1996
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996
COMMISSION FILE NUMBER: 1-12088
UNITED MERIDIAN CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 75-2160316
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1201 LOUISIANA
SUITE 1400 77002
HOUSTON, TEXAS (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code: (713) 654-9110
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- --------------------
Common Stock, $0.01 par value New York Stock Exchange
10-3/8% Senior Subordinated Notes due 2005 New York Stock Exchange
Rights to Purchase Series A Junior Preferred Stock New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS
REQUIRED TO BE FILED BY SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE
REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO SUCH
FILING REQUIREMENTS FOR THE PAST 90 DAYS. YES X NO _______
------
INDICATE BY CHECK MARK IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO ITEM 405
OF REGULATION S-K IS NOT CONTAINED HEREIN, AND WILL NOT BE CONTAINED, TO THE
BEST OF REGISTRANT'S KNOWLEDGE, IN DEFINITIVE PROXY OR INFORMATION STATEMENTS
INCORPORATED BY REFERENCE IN PART III OF THIS FORM 10-K OR ANY AMENDMENT TO THIS
FORM 10-K. [X]
THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES OF THE
REGISTRANT AS OF FEBRUARY 28, 1997 WAS $985,302,563 BASED UPON A CLOSING
PRICE OF $30 1/8 PER SHARE.
INDICATE THE NUMBER OF SHARES OUTSTANDING OF EACH OF THE REGISTRANT'S CLASSES
OF COMMON STOCK, AS OF THE LATEST PRACTICABLE DATE.
NUMBER OF SHARES OUTSTANDING
TITLE OF EACH CLASS AT FEBRUARY 28, 1997
------------------- ----------------------------
Common Stock, $0.01 par value 35,248,805
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's Proxy Statement pertaining to the Registrant's
1997 Annual Meeting of Stockholders are incorporated by reference into Part III
hereof.
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TABLE OF CONTENTS
Page
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Part I. Items 1. and 2. Business and Properties
(a) General................................................................................. 1
(b) Business Strategy....................................................................... 1
(c) Oil and Gas Properties.................................................................. 3
(d) Reserves................................................................................ 7
(e) Acreage and Productive Wells............................................................ 8
(f) Production, Unit Prices and Costs....................................................... 9
(g) Drilling Activity...................................................................... 10
(h) Marketing and Contracts................................................................ 10
(i) Customers.............................................................................. 11
(j) Competition............................................................................ 11
(k) Environmental Matters.................................................................. 11
(l) Employees.............................................................................. 12
(m) Offices................................................................................ 13
Item 3. Legal Proceedings................................................................................ 13
Item 4. Submission of Matters to a Vote of Security Holders.............................................. 13
Part II. Item 5. Market for Registrant's Common Equity and Related Stockholder Matters............................ 13
Item 6. Selected Financial Data.......................................................................... 14
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
(a) Introduction........................................................................... 15
(b) Overview............................................................................... 15
(c) Results of Operations.................................................................. 15
(d) Capital Resources and Liquidity........................................................ 18
(e) Net Operating Loss Carryforwards and Canadian Tax Pools................................ 20
(f) Foreign Currency Transactions.......................................................... 21
(g) Changes in Prices and Inflation........................................................ 21
(h) Forward-Looking Statements............................................................. 21
(i) Impact of Recently Issued Accounting Standards......................................... 21
Item 8. Financial Statements and Supplementary Data...................................................... 22
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure............. 53
Part III. Item 10. Directors and Executive Officers of the Registrant............................................... 53
Item 11. Executive Compensation........................................................................... 53
Item 12. Security Ownership of Certain Beneficial Owners and Management................................... 53
Item 13. Certain Relationships and Related Transactions................................................... 53
Part IV. Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.................................. 53
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
(A) GENERAL
United Meridian Corporation (UMC or the Company) is a leading independent
energy company engaged in the exploration, development, production and
acquisition of oil and natural gas in North America and certain international
regions. Since its inception in 1987, the Company has grown through a series of
strategic corporate and property acquisitions, and a successful exploration
program that has focused on UMC's core operating areas in North America and in
certain high potential international regions. In North America, the Company's
production is concentrated in the Gulf Coast, Permian Basin, Midcontinent and
Rocky Mountain regions and in Western Canada. Internationally, the Company
currently operates in the West African oil and natural gas producing regions of
Cote d'Ivoire and Equatorial Guinea. In addition, the Company has been awarded
production sharing contracts or petroleum concession agreements (PSC) on three
blocks in Pakistan and signed a PSC in Bangladesh in February 1997.
The Company was organized under the laws of Delaware in 1987. Between 1987
and 1989, the Company acquired three publicly held companies (Ensource Inc., MCO
Resources, Inc. and General Energy Development, Ltd.) and one privately held
company (General Drilling and Producing Company). During 1989, these companies
were consolidated into UMC Petroleum Corporation (Petroleum), the primary
operating subsidiary of the Company.
During 1993, UMC made three additional corporate acquisitions, Norfolk
Holdings Inc. (NHI), KPX, Inc. (KPX), and Sterling Energy Limited (SEL), all of
which were privately held oil and gas production companies. In 1994, UMC
acquired General Atlantic Resources, Inc. (GARI), a publicly traded company.
At December 31, 1996, the Company's proved reserves were estimated to be
119.7 MMBOE, 37% oil and 63% gas.
The Company's principal executive offices are located at 1201 Louisiana,
Suite 1400, Houston, TX 77002 and the Company's telephone number is (713) 654-
9110. Unless the context otherwise requires, the term "Company" or "UMC" as used
in this Form 10-K shall mean United Meridian Corporation and its subsidiaries.
Petroleum, with offices also located at the above address, is the Company's only
direct subsidiary. All operations are conducted by Petroleum and its
subsidiaries.
(B) BUSINESS STRATEGY
UMC's business strategy is to increase reserves and production in a cost-
effective manner through a drilling program that balances lower risk development
and exploratory drilling on UMC's North American acreage with high potential
international prospects, supplemented by opportunistic property and corporate
acquisitions. Supporting this strategy are: (i) a substantial portfolio of high
return exploration opportunities; (ii) a large exploitation inventory; and,
(iii) a successful history of acquisitions. The Company also anticipates that
the continued success of its international activities will continue to move the
overall mix of its proved reserves and production toward a more equal balance
between oil and natural gas.
North America. The Company is aggressively exploiting its North American
properties through the integration of advanced 3-D seismic technology,
horizontal drilling and geoscience studies. UMC conducts a North American
exploration program focused on internally-generated prospects, primarily in the
Gulf Coast region, including East Texas, and in the Permian and Williston
Basins, where the Company believes high success rates and excellent reserve
potential exist. The Company manages its domestic exploration risk by applying
state-of-the-art technology to identify prospects, emphasizing prospects over
which it will have operational control. The risks of these prospects are shared
with industry partners and a group of institutional investors on terms
considered favorable to the Company. The Company has generated a significant
number of development drilling opportunities as a result of its exploration
efforts and through producing property acquisitions. UMC has identified a large
exploitation inventory including 155 proved undeveloped drilling sites and 491
probable and possible drilling sites. During 1996, the Company participated in
drilling 114 development wells, 105 of which were successfully completed, and
37 exploratory wells, 18 of which were successfully completed. Total capital
expenditures for North American activities in 1996 were $83.8 million.
-1-
Capital expenditures in North America in 1997 are expected to be approximately
$105.0 million.
International. The Company's business strategy in the international arena is
to pursue selected opportunities characterized by low initial costs, high
reserve potential and the availability of existing technical data that may be
further developed using current technology. The Company believes that it has
unique management and technical expertise in identifying international
opportunities and establishing favorable operating relationships with host
governments. The Company attempts to manage major exploration commitments by
negotiating directly with host governments for terms which minimize bonuses and
initial work commitments. Additionally, the Company forms joint ventures under
which partners provide a significant amount of the initial exploration costs.
This strategy permits the Company to limit its capital exposure until commercial
development is assured. The Company has identified a large number of
exploration prospects on its Equatorial Guinea and Cote d'Ivoire acreage and has
two development programs in progress. Total capital expenditures for
international activities in 1996 were $106.6 million, and in 1997 are expected
to be approximately $145.0 million.
