $ 9,429.9 $ 4,472.2
=========== ===========
See the notes to the condensed consolidated financial statements (unaudited).
-4-
6
UNION PACIFIC RESOURCES GROUP INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 1998 and 1997
(Millions of dollars)
(Unaudited)
1998 1997
---- ----
Cash flows provided by operations:
Net income (loss)...................................................... $ (3.4) $ 258.8
Non-cash charges to income:
Depreciation, depletion and amortization............................ 755.1 404.3
Deferred income taxes............................................... (141.7) 68.0
Other non-cash charges - net ....................................... 225.4 73.2
Changes in current assets and liabilities.............................. 162.7 2.2
---------- ---------
Cash provided by operations...................................... 998.1 806.5
---------- ---------
Cash flows from investing activities:
Capital and exploratory expenditures................................... (1,239.9) (1,010.3)
Acquisition of Highlands Gas Corporation............................... -- (179.4)
Acquisition of Norcen (Note 4)......................................... (2,634.3) --
Proceeds from sales of assets ......................................... 262.1 22.3
Proceeds from sales of investments..................................... 48.4 --
Proceeds from settlement of contract................................... 70.3 --
Other investing activities - net....................................... -- (6.4)
---------- ---------
Cash used by investing activities................................ (3,493.4) (1,173.8)
---------- ---------
Cash flows from financing activities:
Dividends paid......................................................... (37.2) (37.5)
Debt financing - net................................................... 2,323.2 307.0
Purchase of treasury stock............................................. (22.1) (2.6)
Other financings - net (Note 6)........................................ 204.8 25.3
---------- ---------
Cash provided by financing activities............................ 2,468.7 292.2
---------- ---------
Net change in cash and temporary investments............................... (26.6) (75.1)
Cash at beginning of period................................................ 70.6 118.9
---------- ---------
Cash at end of period...................................................... $ 44.0 $ 43.8
========== =========
See the notes to the condensed consolidated financial statements (unaudited).
-5-
7
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. RESPONSIBILITIES FOR FINANCIAL STATEMENTS
The Condensed Consolidated Financial Statements of Union Pacific Resources
Group Inc. and subsidiaries (the "Company") have been prepared by
management and are unaudited. Such unaudited interim financial statements
reflect all adjustments (including normal recurring adjustments) that are,
in the opinion of management, necessary for a fair presentation of the
financial position and operating results of the Company for the interim
periods; however, such condensed statements do not include all of the
information and footnotes required by generally accepted accounting
principles to be included in a full set of financial statements. The report
of Arthur Andersen LLP commenting on their review accompanies the Condensed
Consolidated Financial Statements and is included in Part I, Item 1 in this
report. The Condensed Consolidated Statement of Financial Position at
December 31, 1997, is derived from audited financial statements. The
Condensed Consolidated Financial Statements should be read in conjunction
with the consolidated financial statements and notes thereto contained in
the Company's Annual Report on Form 10-K for the year ended December 31,
1997, and the pro forma combined financial statements contained in the
Company's Current Report on Form 8-K/A filed on May 6, 1998. The results of
operations for the nine months ended September 30, 1998, are not
necessarily indicative of the results for the full year ending December 31,
1998.
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, the disclosure of contingent assets and liabilities at the
date of the financial statements, and the reported amounts of revenues and
expenses for 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 and assumptions.
2. NEW ACCOUNTING STANDARDS
In February 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 132, "Employers'
Disclosures about Pensions and Other Postretirement Benefits," which is
effective for fiscal years beginning after December 15, 1997. This
statement revises employers' disclosure requirements relating to pension
and other postretirement benefit plans. It standardizes the disclosure
requirements to the extent practicable and requires additional information
on changes in the benefit obligations and fair values of plan assets. The
Company plans to adopt SFAS No. 132 for the year ending December 31, 1998.
In June 1998, FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," which is effective for all quarters of
fiscal years beginning after June 15, 1999. This statement requires that
all derivatives be recognized on the balance sheet, 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
-6-
8
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 in the first
quarter of 2000.
3. BUSINESS SEGMENT INFORMATION
The following table presents summarized segment information for the Company
pursuant to SFAS No. 131.
Nine Months Ended September 30,
-------------------------------
1998 1997
---- ----
(Millions of dollars)
Revenues:
Exploration and production........................................ $ 1,346.6 $ 993.9
Gathering, processing and marketing............................... 300.0 326.2
Minerals.......................................................... 115.5 105.2
---------- ----------
Total............................................................ $ 1,762.1 $ 1,425.3
========== ==========
Operating income:
Exploration and production.......................................... $ 83.6 $ 276.0
Gathering, processing and marketing............................... 53.2 80.8
Minerals.......................................................... 113.7 100.2
Corporate (a)..................................................... (73.6) (61.1)
---------- ----------
Total ................................................................ $ 176.9 $ 395.9
========== ==========
At September 30, At December 31,
1998 1997
---- ----
(Millions of dollars)
Fixed assets (net of accumulated DD&A):
Exploration and production.......................................... $ 7,398.9 $ 2,695.7
Gathering, processing and marketing................................. 909.1 843.4
Minerals............................................................ 23.7 23.6
Corporate........................................................... 125.8 102.7
---------- ----------
Total............................................................... $ 8,457.5 $ 3,665.4
========== ==========
(a) Operating income for the Corporate segment consists of general and
administrative expense.
4. ACQUISITION OF NORCEN
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 percent 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 percent of the outstanding common shares
of Norcen were tendered at a purchase price of U.S. $13.65 per share.
-7-
9
On March 5, 1998, 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 purchase price for
the Norcen Acquisition, including non-recurring transaction costs of $28.1
million, was $2.634 billion. In addition, the Company assumed the long-term
debt obligations of Norcen.
Norcen operations primarily consisted of oil and 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 the Company's 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 revised preliminary 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. Any
additional adjustments to the allocation of the purchase price are not
anticipated to be material to the Condensed Consolidated Financial
Statements of the Company.
(Millions of dollars)
Working capital......................................................................... $ 112.3
Property, plant and equipment........................................................... 4,923.2
Other assets............................................................................ 225.7
Long-term debt.......................................................................... (1,011.9)
Other non-current liabilities, including deferred taxes................................. (1,615.0)
--------
Total purchase price............................................................... $ 2,634.3
=========
The following table presents unaudited pro forma condensed consolidated
statements of operations of the Company for the nine months ended September
30, 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.
Nine Months Ended September 30,
-------------------------------
1998 1997
---- ----
(Millions of dollars, except per share amounts)
Revenues.............................................................. $1,862.4 $ 1,899.5
Costs and expenses ................................................... 1,716.3 1,567.8
-------- ---------
Operating income...................................................... 146.1 331.7
Interest expense...................................................... (229.7) (181.8)
Other income (expense) - net.......................................... (43.9) 9.6
-------- ---------
Income (loss) before income taxes..................................... (127.5) 159.5
Income tax benefit (expense).......................................... 75.6 (43.4)
-------- ---------
Net income (loss)................................................... $ (51.9) $ 116.1
======== =========
Earnings (loss) per share - basic..................................... $ (0.21) $ 0.46
Earnings (loss) per share - diluted................................... (0.21) 0.46
-8-
10
The unaudited pro forma condensed consolidated information presented above
is not necessarily indicative of the results of operations or the financial
position which would have occurred had the Norcen Acquisition been
consummated on January 1, 1997, nor is it necessarily indicative of future
results of operations of the Company.
NORCEN SUMMARIZED FINANCIAL INFORMATION
Shortly after the Norcen Acquisition, Norcen was amalgamated with UPRI (the
"Amalgamation"). Prior to the Amalgamation, UPRI's operations primarily
consisted of oil and gas operations in western Canada. After the
Amalgamation, certain non-Canadian international assets have been or will
soon be distributed or contributed from UPRI to other subsidiaries of the
Company.
As a result of the Amalgamation, UPRI assumed the obligations of Norcen,
including the public debt obligations of Norcen (the "Debt Securities").
The Debt Securities include 7 3/8% Debentures due May 15, 2006, in the
aggregate principal amount of $250 million, 7.8% Debentures due July 2,
2008, in the aggregate principal amount of $150 million and 6.8% Debentures
due July 2, 2002, in the aggregate principal amount of $250 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 two months ended February 28, 1998,
and seven months ended September 30, 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 for as
long as the Debt Securities remain outstanding and guaranteed by the
Company.
Two Months Ended Seven Months Ended
February 28, 1998(1) September 30, 1998(2)
--------------------- ---------------------
(Millions of dollars) (Millions of dollars)
Summarized Statement of Income Information:
Operating revenues............................................ $ 104.0 $268.9
Operating income (loss)....................................... 4.0 (104.1)
Net income (loss)............................................. (30.0)(3) (106.4)
Summarized Statement of Financial Position Information:
Current assets................................................ $ 275.6 $ 139.2
Non-current assets............................................ 2,456.2 3,520.3
Current liabilities........................................... 182.6 151.4
Non-current liabilities and equity............................ 2,549.2 3,508.1
- ---------------------------------
(1) Results for UPRI as of and for the two months ended February 28,
1998. Results have not been restated in accordance with U.S. generally
accepted accounting principles ("GAAP") and reflect the full cost method
for accounting for oil and gas operations.
(2) Results for UPRI as of and for the seven months ended September 30,
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.
(3) Net loss includes $40 million in costs incurred by UPRI in connection
with the Norcen Acquisition which were not reimbursed by the Company.
-9-
11
5. PLANNED DIVESTITURES
The Company's Board of Directors has authorized management to proceed
with a deleveraging program designed to reduce the Company's debt and
obtain a strong investment grade credit rating. The program included the
Company's plans to sell approximately $600 million of producing
properties. The Company's current forecast shows that the $600 million
target will be substantially achieved by year-end, but with a different
mix of properties being sold than was originally disclosed. Completed
sales include certain properties located in the Denver-Julesburg Basin of
the Western Region (the "DJ Basin properties") for $41 million, Matagorda
Island Block 623 Field and surrounding blocks (the "Matagorda property")
for $158 million, several other Western Region properties and most of the
Canadian properties originally identified for divestiture. In addition,
agreements have been reached to sell interests in certain South Texas
properties for $148 million, certain Gulf of Mexico properties, a Western
Region property and a Canadian property. Additional properties are
scheduled to be sold in early 1999. All of the properties identified for
sale in the aggregate represent approximately ten percent of the
Company's reserves, production volumes and cash flows.
In connection with this deleveraging program, the Board of Directors also
authorized management to pursue potential monetization of the Company's
gathering, processing and marketing ("GPM") business. On July 2, 1998, a
Confidential Descriptive Memorandum for UPFuels ("CDM"), in which the
Company's GPM business is concentrated, was distributed to prospective
buyers. The CDM solicited offers and provided the impetus for further
discussions relating to the monetization of the Company's GPM business.
The Company received several proposals in response to the CDM and invited
certain of the bidders to further review documents and other information
relating to the Company's GPM business. The Company has initiated
discussions with a limited number of bidders seeking to consummate a
monetization transaction as soon as practicable.
6. ADVANCE PAYMENT/FORWARD SALE
In June 1998, Union Pacific Fuels, Inc. ("UPFI") entered into a forward
sale transaction. Under the terms of the forward sale agreement, UPFI
received $250.0 million in cash and is required to deliver approximately
567 MMcf of gas per day to the purchaser beginning in October 1998 and
continuing through March 1999. The Company has recorded the obligation
associated with this transaction as an advance payment. This current
liability will be amortized and recorded on the Condensed Consolidated
Statement of Income as the gas is delivered over the term of the
contract. In addition, UPFI has entered into a gas price swap to hedge
exposure to price risk associated with this transaction (see Quantitative
and Qualitative Disclosures About Market Risk in Part I, Item 3 of this
report).
7. FOREIGN CURRENCY
In the third quarter of 1998, the Company recorded a $43.4 million
non-cash foreign currency loss included in other income (expense) - net
on the Condensed Consolidated Statement of Income. The loss resulted from
U.S.-Canadian exchange rate fluctuations applied to UPRI's U.S. dollar
denominated monetary assets and liabilities (primarily debt obligations).
According to SFAS No. 52, "Foreign Currency Translation," UPRI's U.S.
dollar denominated monetary assets and liabilities must be remeasured
using the month-end exchange rate with the effects of exchange rate
fluctuations recorded immediately as a gain or loss. Translation of
UPRI's financial statements for inclusion in the consolidated results of
the Company requires recognition of the effects of such exchange rate
-10-
12
fluctuations on the Condensed Consolidated Statement of Financial
Position within the deferred foreign exchange adjustment. No recording of
an offsetting gain or loss is allowed. The Company will continue to
record gains or losses relating to UPRI's U.S. dollar denominated
monetary assets and liabilities.
8. COMMITMENTS AND CONTINGENCIES
The Company is subject to Federal, state, provincial and local
environmental laws and regulations and currently is participating in the
investigation and remediation of a number of sites. Where the remediation
costs can reasonably be determined, and where such remediation is
probable, the Company has recorded a liability. 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.
In the last ten years, the Company has disposed of significant pipeline,
refining and producing property assets. In disposition agreements in
connection therewith, the Company has made certain representations and
warranties relating to the assets sold 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 such representations
and warranties and under certain indemnities. Certain claims related to
compliance with environmental laws remain pending. In addition, some of
the representations, warranties and indemnities related to some of the
disposed assets continue to survive under such disposition agreements.
Further claims may be made against the Company under such disposition
agreements or otherwise. While no assurance can be given as to the
ultimate outcome of these claims, the Company does not expect these
matters to have a materially adverse effect on its results of operations,
financial condition or cash flows.
The Company is a defendant in a number of other lawsuits and is involved
in governmental proceedings arising in the ordinary course of business in
addition to those described above. The Company also has entered into
commitments and provided guarantees for specific financial and
contractual obligations of its subsidiaries and affiliates. The Company
does not expect these lawsuits, commitments or guarantees to have a
materially adverse effect on its results of operations, financial
condition or cash flows.
-11-
13
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Shareholders of
Union Pacific Resources Group Inc.
Fort Worth, Texas
We have reviewed the accompanying condensed consolidated statement of financial
position of Union Pacific Resources Group Inc. (a Utah corporation) and
subsidiaries as of September 30, 1998, and the related condensed consolidated
statements of income for the three month and nine month periods then ended and
the condensed consolidated statement of cash flows for the nine months then
ended. These financial statements are the responsibility of the Company's
management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and of making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with generally accepted auditing standards, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to the financial statements referred to above for them to be in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Fort Worth, Texas
October 21, 1998
-12-
14
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
In the second quarter of 1998, the Company reorganized its exploration and
production business units into five core geographic areas in the United States
and four core areas for international operations. The core areas in the United
States comprise (1) the Austin Chalk trend in Texas and Louisiana, unchanged
from the previous structure, (2) the East/West Texas business unit representing
the combination of the former East Texas and West Texas business units, (3) the
Western Region business unit consisting of the Land Grant Area in Colorado,
Wyoming and Utah, as well as additional properties in Kansas, (4) the Gulf Coast
Onshore business unit covering the onshore coastal plain of Texas and Louisiana,
and (5) the Offshore business unit, which manages the Company's Gulf of Mexico
operations. International core areas are (1) Canada, (2) Guatemala, (3)
Venezuela and (4) Other International.
RESULTS OF OPERATIONS
QUARTER ENDED SEPTEMBER 30, 1998 COMPARED TO SEPTEMBER 30, 1997
SUMMARY FINANCIAL DATA
Three Months Ended September 30,
--------------------------------
1998 1997
---- ----
(Millions of dollars)
Total operating revenues............................................ $ 642.0 $ 449.0
Total operating expenses............................................ 561.3 354.5
Operating income.................................................... 80.7 94.5
Net income (loss)................................................... (17.3) 67.2
Earnings (loss) per share - diluted................................. (0.07) 0.27
The Company recorded a loss of $17.3 million for the third quarter of 1998,
an $84.5 million decline from net income of $67.2 million for the third quarter
of last year. Earnings per share also declined to a loss of $0.07 per share
compared to earnings of $0.27 per share in 1997. The earnings decline was
primarily due to lower prices, which caused a significant decrease in income
from producing properties within exploration and production operations. Also
contributing to the decline was a $64.0 million increase in interest expense
principally related to higher debt balances resulting from the Norcen
Acquisition and a $43.4 million loss on foreign currency exchange (see Note 7 to
the Condensed Consolidated Financial Statements). Also contributing to the loss
was lower operating results from gathering, processing and marketing operations.