Acquisitions and asset management. The Company is continually evaluating
opportunities to acquire oil and natural gas properties, primarily focusing on
properties that complement its existing reserve base. This focus allows the
Company to apply its engineering knowledge and expertise to maximize future
development potential and minimize reserve risk. The acquisitions must meet
well-defined return, payout and cash flow criteria. In addition, as part of its
business strategy, the Company periodically evaluates and, from time to time,
sells certain of its producing properties. Such sales enable the Company to
maintain financial flexibility, reduce overhead and operating expenses and
redeploy capital to activities which are expected to have higher financial
returns. Consistent with this strategy, the Company realized $50.2 million in
proceeds from sales of properties in 1996. The realized proceeds consisted of
(i) $18.1 million in cash received in 1996 related to the purchase of an
additional 10% interest in Block B in Equatorial Guinea by Mobil Equatorial
Guinea, Inc. (Mobil), (ii) $28.8 million received from the sales of various non-
strategic North American properties, and (iii) $3.3 million received from Shell
Exploration Africa B.V. (Shell), a unit of the Royal Dutch/Shell group, for a
55% contract interest in Block CI-105 in Cote d'Ivoire.
Low cost operating structure. Management strives to maintain a low cost
operating structure through the implementation of the aforementioned strategies
and by employing an experienced and stable workforce. Controllable cash costs
which are continuously monitored by management include production costs and
general and administrative expenses. During 1996, UMC's lifting costs, before
ad valorem and production taxes, and general and administrative costs averaged
$3.12 and $0.93 per BOE of production, respectively, down from $3.50 and $1.03
per BOE of production, respectively, for 1995. Further per unit cost
improvement is anticipated for 1997 as production volumes increase and cost
containment efforts continue.
Sound financial structure. As part of its business strategy, the Company
maintains a sound financial structure which allows it to effectively implement
its operating strategy. With the 1997 expansion of the Company's credit
facility and the 1996 equity offering, combined with cash flows from operations,
the Company has the financial strength, leverage and liquidity that will allow
it to fund the 1997 capital expenditures program, including the international
exploration and development opportunities in Cote d'Ivoire and Equatorial
Guinea, and continue to selectively pursue strategic corporate and property
acquisitions.
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(c) OIL AND GAS PROPERTIES
The table below summarizes the Company's proved reserves and discounted
present value by geographic region as of December 31, 1996.
PROVED RESERVES
--------------------------------------------------------
DPV/(1)/
NATURAL BEFORE % OF
OIL GAS TOTAL INCOME TAX TOTAL
REGION (MBO) (MMCF) (MMBOE) ($ IN 000'S) DPV
- --------------------------------- ----- ------ ------- ------------ ---
Gulf of Mexico/Gulf Coast Onshore....... 2,139 68,785 13.6 $168,100 17.4%
Permian Basin/Midcontinent.............. 8,532 92,011 23.9 214,306 22.2%
Rocky Mountains......................... 6,270 136,736 29.1 256,440 26.5%
Canada.................................. 3,499 62,781 14.0 80,358 8.3%
Cote d'Ivoire........................... 4,150 90,410 19.2 114,769 11.9%
Equatorial Guinea....................... 19,940 - 19.9 132,890 13.7%
------ ------- ----- -------- ------
Total............................. 44,530 450,723 119.7 $966,863 100.0%
====== ======= ===== ======== ======
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/(1)/ Discounted (at 10%) present value as of December 31, 1996 (year-end prices
held constant). The amounts are before income taxes and therefore are not
the same as the "Standardized Measure" disclosed in Note 18 of the Notes to
Consolidated Financial Statements.
NORTH AMERICA
The Company conducts a focused exploration program designed to find
significant reserves at low costs. The Company's North American efforts are
predominantly in the Gulf of Mexico, East Texas and the Permian and Williston
Basins. The Company's North American exploration program generally involves
either (i) exploratory drilling beneath producing fields where potentially
significant reserves are undeveloped on proven structures, or (ii) drilling on
the Company's 1,680,000 gross (552,000 net to UMC) undeveloped acres, much of
which is adjacent to proven producing acreage. Typically, the Company seeks to
operate these projects and to retain a 25-60% working interest. In 1996, the
Company committed 19.1% of its capital expenditures to North American
exploration and drilled a total of 37 exploratory wells, of which 18 were
completed as productive. The Company has successfully used 3-D seismic
technology as an effective exploration tool in locating hydrocarbon indicators
or "bright spots." This data is used to further delineate specific prospect
leads and to aid in development of exploratory discoveries.
UMC focuses its development activities in those areas which offer the most
attractive potential returns to the Company, including development opportunities
resulting from exploration activities. During 1996, UMC committed 24.8% of its
capital expenditures to North American development and participated in the
drilling of 114 development wells, 105 of which were completed as productive
wells. The Company's working interest in these productive wells averaged
approximately 25%. The Company has identified approximately 155 proved
undeveloped and 491 probable and possible drilling opportunities within its
existing North American inventory. UMC has prioritized development projects
which will maximize the production potential per dollar of investment in view of
the large number of opportunities available to the Company.
-3-
The following paragraphs highlight certain of the Company's more significant
North American properties:
Bearpaw Area, Montana. The Bearpaw area, located in Blaine, Hill and
Chouteau Counties, comprises most of the Company's reserves in Montana. Natural
gas is produced from the Eagle Sandstone at depths of less than 2,000 feet. The
Company has an average 72% working interest in the area, which is an increase of
11% due to two recent acquisitions. The Company's net production averaged
approximately 30 MMCFD of natural gas for December 1996. The Company also
acquired an additional 5% interest in November 1996 in the Havre Pipeline
Company LLC (Havre Pipeline), the gathering and compression system that serves
the Bearpaw area. Havre Pipeline completed a 6,800 HP compression upgrade in
July 1996 that increased throughput by 5.5 MMCFD during the last half of 1996.
This upgrade will allow higher throughput on the Havre Pipeline transmission
system, as well as allowing the Company to realize higher ultimate recovery of
natural gas reserves due to reduced gathering pressures.
High Island A-560, Offshore, Gulf of Mexico. The High Island A-560 lease, in
which the Company owns a 55% working interest, was purchased in the August 1993
Outer Continental Shelf (OCS) lease sale. The discovery well was drilled in
early 1994 followed by a confirmation development well. The platform was
installed in mid-1995 and the first two wells were completed as dual and single
gas wells. First production was in July 1995. One additional producing well
was drilled and completed during December 1995. The platform is currently
producing at a rate of 1.3 MBOD (0.6 MBOD net to the Company) and 8.5 MMCFD (3.8
MMCFD net to the Company).
Eugene Island 301/302, Offshore, Gulf of Mexico. The Eugene Island 301/302
lease, in which the Company owns a 55% working interest, was purchased in the
March 1994 OCS lease sale. The discovery well was drilled in March 1995, with
three additional wells drilled and completed. Production from the four wells
commenced in the first quarter of 1996. Compression was installed in December
1996. The current producing rate is 16.8 MMCFD (7.5 MMCFD net to the Company).
West Cameron 541, Offshore, Gulf of Mexico. The West Cameron 541 lease, in
which the Company owns a 55% working interest, was purchased in the March 1994
OCS lease sale. The discovery well was drilled in July 1995 followed by a
confirmation development well. The platform was installed in June 1996 and two
additional wells were drilled and completed off of this structure. First
production was in September 1996. The current production rate is 24.2 MMCFD
(10.8 MMCFD net to the Company).
High Island 98-L - Offshore, Texas. The High Island 98-L Texas state lease,
in which the Company owns a 55% working interest, was purchased in October 1995
at the Texas state lease sale. The discovery well was drilled and completed in
July 1996. The production platform was installed in November 1996 and first
production was in December 1996. The current production rate is 10.0 MMCFD (4.3
MMCFD net to the Company) and 150 BOD (65 BOD net to the Company).
Young Mendota Field, Texas. The Young Mendota field is the Company's largest
field in the Midcontinent region and is located in Hemphill County. Natural gas
is produced from several formations including the Granite Wash, Morrow and
Douglas formations at depths ranging from 7,000 to 11,500 feet. The Company
operates 45 of the 90 wells in which it has interests in this field. Production
attributable to the Company's net interest averaged 5.9 MMCFD of natural gas for
1996.
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INTERNATIONAL
The Company's business strategy in the international arena is to pursue
selected international opportunities characterized by low initial costs, high
reserve potential and the availability of technical data that may be further
developed by the Company. The Company attempts to manage major exploration
commitments by negotiating directly with host governments for terms which
minimize bonuses and initial work commitments. Additionally, the Company forms
joint ventures where industry partners provide a carry for a significant portion
of the initial exploration costs. This strategy permits the Company to limit
its capital exposure until commercial development is assured.