Offsetting benefits were provided by pretax gains of $128.5 million from the
sale of the Matagorda property and $50.2 million of reduced income taxes due to
lower pretax income.
Operating income decreased by $13.8 million (15%) to $80.7 million for the
quarter. Exploration and production operating income increased by $18.1 million
(37%) to $67.2 million, reflecting the pretax gain on sale of $128.5 million for
the Matagorda property and higher volumes. Those results were offset by lower
prices for all products and increased operating and exploration costs.
Gathering, processing and marketing operating income decreased $26.5 million to
$0.4 million, largely due to tighter margins at gas plants and increased
operating costs due to recent plant construction and expansion. Minerals
operating income decreased $1.3 million largely due to lower soda ash results,
offset by improvements in coal equity income. General and administrative costs
increased $4.1 million, principally due to the expansion of operations
associated with the Norcen Acquisition.
-13-
15
SUMMARY OF SEGMENT FINANCIAL DATA
Three Months Ended September 30,
--------------------------------
1998 1997
---- ----
(Millions of dollars)
Segment operating income:
Exploration and production...................................... $ 67.2 $ 49.1
Gathering, processing and marketing............................. 0.4 26.9
Minerals........................................................ 38.3 39.6
Corporate/general and administrative............................ (25.2) (21.1)
------- --------
Total........................................................ $ 80.7 $ 94.5
======== ========
EXPLORATION AND PRODUCTION OPERATIONS
Three Months Ended September 30,
--------------------------------
1998 1997
---- ----
(Millions of dollars)
Operating revenues................................................... $ 519.1 $ 296.1
Operating expenses:
Production........................................................ 113.1 71.8
Exploration....................................................... 79.0 58.6
Depreciation, depletion and amortization.......................... 259.8 116.6
-------- --------
Total operating expenses.......................................... 451.9 247.0
-------- --------
Operating income..................................................... $ 67.2 $ 49.1
======== ========
OPERATING REVENUES
Exploration and production revenues for the third quarter of 1998 increased
by $223.0 million (75%) to $519.1 million, $132.9 million of which were
associated with properties added in the Norcen Acquisition. In addition,
production volume increases added $8.0 million to revenues, while average
product price declines reduced revenues by $42.9 million. Other revenues were
$125.0 million higher than last year largely due to the $128.5 million gain on
sale of the Matagorda property.
Three Months Ended September 30,
--------------------------------
1998 1997 1998 1997
---- ---- ---- ----
(without hedging) (with hedging)
Average price realizations - exploration and production:
Natural gas (per Mcf).............................. $ 1.65 $ 1.90 $ 1.63 $ 1.84
Natural gas liquids (per Bbl)...................... 7.31 10.05 7.31 10.05
Crude oil (per Bbl)................................ 10.38 18.09 10.28 18.00
Average (per Mcfe)................................. 1.64 2.09 1.63 2.05
Three Months Ended September 30,
--------------------------------
1998 1997
---- ----
Production volumes - exploration and production:
Natural gas (MMcfd)............................................... 1,491.2 1,085.8
Natural gas liquids (MBbld)....................................... 32.9 26.8
Crude oil (MBbld)................................................. 152.8 50.7
Total (MMcfed).................................................... 2,605.2 1,550.5
-14-
16
Exploration and production volumes of 2,605.2 MMcfed were 1,054.7 MMcfed
higher than last year, with increases in all business units except for Western
Region, where volumes were essentially unchanged compared to last year. Expanded
international operations, primarily due to properties added in the Norcen
Acquisition, contributed volume growth of 852.6 MMcfed, and volumes for Gulf
Coast Onshore increased 40.0 MMcfed over 1997 third quarter results. Other
volume increases included Austin Chalk by 48.3 MMcfed and East/West Texas by
17.8 MMcfed. In spite of shut in production due to Hurricane Georges, Offshore
volumes improved 97.7 MMcfed, including 117.4 MMcfed from properties added in
the Norcen Acquisition.
Natural gas volumes increased 405.4 MMcfd (37%) to 1,491.2 MMcfd,
principally reflecting 398.6 MMcfd provided by Norcen Acquisition properties.
Gas production from Canada improved 304.4 MMcfd. Offshore volumes increased by
66.8 MMcfd primarily due to Norcen Acquisition properties which added 86.5
MMcfd; however, this was partially offset by the effects of shut in production
due to Hurricane Georges and the sale of the Matagorda property in the third
quarter. Gulf Coast Onshore was up 32.7 MMcfd due to continued drilling success
in Roleta and Wadsworth SE fields in South Texas, and from properties acquired
in 1997. Austin Chalk production declined 16.2 MMcfd mostly because of
production declines in the Giddings Field due to drilling capital reductions and
the strong performance of deep Washington County drilling in 1997. Offsetting
the Giddings results were production gains in East Texas and Louisiana Chalk
where production increased from last year due to continued successful drilling.
Natural gas liquid volumes increased 6.1 MBbld (23%) to 32.9 MBbld.
Improvements included 2.8 MBbld from Canada and a 2.7 MBbld increase in the
Austin Chalk from the start-up of the Masters Creek plant. In addition, natural
gas liquid volumes were up 1.7 MBbld in East/West Texas due to improved
recoveries at the East Texas plant and improvements in the gathering
infrastructure. These increases were partially offset by volume reductions of
0.7 MBbld in the Western Region reflecting plants in ethane rejection and
bypassed volumes.
Crude oil volumes of 152.8 MBbld were 102.1 MBbld higher than the third
quarter of last year reflecting increases of 92.5 MBbld from properties added in
the Norcen Acquisition, 8.0 MBbld from the Austin Chalk and 1.8 MBbld from Gulf
Coast Onshore. Canada production improved by 39.2 MBbld for the quarter, while
production from Guatemala and Venezuela were 24.6 MBbld and 20.2 MBbld,
respectively. Improvements in the Austin Chalk were the result of 1998 first
quarter discoveries in Louisiana. Gulf Coast Onshore improvements were the
result of acquisitions and production from the recently drilled Savage #2 well
in South Texas.
OPERATING EXPENSES
Production expenses increased $41.3 million to $113.1 million. Production
costs on a per unit basis were $0.47 per Mcfe, down from $0.50 per Mcfe last
year. Total lease operating expenses rose $44.9 million primarily due to the
Norcen Acquisition properties. Production overhead costs declined $2.2 million
from 1997 due to reduced legal costs, computer costs and recruiting and
relocation expenses.
Exploration expenses rose $20.4 million over the third quarter of last
year. The increase was caused by higher surrendered lease costs of $10.2
million, primarily in Gulf Coast Onshore reflecting increased leasing activity,
in East/West Texas from the Cotton Valley Reef prospect and acquired properties,
and in Canada largely due to the Norcen acquisition. Geological and geophysical
costs increased $6.4 million, relating to activity on Norcen Acquisition
properties. Dry hole expense increased $3.3 million related to Offshore
-15-
17
operations and other drilling programs on properties added in the Norcen
Acquisition, offset by lower exploratory drilling activity in Gulf Coast
Onshore.
Depreciation, depletion, and amortization ("DD&A") increased by $143.2
million, or $0.26 per Mcfe to $1.08 per Mcfe. Higher volumes created an $79.3
million increase in DD&A costs over the third quarter of last year, while a
higher per unit rate resulted in a $63.9 million increase. These increases
include DD&A expense of $118.2 million, or $1.27 per Mcfe, for properties added
in the Norcen Acquisition.
GATHERING, PROCESSING AND MARKETING OPERATIONS
Three Months Ended September 30,
--------------------------------
1998 1997
---- ----
(Millions of dollars)
Operating revenues................................................... $ 84.1 $ 111.8
Gas purchases........................................................ 30.6 37.2
-------- --------
Gross operating margin............................................ 53.5 74.6
Operating expenses:
Operating costs................................................... 34.0 29.1
Depreciation, depletion and amortization.......................... 19.1 18.6
-------- --------
Total operating expenses........................................ 53.1 47.7
-------- --------
Operating income..................................................... $ 0.4 $ 26.9
======== ========
OPERATING MARGINS
Gathering, processing and marketing gross operating margins decreased by
$21.1 million (28%) due to tighter margins at the Company's facilities caused by
low prices for natural gas liquids and high purchase prices for natural gas.