UMC continually reassesses its position during the course of larger
international exploration and development projects, and may periodically
consider selling interests in one or more projects. The sale of a part of its
interests in a project may be used to balance perceived technical or political
risks and funding commitments. As part of this on-going strategy employed by
the Company to manage international capital risk, in September 1996, the Company
executed an agreement with Shell to sell a 55% contract interest in Block CI-105
in Cote d'Ivoire. The sale resulted in a pre-tax gain of $3.3 million on cash
proceeds of $3.3 million. UMC received an additional $0.9 million for
reimbursement of exploration expense previously incurred by the Company. During
the fourth quarter of 1995 the Company agreed to assign to Yukong Limited a
portion of UMC's interests in Blocks CI-01 and CI-02 in Cote d'Ivoire and Blocks
B, C and D in Equatorial Guinea. Mobil subsequently exercised its preferential
right to purchase the offered interest in Block B in Equatorial Guinea in lieu
of the Company's assignment of such interest to Yukong Limited. Under the
agreements the Company received $40.1 million in cash for a 15% interest in each
of Block CI-01 and CI-02 in Cote d'Ivoire, a 10% interest in Block B and a 25%
interest in each of Blocks C and D in Equatorial Guinea. The Company recognized
pre-tax gains of $15.8 million and $18.3 million for cash received in 1996 and
1995, respectively.
Cote d'Ivoire. During 1991, UMC initiated negotiations with the Republic of
Cote d'Ivoire for a PSC covering Block CI-11, most of which is located offshore
in the Atlantic Ocean. Since acquiring the initial PSC in 1992, the Company has
negotiated four additional PSCs. Under the five PSCs, UMC holds contract
interests ranging from 25% to 75% in five blocks totaling approximately 2.3
million gross acres.
On Block CI-11, the Company, as operator, has drilled 12 oil and natural gas
wells in the Lion oil and Panthere natural gas fields since late 1993. As a
result of the successful discoveries and subsequent production history, UMC has
proved reserves of 2.9 MMBO of oil and 41.0 BCF of natural gas on Block CI-11 at
December 31, 1996. In addition to its continuing development activities on
Block CI-11, UMC has identified several exploration opportunities on the Block.
A 3-D seismic survey is currently being evaluated which will further delineate
the Company's opportunities in that area. In 1996, the Company drilled two
exploratory wells on CI-11, one of which was successful. In addition, two
development wells were successfully completed.
Initial oil production from the Lion oil field commenced at the rate of up to
10,000 BOD (1,500 BOD net to UMC) in late April 1995 and increased to 16,000 BOD
(2,400 BOD net to the Company) at December 31, 1996. Natural gas production
commenced in October 1995 under a take-or-pay contract under which the
government is currently taking 50 MMBTUD (7.5 MMBTUD net to the Company), and
further increases in market demand are expected. The natural gas price is
approximately $1.70 per MCF. Although UMC's contract interest in this Block is
25%, UMC's current percentage of production (inclusive of cost recovery and
after government allocation) is approximately 15%.
On Block CI-12, which is immediately west of Block CI-11, UMC has identified
several seismic anomalies which it believes are on trend with the Lion oil
sands. In late 1996, the Company began drilling the initial exploratory well on
the Block (Leopard #1) and in February 1997, this well was plugged and
abandoned. The Company plans to drill an additional two exploratory wells in
1997. UMC owns a 37.5% contract interest in Block CI-12. However, the
Company's ultimate contract interest in Block CI-12 is subject to final election
by Petroci, the national petroleum company of Cote d'Ivoire.
In 1996, UMC conducted a 3-D seismic survey covering 1,100 square kilometers
on Block CI-105 which is located due south of Block CI-12 and with water depths
ranging from 1,500 feet to 6,000 feet. As part of the previously discussed
agreement, Shell paid 100% of the first $3.0 million incurred for the survey.
In 1997, the survey will be processed and interpreted with a well location, if
any, to be selected late in the year. UMC will be
-5-
carried for up to $3.5 million (net) of the initial drilling commitment if Shell
elects to proceed to the drilling phase.
Blocks CI-01 and CI-02, located approximately 80 miles east of Block CI-11,
possess proven accumulations of oil and natural gas in reservoirs drilled by
major oil companies in the 1980s. The Company recognized net proved reserves of
1.3 MMBO of oil and 49.4 BCF of natural gas at December 31, 1996. Mapping of
existing 3-D seismic on Block CI-01 and a new 3-D seismic survey on CI-02 will
further evaluate the reserve potential of these Blocks. The Ibex #1 was drilled
on CI-01, but did not find oil or gas. In 1997, the Company drilled a discovery
at Kudu, CI-01, that encountered 75 feet of net pay and flowed 27.7 MMCF of gas
and 740 barrels of condensate per day. UMC owns a 45% contract interest in
Block CI-01 and currently holds 75% in Block CI-02. However, the Company's
ultimate contract interest in Block CI-02 is subject to final election by
Petroci, the national petroleum company of Cote d'Ivoire.
UMC has been in discussions with the government of Ghana for the sale of
natural gas production from Block CI-01. Ghana is currently buying electricity
from Cote d'Ivoire. The governments of Ghana and Cote d'Ivoire have tentatively
approved the sale of natural gas from Block CI-01 to Ghana for power generation.
The plan, if concluded, would call for UMC to develop Block CI-01 and export a
portion of the natural gas to a power plant to be built on the coast of Ghana.
Alternatively, natural gas production could be sold in the Abidjan market.
Equatorial Guinea. UMC has negotiated four PSCs with the Republic of
Equatorial Guinea for blocks located offshore in the Atlantic Ocean. Under the
PSCs, UMC holds approximately 1.8 million gross acres.
Block B was also evaluated by a 1993 seismic program, in which UMC had a
carried interest. Mobil then carried UMC in the drilling of a test well on the
Delta prospect which was a dry hole in late 1994. Mobil, as operator, and UMC
then drilled three successful oil wells on the Zafiro prospect and one
successful oil well on the Opalo prospect in 1995. In 1996, a total of thirteen
wells were drilled, six development and seven exploratory wells. The
development wells were all successful and were tested at rates of 4,000 to
10,500 BOD (1,000 to 2,625 BOD net to UMC). At December 31, 1996, four of the
development wells were producing and two were being completed. Four of the
seven exploratory wells were successful with two finding new pay zones. These
wells have not been tested pending tie-in to the facilities. Total expenditures
to date have been $418.0 million ($104.5 million net to UMC). The Company
recognized proved reserves of 19.9 MMBO (88.6 MMBO gross) on Block B at December
31, 1996. However, the Company's investment is based upon a significantly
higher anticipated level of reserve recovery. The Company owns a 25% contract
interest in Block B.
Initial oil production from Block B commenced in late August 1996 at a rate
of 10,000 BOD (2,300 BOD net to UMC) and has increased to 36,000 BOD (8,378 BOD
net to UMC) at December 31, 1996. Production is expected to increase at mid-year
1997 to approximately 70,000-75,000 BOD (15,750-16,875 BOD net to UMC).
Block D, in which the Company owns a 75% contract interest, is also adjacent
to Block B, which increases the prospectiveness of the Block. In late 1996, the
Company drilled the initial exploratory well on the Block (Perla #1) and in
January 1997, this well was plugged and abandoned and the drilling rig was moved
to the second location on the Block (Tsavorita #1). In January 1997, the
Company experienced a shallow dry gas kick on the Tsavorita #1. The well was
plugged and the rig moved. The Company is currently drilling the Tsavorita #1A,
and results are expected late in the first or early in the second quarter of
1997.
Block C is adjacent to Block B and potentially holds extensions of the
opportunities discovered in Block B. The discovery of high quality reservoirs
and high oil flow rates on Block B increases the likelihood of successful
exploration on this Block. UMC will continue to evaluate the exploration
potential of this Block following the success on Block B. The Company currently
owns a 75% contract interest and will continue to evaluate the seismic data in
1997. A well is not expected to be drilled on the Block before 1998.
Block A was evaluated during 1993 and 1994 with a 2-D seismic program and a
test well, the Dorado #1, a dry hole in which UMC had a carried interest. UMC
is evaluating further exploration opportunities on the Block. The Company
currently owns a 100% contract interest in Block A.
Pakistan. UMC signed a PSC with the government of Pakistan on January 14,
1996 covering Block No. 2462-1 (E/L) Pasni-Balochistan. The block covers 1.9
million acres and UMC currently holds a 76% contract interest in the
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block. The Company also acquired a 76% interest in the Pasni East and Gwadar
Blocks, adjacent to the Pasni-Bolochistan Block. These Blocks cover 1.4 and 1.1
million acres, respectively. UMC plans to conduct geological and geophysical
studies during the first two years of the exploration license on the three
Blocks, with possible drilling in 1998.