Also contributing to the decrease was a $6.4 million decline in gains on asset
sales, which included the gain on sale of the Company's interest in Frontier
Pipeline in 1997.
Gathering margins decreased by $1.1 million. The decline was caused by
lower throughput on the Ferguson Burleson pipeline and lower margins, partially
offset by benefits from new pipelines and gathering systems that were not
operating in the third quarter of 1997.
Processing margins declined by $11.5 million with tighter margins caused by
lower product prices, which declined $0.60 per Mcfe (31%). Total volumes were
down 56.6 MMcfed (19%) to 242.6 MMcfed largely due to ethane rejection or
bypassed natural gas volumes.
Three Months Ended September 30,
---------------------------------
1998 1997
---- ----
Sales volumes - plants:
Natural gas (MMcfd)............................................... 24.8 37.4
Natural gas liquids (MBbld)....................................... 36.3 43.6
Total (MMcfed).................................................... 242.6 299.2
Average product price realizations - plants:
Natural gas (per Mcf)............................................. $ 1.28 $ 2.12
Natural gas liquids (per Bbl)..................................... 7.98 11.43
Average (per Mcfe)................................................ 1.33 1.93
-16-
18
Plant natural gas liquids volumes decreased by 7.3 MBbld (17%) to 36.3
MBbld as a result of lower inlet volumes at Austin Chalk plants other than
Masters Creek, lower inlets at West Texas facilities and ethane rejection at the
Emigrant Trail plant. These decreases were partially offset by the expansion at
the Patrick Draw plant, the start-up of the Masters Creek plant and increases at
the East Texas plant due to improved efficiencies in plant and pipeline
operations. Plant natural gas volumes decreased by 12.6 MMcfd, to 24.8 MMcfd,
due to lower volumes at the Highlands facilities, partially offset by the
addition of Masters Creek plant volumes.
Marketing gross operating margins decreased by $2.1 million as improvements
from higher marketed volumes were more than offset by lower per unit margins.
Marketed volumes improved for all products, reflecting the Company's higher
exploration and production volumes.
OPERATING EXPENSES
Gathering, processing and marketing operating expenses increased by $4.9
million, primarily reflecting costs at acquired, expanded or constructed
operations and an expanded support staff. Highlands facilities added $2.0
million, Masters Creek expenses added $0.8 million and the Ladder Creek Helium
Facility also added $0.8 million.
MINERALS OPERATIONS
OPERATING INCOME Three Months Ended September 30,
--------------------------------
1998 1997
---- ----
(Millions of dollars)
Coal ................................................ $ 28.8 $ 20.5
Soda ash............................................. 9.7 18.2
Other................................................ (0.2) 0.9
-------- --------
Total............................................ $ 38.3 $ 39.6
======== ========
Minerals operating income decreased by $1.3 million compared to 1997. Soda
ash results declined $8.5 million from last year primarily reflecting the
absence of a 1997 lease bonus. Coal results improved $8.3 million primarily from
$7.9 million in higher equity income from Black Butte Coal Company ("Black
Butte") as a result of the 1997 amendment of a coal supply contract that
accelerated coal shipments.
GENERAL AND ADMINISTRATIVE AND OTHER
General and administrative expenses increased $4.1 million to $25.2 million
as a result of the Company's expanded operations due to the Norcen Acquisition,
which added $6.8 million in general and administrative expense. Partially
offsetting this increase were reduced professional and temporary costs and
personnel costs. On a per unit basis, general and administrative expenses
decreased by $0.03 per Mcfe to $0.09 per Mcfe.
Other income/expense was $56.9 million lower than last year primarily due
to a $43.4 million loss on foreign currency exchange. In addition, other
income/expense in 1997 included a $10 million partial reduction of reserves
associated with the sale of the Wilmington Field.
-17-
19
Interest expense for the quarter increased $64.0 million over last year to
$77.8 million. The increase principally reflects the borrowings made in
connection with the Norcen Acquisition.
Income taxes declined $50.2 million from the third quarter of 1997 to a
benefit of $28.0 million. This change resulted primarily from the Company's
pretax loss caused by lower prices, higher exploration, interest and DD&A costs
and the foreign currency loss. The effective tax rate was 61.9% in the third
quarter of 1998 (including $4.1 million of Section 29 credits) compared to 24.8%
in 1997 (including $4.7 million of Section 29 credits). The gains on property
sales in the U.S. create taxable income resulting in a current tax expense.
However, operating losses from the Company's international operations create
deferred tax benefits at a higher statutory rate. The combination of low
consolidated net income before tax, the current tax expense in the U.S., and the
deferred tax benefit from international operations result in inflated effective
tax rates on a consolidated basis.
NINE MONTHS ENDED SEPTEMBER 30, 1998 COMPARED TO SEPTEMBER 30, 1997
SUMMARY FINANCIAL DATA
Nine Months Ended September 30,
-------------------------------
1998 1997
---- ----
(Millions of dollars)
Total operating revenues............................................ $ 1,762.1 $ 1,425.3
Total operating expenses............................................ 1,585.2 1,029.4
Operating income.................................................... 176.9 395.9
Net income (loss)................................................... (3.4) 258.8
Earnings (loss) per share - diluted................................. (0.01) 1.03
A loss of $3.4 million or $0.01 per share for year-to-date 1998 represented
a $262.2 million decline from earnings of $258.8 million or $1.03 per share in
1997. The net income decrease includes the impacts of average price declines of
more than 20%, $159.8 million of higher interest expenses and $27.6 million of
lower operating income from gathering, processing and marketing. Benefits to net
income were provided by the $128.5 million gain on the sale of the Matagorda
property, the $30.0 million gain on the settlement of a gas supply agreement and
the $26.0 million gain on the sale of the DJ Basin properties. Also contributing
was strong operating income from the minerals business.
Operating income decreased by $219.0 million (55%) to $176.9 million for
the first nine months of 1998. Exploration and production operating income
declined $192.4 million to $83.6 million, reflecting lower prices for all
products and increased operating, exploration and DD&A costs, which offset
higher volumes and the gain on sale of the Matagorda and DJ Basin properties.
Gathering, processing and marketing operating income decreased $27.6 million, as
tighter margins at gas plants more than offset the settlement on the gas supply
agreement. Minerals operating income improved $13.5 million, reflecting the
effects of the amended coal supply agreement. General and administrative costs
increased $12.5 million, principally reflecting administrative costs of expanded
international operations.
-18-
20
SUMMARY OF SEGMENT FINANCIAL DATA
Nine Months Ended September 30,
-------------------------------
1998 1997
---- ----
(Millions of dollars)
Segment operating income:
Exploration and production...................................... $ 83.6 $ 276.0
Gathering, processing and marketing............................. 53.2 80.8
Minerals........................................................ 113.7 100.2
Corporate/general and administrative............................ (73.6) (61.1)
---------- ---------
Total........................................................ $ 176.9 $ 395.9
========== =========
EXPLORATION AND PRODUCTION OPERATIONS
Nine Months Ended September 30,
-------------------------------
1998 1997
---- ----
(Millions of dollars)
Operating revenues................................................... $ 1,346.6 $ 993.9
Operating expenses:
Production........................................................ 336.1 216.7
Exploration....................................................... 229.6 150.6
Depreciation, depletion and amortization.......................... 697.3 350.6
---------- ---------
Total operating expenses.......................................... 1,263.0 717.9
---------- ---------
Operating income..................................................... $ 83.6 $ 276.0
========== =========
OPERATING REVENUES
Exploration and production revenues increased by $352.7 million (35%),
$332.1 million of which were associated with properties added in the Norcen
Acquisition. Excluding the Norcen Acquisition properties, volume increases added
$41.6 million to revenues; however, product price declines reduced revenues by
$147.5 million. Other revenues increased $126.5 million principally from the
gains on sale of the Matagorda and DJ Basin properties. Other revenues in 1997
included the partial reduction of the Columbia Gas Transmission Company
bankruptcy settlement reserve ($12.0 million).
Nine Months Ended September 30,
-------------------------------
1998 1997 1998 1997
---- ---- ---- ----
(without hedging) (with hedging)
Average price realizations - exploration and production:
Natural gas (per Mcf).............................. $ 1.78 $ 2.08 $ 1.79 $ 2.03
Natural gas liquids (per Bbl)...................... 8.07 11.17 8.07 11.17
Crude oil (per Bbl)................................ 10.71 19.00 10.76 18.54
Average (per Mcfe)................................. 1.75 2.27 1.75 2.22
Nine Months Ended September 30,
-------------------------------
1998 1997
---- ----
Production volumes - exploration and production:
Natural gas (MMcfd)............................................... 1,452.9 1,110.5
Natural gas liquids (MBbld)....................................... 34.4 29.7
Crude oil (MBbld)................................................. 138.1 51.3
Total (MMcfed).................................................... 2,487.8 1,596.5
-19-
21
Exploration and production volumes improved 891.3 MMcfed to 2,487.8 MMcfed
for the first nine months of 1998. Canada volumes were 471.3 MMcfed higher than
last year, while other international volumes increased from 12.2 MMcfed, in both
cases primarily due to properties added in the Norcen Acquisition. Other
increases included Gulf Coast Onshore by 34.6 MMcfed, Austin Chalk by 31.4
MMcfed and East/West Texas by 22.4 MMcfed. Offshore volumes improved 104.0
MMcfed, including 100.8 MMcfed from properties added in the Norcen Acquisition.
Natural gas volumes increased 342.4 MMcfd (31%). Canada volumes increased
by 257.2 MMcfd and Offshore production was up 76.7 MMcfd, largely due to
properties added in the Norcen Acquisition. Gulf Coast Onshore production was
28.9 MMcfd higher from continued drilling success in the Roleta Field and
volumes from acquired properties. East/West Texas volumes improved 15.6 MMcfd
from development drilling in East Texas. Partially offsetting these improvements
was a 58.0 MMcfd decline in the Austin Chalk. In 1997, Austin Chalk volumes
reflect results of new well performance in Washington County.
Natural gas liquids volumes increased 4.7 MBbld (16%) to 34.4 MBbld.
Production improvements included 4.0 MBbld in the Austin Chalk resulting from
the start-up of the Masters Creek gas plant and 2.5 MBbld from Canada properties
acquired in the Norcen Acquisition. These increases were partially offset by 3.1
MBbld of lower volumes from the Western Region, reflecting plants in ethane
rejection and bypassed volumes.
Crude oil volumes were 86.8 MBbld higher in 1998 primarily reflecting
properties added in the Norcen Acquisition and an 11.0 MBbld improvement from
the Austin Chalk, reflecting drilling success in Louisiana. Canada production
was 33.2 MBbld higher for the period, while production from Guatemala and
Venezuela was 20.4 MBbld and 15.3 MBbld, respectively.
OPERATING EXPENSES
Production expenses increased $119.4 million, with production costs of
$0.49 per Mcfe slightly less than last year's $0.50 per Mcfe. Total lease
operating expenses rose $117.2 million, of which $96.4 million was attributable
to Norcen Acquisition properties. The remainder of the lease operating expense
increase largely reflects higher personnel costs due to other acquisitions and
salt water disposal costs in the Austin Chalk, East/West Texas and Gulf Coast
Onshore. Production overhead costs were up $4.8 million largely because of
increased personnel costs due to the expanded operations.
Exploration expenses increased $79.0 million over year-to-date last year,
with activity relating to properties added in the Norcen Acquisition
contributing $64.3 million. Other increases were primarily the result of a $27.8
million increase in surrendered lease costs, relating to the Cotton Valley Reef
and other acquired properties in East/West Texas, and increased leasing activity
in Gulf Coast Onshore. Dry hole expenses not associated with Norcen Acquisition
properties were down $9.0 million due to the reduced exploratory drilling
program for domestic properties, while delay rentals decreased $3.9 million from
last year.
DD&A increased by $346.7 million, including $289.8 million related to
properties added in the Norcen Acquisition. On a per unit basis, DD&A expense
rose $0.23 per Mcfe to $1.03 per Mcfe. Higher volumes caused $195.9 million of
the total increase in DD&A, while a higher per unit rate added $146.8 million.
In addition, the 1998 write-off of two Offshore fields contributed $4.0 million
to the increase.
-20-
22
GATHERING, PROCESSING AND MARKETING OPERATIONS
Nine Months Ended September 30,
-------------------------------
1998 1997
---- ----
(Millions of dollars)
Operating revenues................................................... $ 300.0 $ 326.2
Gas purchases........................................................ 93.7 116.3
-------- ---------
Operating margin.................................................. 206.3 209.9
Operating expenses:
Operating costs................................................... 99.5 79.3
Depreciation, depletion and amortization.......................... 53.6 49.8
-------- ---------
Total operating expenses........................................ 153.1 129.1
-------- ---------
Operating income..................................................... $ 53.2 $ 80.8
======== =========
OPERATING MARGINS
Gathering, processing, and marketing margins decreased by $3.6 million to
$206.3 million due to tighter plant margins reflecting low natural gas liquid
prices. This decrease was partially offset by the $30 million gain on the gas
supply agreement settlement. In addition, 1997 margins include the gain on the
sale of the Company's interest in Frontier Pipeline ($6.4 million).
Gathering margins decreased by $2.0 million, principally reflecting lower
throughput on the Ferguson Burleson pipeline and lower margins. Partially
offsetting the decline were higher volumes at Panola pipeline and benefits from
pipelines and gathering systems acquired or placed in service since the third
quarter of last year.
Processing margins decreased by $24.1 million with tighter margins caused
by lower product prices, which declined by $0.51 per Mcfe (25%), partly offset
by contributions from Highlands plants acquired in 1997.
Nine Months Ended September 30,
-------------------------------
1998 1997
---- ----
Sales volumes - plants:
Natural gas (MMcfd)............................................... 22.4 26.3
Natural gas liquids (MBbld)....................................... 40.3 41.3
Total (MMcfed).................................................... 264.4 274.3
Nine Months Ended September 30,
-------------------------------
1998 1997
---- ----
Average product price realizations - plants:
Natural gas (per Mcf)............................................. $ 1.74 $ 2.21
Natural gas liquids (per Bbl)..................................... 8.89 11.95
Average (per Mcfe)................................................ 1.50 2.01
Plant natural gas liquids volumes decreased by 1.0 MBbld primarily as a
result of ethane rejection in the Western Region which offset the addition of
the Highlands plants and the start-up of Masters Creek. Plant natural gas
volumes decreased by 3.9 MMcfd over the first nine months of last year.
-21-
23
Marketing operating margins increased by $26.0 million as the $30.0 million
gain from the gas supply agreement settlement and higher marketed volumes were
partly offset by lower per unit realizations.
OPERATING EXPENSES
Gathering, processing and marketing expenses increased by $20.2 million
primarily reflecting costs at acquired, expanded or constructed operations, as
well as increases in support staff.
DD&A increased by $3.8 million with the addition of the Highlands assets,
Masters Creek plant and the Blacklake pipeline. Offsetting declines occurred at
Ferguson Burleson pipeline and at the Brookeland plant reflecting the revision
of estimated asset lives.
MINERALS OPERATIONS
Nine Months Ended September 30,
-------------------------------
OPERATING INCOME 1998 1997
---- ----
(Millions of dollars)
Coal .................................................. $ 86.2 $ 61.6
Soda ash............................................... 26.1 37.3
Other.................................................. 1.4 1.3
--------- --------
Total.............................................. $ 113.7 $ 100.2
========= ========
Minerals operating income increased by $13.5 million (13%), principally the
result of $23.7 million of higher equity income from Black Butte reflecting the
amendment of a coal supply contract. The improvement was offset by an $11.2
million decline from soda ash operations, reflecting lower royalties, the
absence of a 1997 lease bonus and lower equity income from the Company's soda
ash joint venture.
GENERAL AND ADMINISTRATIVE AND OTHER
General and administrative expenses increased $12.5 million (20%) to $73.6
million, principally reflecting $14.4 million relating to expanded international
operations, partially offset by $3.2 million reduction (39%) in professional and
temporary services. On a per unit basis, general and administrative expenses
decreased by $0.02 per Mcfe to $0.09 per Mcfe.