Bangladesh. UMC initialed a PSC covering Block 22, Chittagong Hills Tracts
in December 1995, with final signing in February 1997. UMC plans to conduct
geological and geophysical work during the first year of the PSC. The block
covers 13,390 square kilometers (3.3 million acres). UMC currently holds a 40%
contract interest.
(D) RESERVES
The Company holds interests in producing properties in 15 states, Canada,
Equatorial Guinea and Cote d'Ivoire, with most of its proved reserves located in
four major natural gas producing areas of the United States (Gulf of Mexico/Gulf
Coast Onshore, Permian Basin/Midcontinent, Rocky Mountains and Montana), in the
Alberta and Saskatchewan provinces of Canada and in Western Africa. At December
31, 1996, the Company had estimated proved reserves of 44.5 MMBO of oil and
450.7 BCF of natural gas, or 119.7 MMBOE.
The following table sets forth estimates of the proved oil and natural gas
reserves of the Company at December 31, 1996, as evaluated by Ryder Scott,
Netherland, Sewell & Associates, Inc. and McDaniel & Associates Consultants
Ltd., the Company's independent petroleum reserve engineers:
BARRELS OF OIL EQUIVALENTS
OIL (MBO) NATURAL GAS (MMCF) (MBOE)
----------------------------- ------------------------------ -------------------------------
DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL
--------- ----------- ----- --------- ----------- ----- --------- ----------- -----
Gulf Coast............... 2,090 49 2,139 52,473 16,312 68,785 10,836 2,768 13,604
Permian Basin/
Midcontinent............ 7,533 999 8,532 80,524 11,487 92,011 20,954 2,913 23,867
Rocky Mountains.......... 5,178 1,092 6,270 112,850 23,886 136,736 23,986 5,073 29,059
------ ------ ------ ------- ------- ------- ------ ------ -------
Sub-Total U.S.......... 14,801 2,140 16,941 245,847 51,685 297,532 55,776 10,754 66,530
Canada................... 3,499 - 3,499 62,781 - 62,781 13,963 - 13,963
Cote d'Ivoire............ 1,926 2,224 4,150 21,433 68,977 90,410 5,498 13,720 19,218
Equatorial Guinea........ 4,353 15,587 19,940 - - - 4,353 15,587 19,940
------ ------ ------ ------- ------- ------- ------ ------ -------
Total Company.......... 24,579 19,951 44,530 330,061 120,662 450,723 79,590 40,061 119,651
====== ====== ====== ======= ======= ======= ====== ====== =======
The Company has not filed any different estimates of its December 31, 1996
reserves with any federal agency.
The reserve data set forth in this Form 10-K represents only estimates.
Reserve engineering is a subjective process of estimating underground
accumulations of crude oil and natural gas that cannot be measured in an exact
manner. The accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and adjustment.
As a result, estimates of different engineers often vary. In addition, results
of drilling, testing and production subsequent to the date of an estimate may
justify revision of such estimates. Accordingly, reserve estimates often differ
from the quantities of crude oil and natural gas that are ultimately recovered.
Estimates of economically recoverable oil and natural gas reserves and of future
net revenues are based upon a number of variables and assumptions, all of which
may vary considerably from actual results. The reliability of such estimates is
highly dependent upon the accuracy of the assumptions upon which they were
based.
-7-
The following table sets forth, at December 31, 1996, the discounted present
value attributable to the Company's estimated proved reserves at that date as
estimated primarily by Ryder Scott, Netherland, Sewell & Associates, Inc. and
McDaniel & Associates Consultants Ltd., the Company's independent petroleum
reserve engineers:
IN THOUSANDS OF U.S. DOLLARS
-------------------------------------------------------------------
UNITED COTE EQUATORIAL
STATES CANADA d'IVOIRE GUINEA TOTAL
----------- ---------- ---------- ------------ ----------
Future cash inflows.................... $1,445,872 $206,041 $305,988 $ 450,785 $2,408,686
---------- -------- -------- --------- ----------
Future production costs................ 379,096 55,993 53,927 102,275 591,291
Future development costs............... 53,067 4,501 74,957 152,780 285,305
Future income taxes.................... 221,053 44,263 45,833 49,782 360,931
---------- -------- -------- --------- ----------
Total future costs..................... 653,216 104,757 174,717 304,837 1,237,527
---------- -------- -------- --------- ----------
Future net cash inflows................ 792,656 101,284 131,271 145,948 1,171,159
Discount at 10% per annum.............. (253,431) (42,431) (40,465) (40,810) (377,137)
---------- -------- -------- --------- ----------
Standardized measure of discounted
future net cash flows................. $ 539,225 $ 58,853 $ 90,806 $ 105,138 $ 794,022
========== ======== ======== ========= ==========
In computing this data, assumptions and estimates have been utilized, and no
assurance can be given that such assumptions and estimates will be indicative of
future economic conditions. The future net cash inflows are determined by using
estimated quantities of proved reserves and the periods in which they are
expected to be developed and produced based on December 31, 1996 economic
conditions. The estimated future production is priced at December 31, 1996,
except where fixed and determinable price escalations are provided by contract.
The resulting estimated future gross revenues are reduced by estimated future
costs to develop and produce the proved reserves based on December 31, 1996 cost
levels, but not for debt service and general and administrative expenses.
(E) ACREAGE AND PRODUCTIVE WELLS
The following table sets forth the Company's developed and undeveloped
acreage at December 31, 1996. In North America, the Company holds its acreage
through oil and gas leases. The leases have a variety of primary terms and may
require delay rentals to continue the primary term if not productive. The
leases may be surrendered by the operator at any time by notice to the lessors,
by the cessation of production, fulfillment of commitments, or by failure to
make timely payment of delay rentals.
The Company's acreage holdings in Cote d'Ivoire, Equatorial Guinea and
Pakistan are evidenced by PSCs with the governments of those countries. Among
the terms that may be in the PSCs are obligations of UMC to conduct exploration
operations (including the drilling of wells) and the manner in which any oil and
gas that may be produced will be allocated among the parties to the contract.
Refer to pages 5, 6, and 7 of this Form 10-K for further discussion of the PSCs.
DEVELOPED ACREAGE UNDEVELOPED ACREAGE TOTAL
----------------- ------------------- -------------
GROSS NET GROSS NET GROSS NET
--------- ------ --------- -------- ------ -----
(IN THOUSANDS) (IN THOUSANDS) (IN THOUSANDS)
----------------- ------------------- -------------
Gulf Coast Onshore... 72 18 310 52 382 70
Gulf Coast Offshore.. 148 37 174 114 322 151
Midcontinent......... 330 121 123 23 453 144
Rocky Mountains...... 321 142 613 191 934 333
Other U.S............ 44 8 66 9 110 17
----- --- ------ ----- ------ -----
Sub-Total U.S..... 915 326 1,286 389 2,201 715
Canada............... 439 72 394 163 833 235
Cote d'Ivoire........ 13 4 2,268 900 2,281 904
Equatorial Guinea.... 36 9 1,798 1,203 1,834 1,212
Pakistan............. - - 4,391 3,337 4,391 3,337
----- --- ------ ----- ------ -----
Total /(1)/....... 1,403 411 10,137 5,992 11,540 6,403
===== === ====== ===== ====== =====
/(1)/ Does not include 3.3 million gross acres (1.3 million net acres) in
Bangladesh where the Company signed a PSC in February 1997.
-8-
At December 31, 1996, the Company had 6,649 gross productive wells (1,143
net), of which 4,594 gross wells (439 net) were oil and 2,055 gross wells (704
net) were natural gas. Productive wells consist of producing wells and wells
capable of production. Wells that are completed in more than one producing
horizon are counted as one well. Of the gross wells reported above, 13 had
multiple completions.
(F) PRODUCTION, UNIT PRICES AND COSTS
The following table sets forth information with respect to the Company's
production and average unit prices and costs for the periods indicated:
YEARS ENDED
DECEMBER 31,
-------------------------------------
1996 1995 1994
--------- -------- --------
Production:
Oil (MBO)
United States............................................. 2,022 1,826 1,160
Canada.................................................... 511 649 618
Cote d'Ivoire............................................. 894 285 -
Equatorial Guinea......................................... 967 - -
------ ------ ------
Total................................................... 4,394 2,760 1,778
Natural gas (MMCF)
United States............................................. 47,719 38,878 35,182
Canada.................................................... 5,339 5,383 4,487
Cote d'Ivoire............................................. 2,387 192 -
------ ------ ------
Total................................................... 55,445 44,453 39,669
Average net sales price, including hedging:
Oil ($ per bbl)
United States............................................. $20.91 $16.41 $14.93
Canada.................................................... $19.43 $16.59 $15.14
Cote d'Ivoire............................................. $20.56 $15.45 $ -
Equatorial Guinea......................................... $22.17 $ - $ -
Average................................................. $20.94 $16.35 $15.00
Natural gas ($ per MCF)
United States............................................. $ 2.15 $ 1.58 $ 1.73
Canada.................................................... $ 1.44 $ 1.17 $ 1.58
Cote d'Ivoire............................................. $ 1.80 $ 1.72 $ -
Average................................................. $ 2.07 $ 1.53 $ 1.71
Additional disclosures ($ per BOE):
Production and operating costs/(1)/......................... $ 3.12 $ 3.50 $ 3.49
Ad valorem and production taxes............................. $ 0.64 $ 0.72 $ 0.91
Oil and natural gas depletion and depreciation/(2)/......... $ 6.00 $ 5.19 $ 5.93
- --------------
/(1)/ Costs incurred to operate and maintain wells and related equipment,
excluding ad valorem and production taxes.
/(2)/ Does not include impairments of proved oil and gas property.
-9-
(G) DRILLING ACTIVITY
During the periods indicated, the Company drilled or participated in the
drilling of the following exploratory and development wells:
YEARS ENDED DECEMBER 31,
-------------------------------------
1996 1995 1994
---------- ----------- -----------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ----
Exploratory:
Productive..................... 23 7.8 18 5.2 13 5.5
Non-Productive................. 25 8.6 15 3.2 17 7.5
--- ---- --- ---- --- ----
Total........................ 48 16.4 33 8.4 30 13.0
=== ==== === ==== === ====
Development:
Productive..................... 113 26.8 114 19.4 108 52.5
Non-Productive................. 9 4.4 22 3.3 20 13.4
--- ---- --- ---- --- ----
Total........................ 122 31.2 136 22.7 128 65.9
=== ==== === ==== === ====
Total:
Productive..................... 136 34.6 132 24.6 121 58.0
Non-Productive................. 34 13.0 37 6.5 37 20.9
--- ---- --- ---- --- ----
Total........................ 170 47.6 169 31.1 158 78.9
=== ==== === ==== === ====
At December 31, 1996, the Company was participating in the drilling or
completion of 45 gross (8.6) net wells. All of the Company's drilling
activities are conducted with independent contractors.
(H) MARKETING AND CONTRACTS
A substantial portion of the Company's current natural gas production is sold
on the spot market or under market sensitive agreements with a variety of
purchasers, including intrastate and interstate pipelines, their marketing
affiliates, independent marketing companies and other purchasers who have the
ability to move the gas under firm transportation or interruptible agreements.
The Company has a few long term contractual arrangements which are market
sensitive.
During 1995, the Company entered into a five-year contract with a Michigan
buyer to sell up to 35 MMCFD during the period April through October of each
year, beginning in 1996. The Company's existing 35 MMCFD of firm transport
capacity on TransCanada Pipeline and Great Lakes Transmission is used to
transport these volumes. During 1996, the Company applied for an additional 8
MMCFD of ten-year term firm transport capacity on TransCanada Pipeline beginning
in November 1997. The supply for this contract will mainly come from the
Bearpaw Field in Montana, where the net company production was approximately 30
MMCFD for the month of December 1996, or from third party gas purchases. The
price received under this contract will be based on negotiated natural gas
contract pricing on the New York Mercantile Exchange plus a premium and/or index
related pricing. The Company incurs transportation charges to deliver gas to
the Midwest markets.
The Company's natural gas production is subject to regional discounts or
premiums to the benchmark Gulf Coast spot market price for natural gas. In West
Texas, the Rocky Mountains and the Midcontinent, the Company's natural gas
production has recently been sold at the prevailing regional price, with the
Rocky Mountain price benefiting from the aforementioned marketing agreement.
Deregulation in Canada has facilitated access to alternative markets for oil
and natural gas, such as direct sales to end-users and export sales to United
States markets. Generally, one-year renewable contracts in which price is
negotiated annually have been used to access these markets. Firm transportation
and gas processing capacity from major aggregators have been obtained in Canada
to provide continued ability to produce under these contracts.
Approximately 85% of the Company's Canadian gas is currently sold under
market sensitive contracts redetermined annually. The remaining 15% is sold on
the spot market.
In September 1994, UMC executed a contract under which UMC and its partners
will sell natural gas production from Block CI-11 to the Government of Cote
d'Ivoire. Under the terms of the agreement, the Government will take-or-pay for
50 MMBTUD. UMC and its partners will receive approximately $1.70 per MCF for
the first four years, after which time the price will be adjusted based on a
fixed discount to the West Texas Intermediate crude oil price. The
-10-
government is paying UMC for the natural gas with a portion of its oil
production. Additional sales contracts for natural gas from this and other Cote
d'Ivoire blocks are currently being negotiated.
(I) CUSTOMERS
The Company markets its oil and gas production to numerous purchasers under a
combination of short and long-term contracts. During 1996, 1995 and 1994,
Northern Natural Gas Company, a subsidiary of Enron Corporation, accounted for
0.9%, 9.0% and 10.7%, respectively, of oil and gas revenues of the Company. In
addition, during 1996, Mobil Sales and Supply Corporation and H&N Gas Limited,
Inc. accounted for 10.4% and 15.5%, respectively, of the Company's oil and gas
revenues. Sales to H&N Gas Limited, Inc. are backed by an irrevocable standby
letter of credit. The Company had no other purchasers that accounted for
greater than 10.0% of its oil and gas revenues. The Company believes that the
loss of any single customer would not have a material adverse effect on the
results of operations of the Company.
(J) COMPETITION
The exploration for and production of oil and natural gas is highly
competitive. In seeking to obtain desirable producing properties, new leases and
exploration prospects, the Company faces competition from both major and
independent oil and natural gas companies, as well as from numerous individuals
and drilling programs. Extensive competition also exists in the market for
natural gas produced by the Company. Many of these competitors have financial
and other resources substantially in excess of those available to the Company
and, accordingly, may be better positioned to acquire and exploit prospects,
hire personnel and market production. In addition, many of the Company's larger
competitors may be better able to respond to factors such as changes in
worldwide oil and natural gas prices and levels of production, the cost and
availability of alternative fuels and the application of government regulations,
which affect demand for the Company's oil and natural gas production and which
are beyond the control of the Company.
Natural gas prices, which were once effectively determined by government
regulations, are now influenced largely by the effects of competition.
Competitors in this market include other producers, gas pipelines and their
affiliated marketing companies, independent marketers and providers of alternate
energy supplies, such as residual fuel oil.
(K) ENVIRONMENTAL MATTERS
United States Environmental Regulations. Operations of the Company are
subject to numerous laws and regulations governing the discharge of materials
into the environment or otherwise relating to environmental protection. These
laws and regulations may require the acquisition of a permit before drilling
commences, restrict the types, quantities and concentration of various
substances that can be released into the environment in connection with drilling
and production activities, limit or prohibit drilling activities on certain
lands lying within wilderness, wetlands and other protected areas, and impose
substantial liabilities for pollution resulting from the Company's operations.
Moreover, the recent trend toward stricter standards in environmental
legislation and regulation is likely to continue. For instance, legislation has
been proposed in Congress from time to time that would reclassify certain oil
and gas production wastes as "hazardous wastes" which would make the
reclassified exploration and production wastes subject to much more stringent
handling, disposal and clean-up requirements. If such legislation were to be
enacted, it could have a significant impact on the operating costs of the
Company, as well as the oil and gas industry in general. State initiatives to
further regulate the disposal of oil and gas wastes are also pending in certain
states, and these various initiatives could have a similar impact on the
Company. Management believes that the Company is in substantial compliance with
current applicable environmental laws and regulations and that continued
compliance with existing requirements will not have a material adverse impact on
the Company.
The U.S. Environmental Protection Agency has indicated that the Company may
be potentially responsible for costs and liabilities associated with alleged
releases of hazardous substances at two sites in Louisiana under the
Comprehensive Environmental Response, Compensation and Liability Act. Given the
extremely large number of companies that have been identified as potentially
responsible for releases of hazardous substances at the sites and the small
volume of hazardous substances allegedly disposed of by the companies whose
properties the Company acquired, management believes that the Company's
potential liability arising from these sites, if any, will not have a material
adverse impact on the Company.
-11-
During the three year period ended December 31, 1996, neither UMC, nor any of
its subsidiaries, have been cited by any governmental authority with respect to
environmental matters. The Company has spent less than $100,000 per year during
the years 1996, 1995 and 1994 for the routine clean-up of oil, salt water or
other substances in the ordinary course of business. The Company has no
significant commitments for capital expenditures to comply with existing
environmental requirements.