Other income/expense was $42.4 million lower than 1997 primarily as a
result of the $43.4 million foreign currency exchange rate loss and the
inclusion in 1997 of a $10.0 million partial reduction of reserves associated
with the sale of Wilmington Field. Partially offsetting the declines was an
$11.0 million gain on the closure of a foreign exchange contract entered into in
connection with the Norcen Acquisition.
Interest expense increased $159.8 million to $195.3 million. This increase
reflects the borrowings made in connection with the Norcen Acquisition and
capital spending programs.
Income taxes declined $159.0 million for the first nine months of 1998
compared to last year to a benefit of $47.8 million. This decline is primarily
the result of the pretax net loss in 1998. Included in 1998 are $12.3 million of
Section 29 credits compared to $14.2 million of Section 29 credits in the first
nine months of 1997.
-22-
24
LIQUIDITY AND CAPITAL RESOURCES
The Company's primary source of cash during the first nine months of 1998
was cash provided by operations, debt financing, sales of assets and contract
settlements. Cash outflows for the first nine months of 1998 include the
purchase price for Norcen, capital and exploratory expenditures and the
repurchase of common stock by the Company.
Cash provided by operations for the first nine months of 1998 increased
$191.6 million (24%) compared to the same period of 1997, as the benefit of
significantly higher volumes was offset by lower sales prices for the Company's
oil and gas products, tighter margins from gathering, processing and marketing
operations and higher interest expense associated with higher debt levels. Cash
from operations also includes two non-recurring items: the collection of an
acquired note receivable relating to Norcen's 1997 partial sale of Superior
Propane ($85.4 million) and the closure of certain commodity and foreign
currency financial contracts also acquired in the Norcen Acquisition ($63.9
million).
Cash used in investing activities for the first nine months of 1998 rose
$2.3 billion over 1997. This increase primarily reflects the $2.6 billion
purchase price for Norcen and a $50.2 million increase in other capital and
exploratory expenditures. These increases were partly offset by a $358.5 million
improvement in proceeds from asset sales and contract settlements. In 1998,
these asset sales and settlements include proceeds from the sales of the
Matagorda ($158.0 million) and the DJ Basin properties ($41.0 million), the sale
of the remaining investment in Superior Propane ($48.4 million) and proceeds
from settlements of gas supply contracts acquired in the Norcen Acquisition
($70.3 million). In addition, the Company entered into a forward sale agreement
that provided $250.0 million, which is included in cash provided by financing
activities (see Note 6 to the Condensed Consolidated Financial Statements).
Capital and exploratory expenditures for the first nine months of 1998,
excluding the Norcen Acquisition, were $1.24 billion, an increase of 4% over
last year. Expenditure categories are as follows:
Nine Months Ended September 30,
-------------------------------
1998 1997
---- ----
(Millions of dollars)
Capital and exploratory expenditures:
Exploration and production........................................ $ 1,066.1 $ 849.6
Gathering, processing and marketing............................... 135.7 323.2
Minerals and other................................................ 38.1 16.9
--------- ---------
Total........................................................ $ 1,239.9 $ 1,189.7
========= =========
Exploration and production capital spending for the first nine months of
1998 increased by $216.5 million (25%) over last year, reflecting increases in
development drilling ($156.9 million), exploratory drilling ($41.5 million) and
production facilities and equipment ($91.6 million). Development drilling
increases were concentrated in the Austin Chalk, Canada and other international
areas, while exploratory drilling focused in the Gulf Coast Onshore and Offshore
areas. Production facility capital reflects spending on properties added in the
Norcen Acquisition to support production operations. Offsetting these increases
was a $144.9 million decline in lease acquisition spending reflecting the more
active leasing programs in 1997.
-23-
25
Gathering, processing and marketing spending declined by $187.5 million.
Spending in 1997 reflects the acquisition of Highlands Gas Corporation for
$179.4 million. Other spending was up $21.2 million, primarily reflecting
spending relating to the Company's relocation to a new headquarters building.
The Company's Board of Directors has authorized management to proceed with
a deleveraging program designed to reduce the Company's debt and obtain a strong
investment grade credit rating. The program included the Company's plans to sell
approximately $600 million of producing properties. The Company's current
forecast shows that the $600 million target will be achieved by year-end, but
with a different mix of properties being sold than was originally disclosed.
Completed sales include the DJ Basin properties, the Matagorda property, several
Western Region properties and most of the Canadian properties originally
identified for divestiture. In addition, agreements have been reached to sell
interests in certain South Texas properties for $148 million, certain Gulf of
Mexico properties, a Western Region property and a Canadian property. Additional
properties are scheduled to be sold in early 1999. All of the properties
identified for sale in the aggregate represent approximately ten percent of the
Company's reserves, production volumes and cash flows.
In connection with this deleveraging program, the Board of Directors also
authorized management to pursue potential monetization of the Company's
gathering, processing and marketing ("GPM") business. On July 2, 1998, a
Confidential Descriptive Memorandum for UPFuels ("CDM"), in which the Company's
GPM business is concentrated, was distributed to prospective buyers. The CDM
solicited offers and provided the impetus for further discussions relating to
the monetization of the Company's GPM business. The Company received several
proposals in response to the CDM and invited certain of the bidders to further
review documents and other information relating to the Company's GPM business.
The Company has initiated discussions with a limited number of bidders seeking
to consummate a monetization transaction as soon as practicable.
As of September 30, 1998 and December 31, 1997, the total capitalization of
the Company was as follows:
September 30, December 31,
1998 1997
---- ----
(Millions of dollars)
Long-term debt:
Commercial paper and other, net...................................... $ 2,332.2 $ 663.1
Notes and debentures................................................. 2,225.0 550.0
Tax exempt revenue bonds............................................. 20.1 20.1
(Discount) premium on notes and debentures - net..................... 8.4 (2.6)
--------- ----------
Total long-term debt.............................................. 4,585.7 1,230.6
Shareholders' equity....................................................... 1,655.8 1,760.7
--------- ----------
Total capitalization................................................. $ 6,241.5 $ 2,991.3
========= ==========
Debt to total capitalization......................................... 73.5% 41.1%
During the first quarter of 1998, in connection with the Norcen
Acquisition, the Company issued commercial paper supported by its $2.7 billion
364 Day Competitive Advance/Revolving Credit Agreement (the "Norcen Acquisition
Facility"), and also assumed the net debt of Norcen, aggregating approximately
$1.0 billion. In October 1998, the Company replaced its eight existing
facilities (the Norcen Acquisition Facility, its $600 million and $300 million
revolving credit agreements and five Canadian facilities), which totaled
approximately U.S.$2.9 billion. The facilities were replaced with three new
facilities totaling an
-24-
26
aggregate of U.S.$2.5 billion. These new facilities are 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 Five-Year Competitive Advance/Revolving Credit
Agreement (collectively the "Facilities"). Each of the Facilities contain 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. This covenant
replaces the consolidated debt to total capitalization ratio covenant applicable
under previous facilities. The Bridge Facility also contains mandatory reduction
provisions whereby it will be permanently reduced by seventy-five percent of the
net proceeds from specified asset sales (certain identified asset sales and the
monetization of the Company's gathering, processing and marketing business). The
Facilities also place other restrictions on the Company regarding the creation
of liens, incurrance of additional indebtedness of 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.
Excluding commercial paper, the Company has no debt maturing in the next
four years. All debt of the Company has been classified as long-term reflecting
the Company's intent and ability to maintain any short-term commercial paper
borrowings on a long-term basis either through the issuance of additional
commercial paper or debt securities. In the second quarter of 1998, the Company
issued $1.025 billion of notes and debentures, with interest rates ranging from
6.5% to 7.15% and maturities from 2005 through 2028. The proceeds from this
issuance were used to repay outstanding commercial paper.
The Company has initiated a deleveraging program directed toward reducing
its debt levels and improving cash flow coverage ratios. In addition to the
asset sales, the Company has taken steps to reduce its 1998 capital spending to
approximate its anticipated cash flow for the year. The lower capital spending
levels are also in response to the weakness of crude oil, natural gas and
natural gas liquids prices and higher debt service requirements. Capital
spending plans in 1998 have declined from an original range (before the Norcen
Acquisition) of $1.5 to $1.8 billion to the current projection of approximately
$1.3 billion.
During 1998, the Company has purchased $22.1 million of its common stock.
During 1998, the Company has paid quarterly cash dividends of $0.05 per share on
its outstanding common stock, and on October 29 declared a $0.05 per share
dividend to be paid on January 2, 1999.
The extent and timing of capital spending may be affected by changes in
business, financial and operating conditions as well as by the timing and
availability of suitable investment opportunities. For example, the Company has
spent over ninety percent of its projected 1998 capital budget in the first nine
months of the year. As a result, the capital spending rate will decrease
significantly in the remaining months of 1998, resulting in decreased drilling
activity. Capital spending for 1998 has and will be funded primarily through
cash provided by operations as well as certain cash generating strategies that
have occurred during the year. Drilling is expected to be concentrated in the
Gulf of Mexico, Austin Chalk, western Canada and Guatemala. The Company expects
to increase its total annual sales volumes in 1998 by more than 50% over 1997,
while increasing its hydrocarbon reserves. The sales volume growth over 1997 is
expected to be achieved primarily as a result of the Norcen Acquisition.
Prices for oil and natural gas have declined during 1998 as a result of
several contributing factors, including, but not limited to, high production
levels from members of the Organization of Petroleum Exporting Countries and
other countries, generally mild weather conditions and the economic weakness in
-25-
27
several Asian countries. These price declines have had a negative near-term
impact on the cash flows from the Company's production activities. If the weak
prices continue and if the Company determines that such price declines have
longer-term negative implications, the Company will revise its long-term price
forecasts utilized in its periodic evaluations of potential asset impairments.
In addition, as part of its normal year-end process, the Company will evaluate
its reserves, including those acquired in the Norcen Acquisition, which are also
being reviewed for the purpose of purchase price allocation as required under
Accounting Principles Board Opinion No. 16, "Accounting for Business
Combinations." If weak prices continue and the quantity of proved reserves
determined by such evaluations are not sufficient to recover the current book
value of the investment, the Company may be required to write-down the book
value of certain producing properties and recognize non-cash charges to earnings
in the fourth quarter of 1998.
YEAR 2000 ISSUE
The Company has established a formal Year 2000 Readiness Program to
address the Company's issues relating to the Year 2000. Program activities are
directed by a Program Management Office staffed with a Year 2000 Program
Manager, several senior Information Technology ("IT") project managers and
representatives from key internal functions including exploration & production,
operations, purchasing, finance and legal. The Program Management Office
operates under the oversight of a Year 2000 Executive Steering Committee and the
Audit Committee of the Board of Directors. The Company has engaged CSC
Consulting ("CSC") during the inventory and assessment phases of the program and
continues to make use of CSC services for program management recommendations and
reviews. The Company has also engaged the law firm of Morgan, Lewis & Bockius
LLP for legal advice on Year 2000 related issues.
The general phases for the Company's Year 2000 Readiness Program are (1)
inventory of Year 2000 items; (2) assessment of business criticality and
compliance status of inventory items; (3) remediation and verification planning
for items determined to be material to the company; (4) remediation (including
repairing, retiring, replacing or preparing work-arounds) of material items that
are determined not to be Year 2000 compliant; (5) verification that material
items are Year 2000 compliant; and (6) business continuity and contingency
planning for material business processes related to Year 2000 items.
The Company's Year 2000 Readiness Program is organized around the following
major program areas:
o Information technology ("IT") infrastructure
o Information systems
o Process control and embedded technology
o Third party suppliers, partners, customers and governmental entities
The IT infrastructure program area is currently in the remediation phase
with approximately one third of the items already progressing into the
verification phase. Activity in this area primarily involves installing and
testing upgrades and software service releases supplied by vendors. Verification
of Year 2000 compliance is currently anticipated by the end of the first quarter
in 1999. Contingency planning and periodic contingency reviews are scheduled to
commence in the fourth quarter for 1998, and continue through mid-1999.
The information systems program area is currently in the remediation phase.
Between 1993 and 1997, the Company replaced its inventory of information systems
and eliminated its entire mainframe computing environment. A large proportion
(over 80%) of the Company's Year 2000 remediation work was completed as a
by-product of this wholesale system replacement. Remaining activity in this area
primarily involves
-26-
28
installing and testing new versions of applications software packages as they
are made available by software vendors. Completion is dependent on several
vendors' delivery schedules, but is currently anticipated by mid-1999.
Contingency planning and periodic contingency reviews are scheduled to commence
in fourth quarter of 1998, and continue through mid-1999.
The process control and embedded technology program area is currently in
the remediation and verification planning phase. Remaining activity in this area
primarily involves implementing software upgrades to selected equipment and
verifying the Year 2000 compliance of process control and embedded technology
equipment. The Company currently anticipates completion by mid-1999 of both the
remediation and verification activities. Contingency planning for this area is
scheduled to commence in the second quarter of 1999 and continue through the
remainder of 1999.
The third-party suppliers, partners, customers and governmental entities
program area is currently in the verification planning phase. The assessment
phase was completed in the second quarter of 1998 and included the process of
identifying and prioritizing external entities. Approximately 400 third party
entities were contacted and surveyed concerning their Year 2000 plans and
readiness during the assessment phase. Verification activities and development
of contingency plans are scheduled to commence in the fourth quarter of 1998
with completion by mid-1999.
The total cost of the Company's Year 2000 Readiness Program is not
expected to be material to the Company's financial position. Not including the
cost of replacing its information systems between 1993 and 1997, the Company
anticipates spending a total of approximately $2.5 million dollars during 1998
and 1999 for Year 2000 related modifications and testing. This estimate 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. Year-to-date 1998 expenditures through September are $1.0 million.
Due to the general uncertainty inherent in the Year 2000 problem,
resulting in large part from the uncertainty of the Year 2000 readiness of
third-party suppliers, partners and customers, the Company is unable to
determine at this time whether the consequences of Year 2000 failures will have
a material impact on the Company's results of operations, liquidity or financial
condition. The Company's Year 2000 Readiness Program is expected to
significantly reduce the Company's level of uncertainty about Year 2000 issues.
The Company believes that, with the completion of the Year 2000 Readiness
Program, the possibility of significant interruptions of normal operations
should be reduced.
The Company believes that the most reasonably likely worst case Year 2000
scenarios are as follows: (i) unanticipated Year 2000 induced failures in
information systems could cause a reliance on manual contingency procedures and
significantly reduce efficiencies in the performance of certain normal business
activities; (ii) unanticipated failures in embedded technology or process
control systems due to Year 2000 causes could result in temporarily suspending
operations at certain operating facilities with consequent loss of revenue; and
(iii) slow downs or disruptions in the third party supply chain due to Year 2000
causes could result in operational delays and reduced efficiencies in the
performance of certain normal business activities.
FORWARD LOOKING INFORMATION
Certain information included in this quarterly report and other materials
filed by the Company with the Securities and Exchange Commission contain
projections and other forward looking statements within the meaning of Section
21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the
-27-
29
Securities Act of 1933, as amended. Such forward looking statements may be or
may concern, among other things, capital expenditures, drilling activity,
acquisitions and dispositions (including the timing of the completion of the
Company's deleveraging program), development activities, cost savings efforts,
production activities and volumes, hydrocarbon reserves, hydrocarbon prices,
hedging activities and the results thereof, liquidity, regulatory matters and
competition. Such forward looking statements generally are accompanied by words
such as "estimate," "expect," "predict," "anticipate," "goal," "should,"
"assume," "believe" or other words that convey the uncertainty of future events
or outcomes.
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 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 hydrocarbon prices 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; 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 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 and deleveraging program and the
availability of technology may affect the amount and timing of such capital
expenditures and drilling activity. With respect to the Company's deleveraging
program, factors such as the ability to identify qualified buyers, the buyer's
ability to obtain financing (if necessary), successful negotiation of contract
terms and completion of due diligence may affect the success and timing of the
completion of the program. 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, deleveraging programs, uncertainties inherent in estimating
reserve quantities and the availability of technology may affect such production
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, factors such as changes in
oil and gas prices, the Company's success in acquiring or divesting producing
properties or other assets, environmental matters and other contingencies,
hedging activities, the Company's credit rating and debt levels, and the state
of domestic capital markets may affect the Company's ability to generate
expected cash flows. With respect to contingencies, factors such as changes in
environmental and other 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 or financial condition of the
Company. Certain factors, such as changes in oil and 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.