The Oil Pollution Act of 1990 (OPA) and regulations thereunder impose a
variety of regulations on "responsible parties" related to the prevention of oil
spills and liability for damages resulting from such spills in United States
waters. A "responsible party" includes the owner or operator of a facility or
vessel, or the lessee or permittee of the area in which an offshore facility is
located. The OPA assigns liability to each responsible party for oil removal
costs and a variety of public and private damages. While liability limits apply
in some circumstances, a party cannot take advantage of liability limits if the
spill was caused by gross negligence or willful misconduct or resulted from
violation of a federal safety, construction or operating regulation. If the
party fails to report a spill or to cooperate fully in the cleanup, liability
limits likewise do not apply. Few defenses exist to the liability imposed by
the OPA.
The OPA also imposes ongoing requirements on a responsible party, including
proof of financial responsibility, to cover at least some costs in a potential
spill. On August 25, 1993, an advance notice of intention to adopt a rule under
the OPA was published that would require owners and operators of offshore oil
and gas facilities to establish $150 million in financial responsibility. Under
the proposed rule, financial responsibility could be established through
insurance, guarantee, indemnity, surety bond, letter of credit, qualification as
a self-insurer or a combination thereof. There is substantial uncertainty as to
whether insurance companies or underwriters will be willing to provide coverage
under the OPA because the statute provides for direct lawsuits against insurers
who provide financial responsibility coverage, and most insurers have strongly
protested this requirement. On October 19, 1996, Congress adopted an amendment
to OPA that lowered the financial requirement for certain offshore facilities to
$35 million. That amendment, however, also authorizes the U.S. Department of
the Interior to adopt rules increasing that requirement in circumstances that
the agency deems appropriate. The Company cannot predict the final form of the
financial responsibility rule that might be adopted. However, the impact of any
such rule should not be any more adverse to the Company than it will be to other
similarly situated or less capitalized owners or operators.
Canadian Environmental Regulations. The oil and natural gas industry is
subject to environmental regulation pursuant to local, provincial and federal
legislation in Canada. Environmental legislation provides for restrictions and
prohibitions on releases or emissions of various substances produced in
association with certain oil and gas industry operations. In addition,
legislation requires that well and facility sites be abandoned and reclaimed to
the satisfaction of provincial authorities. A breach of such legislation may
result in the imposition of fines and penalties. Environmental legislation in
Alberta was substantially revised in 1993 to update and consolidate the various
acts applicable to environmental protection. The various acts were consolidated
into the Environmental Protection and Enhancement Act, proclaimed April 22, 1993
and became effective September 1, 1993. Under the new Act, environmental
standards and compliance for releases, clean-up and reporting are stricter.
Also, the range of enforcement actions available and severity of penalties are
significantly increased. The changes had an incremental but not material effect
on the cost of conducting operations in Alberta. The full extent of the impact
will not be known until the Government of Alberta releases its enforcement
policy. Federal environmental regulations are generally restricted to the use
and transport of certain restricted and prohibited substances and the
environmental assessment of projects which require an approval from a federal
authority. The Company anticipates making necessary expenditures of both a
capital and expense nature as a result of the increasingly stringent laws
relating to the protection of the environment. The Company believes that it is
in material compliance with applicable environmental laws and regulations in
Canada.
(L) EMPLOYEES
At January 31, 1997, the Company employed approximately 310 people in its
Houston, Texas; Denver, Colorado; Calgary, Alberta; Abidjan, Cote d'Ivoire; and
Malabo, Equatorial Guinea offices and various field locations whose functions
are associated with management, engineering, geology, geophysics, operations,
land, legal, accounting, financial planning and administration. Of this amount,
approximately 47 full-time employees are responsible for the supervision and
operation of its field activities. The Company, which has no collective
bargaining arrangement with employees, believes its relations with its employees
are satisfactory.
-12-
(M) OFFICES
The Company leases its Houston headquarters under a lease covering
approximately 83,000 square feet, expiring in December 2006. The monthly rent
expense recognized under generally accepted accounting principles is
approximately $87,000. The Company also leases additional space for two division
and seven field operating offices.
ITEM 3. LEGAL PROCEEDINGS
The Company is a named defendant in lawsuits and is a party in governmental
proceedings from time to time arising in the ordinary course of business. While
the outcome of such lawsuits or other proceedings against the Company cannot be
predicted with certainty, management does not expect these matters to have a
material adverse effect on the financial condition or results of operations of
the Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None during the fourth quarter of 1996.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Since July 22, 1993, the Company's Series A Voting Common Stock, $0.01 par
value (the "Common Stock"), has been traded on the New York Stock Exchange under
the symbol "UMC". As of February 28, 1997, there were 35,248,805 shares of
Common Stock outstanding held by approximately 186 stockholders of record. The
Company has never paid dividends on its Common Stock and does not expect to pay
dividends in the near future.
The following table shows the high and low sales prices of the Common Stock
on the New York Stock Exchange for the last two years:
QUARTER ENDED, 1995 HIGH LOW
------------------- ------- -------
March 31................... $14.25 $10.25
June 30.................... $16.13 $13.38
September 30............... $18.75 $15.13
December 31................ $18.13 $16.13
QUARTER ENDED, 1996
-------------------
March 31................... $25.88 $15.00
June 30.................... $36.25 $23.13
September 30............... $48.38 $32.13
December 31................ $53.50 $43.88
The Company's Credit Facility and the 10-3/8% Senior Subordinated Notes (see
Note 5 of the Notes to Consolidated Financial Statements) contain certain
restrictions on the Company's ability to declare and pay dividends. The payment
of future cash dividends, if any, will be reviewed periodically by the Board of
Directors and will depend upon, among other things, the Company's financial
condition, funds from operations, the level of its capital and exploration
expenditures, its future business prospects and any restrictions imposed by the
Company's present or future credit facilities.
-13-
ITEM 6. SELECTED FINANCIAL DATA
The financial data as of and for the years ended December 31, 1992 through
1996 were derived from the audited consolidated financial statements of the
Company and should be read in connection with the consolidated financial
statements and related notes included elsewhere herein (amounts in thousands,
except per share data).
YEARS ENDED DECEMBER 31,
-----------------------------------------------------
1996 1995 1994 1993 1992
--------- -------- -------- -------- --------
Operating revenues:
Gas sales............................................................. $114,498 $ 68,228 $ 67,763 $ 60,457 $ 43,019
Oil sales............................................................. 92,031 45,122 26,675 19,877 17,257
Gain on sale of assets and other /(1)/................................ 29,875 33,691 3,379 1,984 5,793
-------- -------- --------- -------- --------
236,404 147,041 97,817 82,318 66,069
Costs and expenses:
Production costs...................................................... 51,298 42,891 36,938 30,539 21,233
General and administrative............................................ 12,727 10,425 12,504 8,097 7,213
Exploration, including dry holes...................................... 40,325 15,682 16,187 6,811 5,769
Depreciation, depletion and amortization.............................. 84,979 53,942 50,727 35,938 25,155
Impairment of proved oil and gas properties /(2)/..................... - 8,317 94,793 10,051 -
Interest expense...................................................... 22,811 17,945 9,040 6,532 6,434
Interest and other income (expense)................................... 844 (375) 141 (2,102) (71)
-------- -------- --------- -------- --------
212,984 148,827 220,330 95,866 65,733
Income (loss) before taxes and cumulative effect of changes
in accounting principles.............................................. 23,420 (1,786) (122,513) (13,548) 336
Income tax benefit (provision):
Current............................................................... (785) (332) (25) (1,131) (297)
Deferred.............................................................. (5,231) 4,217 41,549 7,436 1,954
-------- -------- --------- -------- --------
Income (loss) before cumulative effect of changes in
accounting principles................................................. 17,404 2,099 (80,989) (7,243) 1,993
Cumulative effect of change in accounting principle, net of tax /(2)/.. - - - (3,543) (368)
-------- -------- --------- -------- --------
Net income (loss)...................................................... $ 17,404 $ 2,099 $ (80,989) $(10,786) $ 1,625
======== ======== ========= ======== ========
Net income (loss) applicable to common stockholders /(3)/.............. $ 15,873 $ 615 $ (80,989) $(12,284) $ 843
Earnings per share of common stock:
Income (loss) before cumulative effect of changes
in accounting principles............................................ $ 0.51 $ 0.02 $ (3.47) $ (0.75) $ 0.09
Cumulative effect of changes in accounting principles................. - - - (0.31) (0.03)
-------- -------- --------- -------- --------
Net income (loss) per common share /(3)/.............................. $ 0.51 $ 0.02 $ (3.47) $ (1.06) $ 0.06
======== ======== ========= ======== ========
Weighted average number of common shares
and common share equivalents outstanding /(3)/........................ 31,428 29,259 23,330 11,588 13,143
Balance Sheet Data (at end of period):
Property, plant and equipment - net /(1)/............................. $524,189 $468,673 $ 424,930 $291,723 $167,885
Total assets.......................................................... 718,293 578,450 511,214 343,223 197,207
Long-term debt, including current maturities.......................... 157,731 247,899 239,634 92,149 67,990
Stockholders' equity /(4)/............................................ 432,236 212,312 171,438 189,672 90,985
- --------------
/(1)/ See Note 4 of the Notes to Consolidated Financial Statements for a
discussion of significant acquisitions and dispositions for the applicable
periods.