-28-
30
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company has established policies and procedures for managing risk
within its organization. These policies and procedures incorporate internal
controls and are governed 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.
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, when this is done, these same instruments may also limit future gains
from favorable price movements. Such risk management activities are generally
accomplished pursuant to exchange-traded futures and over-the-counter swaps and
options.
Recognition of realized gains/losses and option premium payments/receipts
in the Condensed Consolidated Statements of Income is deferred until the
underlying physical product is purchased or sold. Unrealized gains/losses on
derivative financial instruments are not recorded. Margin deposits, deferred
gains/losses on derivative financial instruments and net premiums are included
in other current assets or liabilities in the Condensed Consolidated Statements
of Financial Position. The cash flow impact of derivative and other financial
instruments is reflected as cash flows from operations in the Condensed
Consolidated Statements of Cash Flows. At September 30, 1998, the Company had
margin deposits of $3.7 million.
The following table summarizes the Company's open positions as of September
30, 1998, which hedge the Company's future oil and gas production:
UNRECOGNIZED
CONTRACT WEIGHTED FAIR VALUE GAIN/(LOSS)
PRODUCT TYPE TIME PERIOD VOLUME AVG. PRICE (MILLIONS) (MILLIONS)
------- ---- ----------- ------ ---------- ---------- ----------
Gas Puts Purchased Nov - Dec 1998 1.0Bcfd $ 2.15 $ 3.8 ($5.0)
Gas Puts Purchased Jan - Mar 1999 1.0Bcfd $ 2.15 $ 11.2 ($1.9)
Gas Calls Sold Apr - Oct 1999 1.0Bcfd $ 2.54 $ 16.7 $ 5.2
Gas Swaps Nov - Dec 1998 0.8Bcfd Var. ($0.8) ($0.8)
Gas Swaps Jan - Mar 1999 0.8Bcfd Var. $ 0.9 $ 0.9
Gas Swaps Apr - Oct 1999 0.8Bcfd Var. ($1.7) ($1.7)
Gas Fixed Price Nov'98 - Jun'08 57.6Bcf $ 3.03 $ 23.3 $ 23.3
Gas Fixed Price Nov'98 - Jun'11 253.8Bcf $ 2.79 $ 78.5 $ 78.5
Oil Puts Purchased Nov - Dec 1998 70MBbld $ 14.83 $ 2.0 ($0.3)
Oil Calls Sold Nov - Dec 1998 1MBbld $ 21.00 $ 0.0 $ 0.1
Oil Swaps Jan'99 - Dec'00 2MBbld $ 11.94 ($1.4) ($1.4)
Oil Fixed Price Nov - Dec 1998 2MBbld $ 10.80 ($0.2) ($0.2)
Oil Fixed Price Nov'98 - Mar'99 10MBbld $ 10.13 ($1.2) ($1.2)
Oil Fixed Price Nov'98 - Aug'99 2MBbld $ 10.34 ($0.3) ($0.3)
------- -------
Totals: $ 130.8 $ 95.2
-29-
31
In connection with purchase accounting adjustments relating to the Norcen
Acquisition, an asset has been recorded on the balance sheet for $104.8 million
representing the fair value of acquired futures contracts and fixed price
positions. The value of this asset will be amortized over the contract terms.
Excluding the $72.0 million unamortized value of the asset remaining at
September 30, 1998, the Company's unrecognized gain relating to hedges of oil
and gas production at September 30, 1998, was $23.2 million.
UPFI enters into financial contracts in conjunction with transportation,
storage and customer service programs. The following table summarizes UPFI's
open positions as of September 30, 1998:
UNRECOGNIZED
CONTRACT WEIGHTED FAIR VALUE GAIN/(LOSS)
PRODUCT TYPE TIME PERIOD VOLUME AVG. PRICE (MILLIONS) (MILLIONS)
------- ---- ----------- ------ ----------- ---------- ----------
Gas Futures/Swaps Nov'98 - Dec'04 205.7Bcf $2.26 ($4.4) ($4.4)
Purchased
Gas Futures/Swaps Nov'98 - Dec'04 21.5Bcf $2.33 ($0.6) ($0.6)
Sold
----- -----
Totals: ($5.0) ($5.0)
Additionally, the Company had previously sold near-term futures contracts
and swaps for August through December 1998 with respect to notional natural gas
volumes of 47 MMcfd. Subsequently, these positions were offset by purchasing
corresponding volumes through futures contracts and swaps for the same delivery
periods. The unrecognized gain at September 30, 1998, relating to these
transactions was $0.1 million.
Unrecognized mark-to-market gains and losses were determined based on
current market prices, as quoted by recognized dealers, assuming round lot
transactions and using a mid-market convention without regard to market
liquidity.
TRADING ACTIVITIES
UPR Energy Services Inc., a wholly-owned subsidiary of 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 Condensed Consolidated Statement of
Income. In addition, the fair value of unsettled positions is immediately
included in the Condensed Consolidated Statement of Financial Position as a
current asset or current liability. The net pretax loss recorded in the
Condensed Consolidated Statement of Income relating to these activities for the
third quarter was $1.6 million and the nine months ended September 30, 1998, was
$1.8 million.
-30-
32
The following table summarizes UPR Energy Services Inc. open positions as of
September 30, 1998:
CONTRACT WEIGHTED FAIR VALUE
PRODUCT TYPE TIME PERIOD VOLUME AVG. PRICE (MILLIONS)
------- ---- ----------- ------ ---------- ----------
Gas Futures/Swaps Oct'98 - Dec'99 30.9Bcf $ 2.15 ($1.8)
Purchased
Gas Futures/Swaps Oct'98 - Dec'99 54.3Bcf $ 2.05 $1.2
Sold
Oil Futures/Swaps Oct'98 - Jun'99 838MBbl $16.59 0
Purchased
Oil Futures/Swaps Oct'98 - Jun'99 869MBbl $16.49 ($0.1)
Sold
-----
($0.7)
INTEREST RATE SWAPS
The Company periodically enters into rate swaps and contracts to hedge
certain interest rate transactions. As of September 30, 1998, the Company had no
interest rate swap positions open. During the third quarter, the Company entered
into $300 million of rate lock contracts to hedge interest rates related to a
contemplated bond issuance. At September 30, 1998, the unrecognized loss
associated with these contracts was $15 million.
FOREIGN CURRENCY CONTRACTS
The Company periodically enters 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 a $348 million notional amount and maturities between March 1998
and December 1999, for which a $15.5 million deferred liability was recorded on
the Condensed Consolidated Statement of Financial Position representing the fair
value of these contracts. This deferred liability will be amortized over the
contract terms. The unrecognized loss on such contracts at September 30, 1998,
excluding the $9.8 million remaining unamortized deferred liability recorded in
purchase accounting, was $30.9 million.
CREDIT RISK
Credit risk is the risk of loss as a result of nonperformance 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 credit risk. At
September 30, 1998, the Company's largest credit risk associated with any single
counterparty, represented by the net fair value of open contracts, was $4.0
million.
-31-
33
PART II. OTHER INFORMATION
ITEM 1. 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, personal injury claims and
environmental claims. While management of the Company 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. Refer to the
Company's Annual Report on Form 10-K for additional information regarding such
proceedings.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) EXHIBITS
11 Computation of earnings per share
12 Computation of ratio of earnings to fixed charges
15 Awareness letter of Arthur Andersen LLP dated November 6, 1998
27 Financial data schedule
(b) REPORTS ON FORM 8-K
None.
-32-
34
SIGNATURE
Pursuant to the requirements 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.
Dated: November 6, 1998
UNION PACIFIC RESOURCES GROUP INC.
(Registrant)
/s/ Morris B. Smith
---------------------------------
Morris B. Smith,
Vice President and Chief Financial Officer
(Chief Financial Officer and
Duly Authorized Officer)
-33-
35
UNION PACIFIC RESOURCES GROUP INC.
EXHIBIT INDEX
Exhibit No. Description
- ----------- -----------
11 Computation of earnings per share
12 Computation of ratio of earnings to fixed charges
15 Awareness letter of Arthur Andersen LLP dated November 6, 1998
27 Financial data schedule