/(2)/ See Note 3 of the Notes to Consolidated Financial Statements regarding the
Company's policy for assessing the recoverability of proved oil and gas
properties. In 1992, the Company adopted Statement of Financial Accounting
Standards 109, Accounting for Income Taxes. In 1993, the Company adopted a
policy to assess recoverability of its proved properties by individual
property groups having similar geological or operating characteristics
utilizing estimates of undiscounted future net revenues attributable to
proved reserves based on current prices and to provide impairment reserves
as conditions warrant.
/(3)/ See Exhibit 11.1 for the calculation of net income (loss) per common share
and for the calculation of the weighted average number of common shares
and common share equivalents outstanding.
/(4)/ The Company has never paid dividends on its common stock.
-14-
The following is a condensed summary of the results of operations for the
quarters of 1996 and 1995 (in thousands, except per share amounts):
QUARTERS ENDED (UNAUDITED)
-----------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- -------- ------------- ------------
1996
- ----
Revenues....................... $52,168 $61,323 $54,068 $68,845
Income from operations......... 11,745 14,400 10,927 10,003
Net income..................... 3,716 5,235 2,838 5,615
Net income per share/ (1)/..... 0.10 0.15 0.09 0.16
1995
- ----
Revenues....................... $40,436 $28,338 $29,069 $49,198
Income (loss) from operations.. 11,005 (600) (1,478) 6,857
Net income (loss).............. 3,607 463 (1,852) (119)
Net income (loss) per share.... 0.12 0.02 (0.09) (0.03)
- ---------------
/(1) /The sum of the quarterly reported amounts for earnings per share do not
equal full year amounts.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
(A) INTRODUCTION
The following discussion is intended to assist in understanding the Company's
financial position and results of operations for each year in the three year
period ended December 31, 1996. The Consolidated Financial Statements and the
notes thereto should be referred to in conjunction with this discussion.
(B) OVERVIEW
The Company was organized in 1987 to pursue opportunities to acquire oil and
natural gas properties. Since its inception, the Company has grown through a
series of strategic corporate and property acquisitions combined with an
exploration program that focuses on UMC's existing properties in North America
and in certain international regions. Management's strategy is to (i) balance
the risk of exploration prospects with lower risk exploitation and development
of existing reserves, (ii) concentrate its activities in specific regions where
the Company has expertise, while retaining geographical diversification, and
(iii) augment its industry and institutional relationships to access new
opportunities.
The Company's international activities are focused on the offshore regions of
Equatorial Guinea, Cote d'Ivoire, Pakistan and Bangledesh, where it holds
substantial acreage positions in highly prospective geologic regions.
Management believes that these areas have the potential to significantly
increase the Company's reserves based upon results of drilling to date and
analysis of technical data regarding additional prospects.
Although the Company's reserves have historically been concentrated in natural
gas, recent discoveries, primarily from the Company's international operations,
have shifted the percentage of reserves represented by crude oil and condensate
toward a more equal balance with natural gas reserves. Concurrently, the
Company expects to continue the historical trend of adding to its North American
reserve base. The Company believes these additions to reserves, both
domestically and internationally, will lead to significant increases in
production over the next several years.
(C) RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1996 COMPARED WITH THE YEAR ENDED DECEMBER 31, 1995
Oil and gas revenues for 1996 were $206.5 million, or 82.1% greater than 1995
oil and gas revenues of $113.4 million primarily due to significant improvements
in oil and natural gas prices and production volumes. The average sales price
after hedging for natural gas increased to $2.07 per Mcf, or 35.3%, in 1996 from
1995. The impact of
-15-
hedging on natural gas prices received and natural gas revenues for 1996 and
1995 was an increase (decrease) of ($0.06) and $0.07 per MCF and ($3.7) million
and $3.5 million, respectively. Natural gas production for 1996 was 55,445 MMCF,
an increase of 24.7% over 1995 volumes due primarily to new production from the
Gulf of Mexico and a full year of gas production in Cote d'Ivoire which
commenced in late 1995. Oil production increased 59.2%, or 1,634 MBO, in 1996
due primarily to increased oil production in Cote d'Ivoire and commencement of
production in Equatorial Guinea in August 1996. The average sales price after
hedging for oil increased to $20.94, or 28.1%, in 1996 compared to 1995. The
impact of hedging on oil prices received and oil revenues for 1996 and 1995 was
an increase (decrease) of ($0.04) and $0.22 per barrel and ($0.2) million and
$0.6 million, respectively.
UMC's exploration strategy provides that essentially all prospects will be
generated in-house. This approach usually means that a portion of the interest
in each property is available for farmout, sale or other arrangement. A sales
transaction is often used in the case of international prospects that have been
acquired by UMC and subsequently enhanced by the acquisition and interpretation
of seismic data, geologic and engineering analysis and possibly the drilling of
wells. UMC's exploration and engineering staff have consistently shown the
ability to add value to both domestic and international prospects.
In recent years, UMC has developed its business strategy to include the sale
of both developed and undeveloped properties. With respect to developed
properties, sales may be made to (i) redeploy capital in regions where returns
are greater; (ii) eliminate properties that do not fit the Company's geographic
profile; (iii) dispose of marginal assets, and (iv) accept offers where the
buyer gives significantly greater value to a property than UMC's technical staff
and outside engineers. As a result of a significant portion of the Company's
growth coming through large acquisitions, the sale of developed properties under
the above criteria is a frequent occurrence. During 1996, the Company was
successful in selling certain properties with proved reserves of 3.2 MMBOE and
approximate operating costs, including DD&A, of $7.89/BOE for cash proceeds of
$28.8 million. In return, the Company purchased properties with 3.2 MMBOE of
proved reserves and an approximate operating cost, including DD&A, of $4.75/BOE
for $6.7 million.
The activities discussed above generated gains on sales of assets of $29.0
million in 1996, as compared to $31.2 million in 1995. The 1996 gains on sales
of assets resulted primarily from sales of unproved international interests
including a $15.8 million pre-tax gain recognized as the final installment on
the assignment of a portion of the Company's interest in Block B in Equatorial
Guinea to Mobil in October 1995, and the sale in September 1996 of a 55%
contract interest in Block CI-105 in Cote d'Ivoire to Shell from which the
Company recognized a pre-tax gain of $3.3 million. Gains on sales of producing
properties in North America were primarily generated by a pre-tax gain of $4.7
million recognized as a result of the sale by UMC Resources Canada Ltd., the
Company's wholly-owned Canadian subsidiary, of its interest in the Rocanville
area in June 1996, and a pre-tax gain of $3.6 million recognized as a result of
the sale of interests in the Elk City and Arapaho fields in December 1996. The
largest contributors to the gain in 1995 were the sales of partial interests to
Yukong Limited of a portion of the Company's interests in Block CI-01 and CI-02
in Cote d'Ivoire and Blocks C and D in Equatorial Guinea and the first
installments of the sale to Mobil of a 10% interest in Block B in Equatorial
Guinea. For these international sales in 1995, a pre-tax gain of $18.3 million
was recognized on proceeds of $22.1 million. During 1995, the Company
recognized pre-tax gains of $12.9 million on sales of producing properties in
North America.
Production costs, including ad valorem and production taxes, for 1996 of $51.3
million increased 19.6% from $42.9 million for 1995, primarily due to a full
year of production in Cote d'Ivoire and commencement of production in Equatorial
Guinea. However, on a cost per BOE basis, production costs for 1996 decreased
$0.46 per BOE (10.9%) when compared to 1995.
General and administrative expenses for 1996 were $12.7 million compared to
$10.4 million in 1995. This increase was primarily due to nonrecurring
severance expenses of $0.9 million in 1996, $0.7 million of expenses associated
with miscellaneous non-cash benefits accruals and an overall expansion of the
Company's operations. However, general and administrative expenses per BOE of
production decreased from $1.03 per BOE in 1995 to $0.93 per BOE in 1996.
Exploration, dry hole and lease impairment expenses for 1996 totaled $40.3
million as compared to $15.7 million in 1995. This increase of $24.6 million
was primarily due to increased dry hole costs experienced in the Gulf of Mexico,
certain onshore areas and Equatorial Guinea Block D. In addition, the Company
had increased geological
-16-
and geophysical costs in 1996 reflecting a higher level of exploration activity
in Cote d'Ivoire, Equatorial Guinea and North America.
Depreciation, depletion and amortization (DD&A) expense for 1996 of $85.0
million increased 57.7% from $53.9 million for 1995. This increase is primarily
attributable to increased production levels in Cote d'Ivoire and Equatorial
Guinea. The rate per BOE of oil and gas DD&A increased 15.6% from $5.19 per BOE
in 1995 to $6.00 per BOE in 1996. This increase is a result of capitalized
costs in Equatorial Guinea which reflect certain development expenditures in
anticipation of significant future reserve extensions and additions that are not
recognized as proved reserves at December 31, 1996. In addition, certain
downward revisions of proved oil and gas reserves in the United States were
recognized by the Company during 1996, increasing DD&A rates. Furthermore, a
greater proportion of the Company's North American oil and gas volumes were
produced from the Gulf of Mexico region in 1996 versus 1995, which historically
has higher depletion rates.
Interest and debt expense for 1996 was $22.8 million compared to $17.9 million
in 1995. Non-cash amortization of debt issue costs totaled $2.1 million for
1996, as compared to $1.2 million for 1995. The $0.9 million increase is
primarily due to the amortization of the original issue discount on the 10-3/8%
Senior Subordinated Notes (Notes) due 2005 and the write-off of debt issue costs
upon the purchase of the Cote d'Ivoire Project Loan in November 1996 by the
Company with a portion of the proceeds from the November 1996 offering of common
stock. The additional $4.0 million increase is primarily due to a higher
average interest rate in 1996, resulting from the issuance of the Notes in the
fourth quarter 1995, and higher average debt levels in 1996 as compared to 1995.
An income tax provision of $6.0 million was recognized for 1996, compared to a
benefit of $3.9 million for 1995. Consistent with Statement of Financial
Accounting Standards (SFAS) 109, Accounting for Income Taxes, the income tax
provision or benefit was derived primarily from changes in deferred income tax
assets and liabilities recorded on the balance sheet. The primary items
affecting the 1996 deferred tax provision were the use of $13.0 million of net
operating loss (NOL) carryforwards to eliminate 1996 taxable income and the
deferred tax effect of exercised stock options. The 1995 deferred tax benefit
was affected by property sales, the impairment of proved properties relating to
the adoption of SFAS 121, Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to be Disposed Of, during the fourth quarter of 1995, and
offset by the use of $31.0 million of NOL carryforwards. At December 31, 1996,
the Company had $98.0 million of United States NOL carryforwards, $52.0 million
of Equatorial Guinea NOL carryforwards and $17.6 million of Canadian federal tax
pools. The Company paid cash income taxes in 1996 and 1995 of $0.4 million and
$0.6 million, respectively, to several states, Canada and the U.S. for the
Alternative Minimum Tax.
The Company reported net income of $17.4 million, or $0.51 per share, for 1996
compared to a net income of $2.1 million, or $0.02 per share, for 1995.
YEAR ENDED DECEMBER 31, 1995 COMPARED WITH THE YEAR ENDED DECEMBER 31, 1994
Oil and gas revenues for 1995 were $113.4 million, or 20.1% greater than 1994
oil and gas revenues of $94.4 million. The average sales price before hedging
for U.S. natural gas decreased to $1.46 per Mcf or 15.1% in 1995 from 1994. The
impact of hedging on natural gas prices received and natural gas revenues for
1995 and 1994 was an increase (decrease) of $0.07 and $(0.01) per MCF and $3.5
million and $(0.4) million, respectively. Natural gas production for 1995 was
44,453 MMCF, an increase of 12.1% over 1994 volumes due primarily to the
acquisition of GARI in late 1994 and commencement of production in Cote
d'Ivoire. The average sales price before hedging for oil increased 7.7% in 1995
compared to 1994. The impact of hedging on oil prices received and oil revenues
for 1995 and 1994 was an increase of $0.22 and $0.03 per barrel and $0.6 million
and $0.1 million, respectively. Oil production increased 55.2% or 982 MBO in
1995 due primarily to commencement of oil production in Cote d'Ivoire and the
GARI acquisition in late 1994.
The aforementioned business strategy of selling both developed and undeveloped
properties generated gains on sales of assets of $31.2 million in 1995, as
compared to $0.7 million in 1994. The largest contributors to the gain in 1995
were the sales of partial interests to Yukong Limited of a portion of the
Company's interests in Block CI-01 and CI-02 in Cote d'Ivoire and Blocks C and D
in Equatorial Guinea and the sale to Mobil of a 10% interest in Block B in
Equatorial Guinea. Under the agreement, the Company received $40.1 million in
cash in 1995 and 1996. A pre-tax gain of $18.3 million was recognized on 1995
proceeds of $22.1 million. During 1995, the Company recognized
-17-
$12.9 million as gain on sales of producing properties in North America.
Production costs, including ad valorem and production taxes, for 1995 of $42.9
million increased 16.3% from $36.9 million for 1994, primarily due to a full
year of ownership of GARI and commencement of production in Cote d'Ivoire.
However, on a cost per BOE basis, production costs for 1995 decreased $0.18 per
BOE when compared to 1994.
General and administrative expenses for 1995 were $10.4 million compared to
$12.5 million in 1994. This decrease was due to (i) certain non-recurring costs
in 1994 associated with the GARI merger; (ii) increase in recovery of management
fees from institutional partners; (iii) increase in recovery of overhead from
industry partners domestically and internationally and (iv) certain
consolidation efficiencies from the GARI merger. For the reasons previously
mentioned, general and administrative expense as a percentage of total revenue
decreased from 12.8% in 1994 to 7.1% in 1995.
Exploration, dry hole and lease impairment expenses for 1995 totaled $15.7
million as compared to $16.2 million in 1994. This decrease of $0.5 million was
primarily due to recovery of costs incurred from the sale of certain of the
Company's interests in Cote d'Ivoire and Equatorial Guinea as previously
discussed, offset by higher exploration activity levels internationally and
offshore in the Gulf of Mexico.
DD&A expense for 1995 of $53.9 million increased 6.3% from $50.7 million for
1994. However, the rate per BOE of oil and gas DD&A decreased 12.5% from $5.93
per BOE in 1994 to $5.19 per BOE in 1995. This absolute increase is primarily
attributable to increased production levels and commencement of production in
Cote d'Ivoire, offset by decreases in net book values due primarily to the
impairment of proved properties recorded at December 31, 1994.
During 1995, the Financial Accounting Standards Board (FASB) issued SFAS 121.
The Company adopted the provisions of SFAS 121 during the fourth quarter of
1995, recording a pre-tax impairment of $8.3 million (after-tax effect: $5.1
million).
Interest and debt expense for 1995 was $17.9 million compared to $9.0 million
in 1994. This $8.9 million increase is primarily due to the increased debt
levels incurred to acquire GARI and to support the 1995 capital expenditure
program, which was dominated by development expenditures in the Gulf of Mexico
and Western Africa. The Company's average interest rate for 1995 and 1994 was
7.47% and 5.95%, respectively. The increase in the average interest rate is due
primarily to the issuance of the Notes during the fourth quarter of 1995. While
raising the Company's average interest rate, issuance of the Notes replenished
liquidity available under the Company's Credit Facility.
An income tax benefit of $3.9 million was recognized for 1995, compared to a
benefit of $41.5 million for 1994. Consistent with SFAS 109, the income tax
benefit was derived primarily from changes in deferred income tax assets and
liabilities recorded on the balance sheet. The primary items affecting the 1995
deferred tax benefit were the property sales and the impairment of proved
properties relating to the adoption of SFAS 121 during the fourth quarter of
1995. The 1994 $94.8 million impairment of proved oil and gas property was the
largest item affecting the 1994 deferred tax benefit. All of these transactions
had the effect of reducing the difference between the tax basis of Company
assets and the basis of those assets for financial reporting purposes. This
reduction in deferred tax liabilities more than offset the use of $31.0 million
of NOL carryforwards to eliminate 1995 taxable income. The Company paid cash
income taxes in 1995 and 1994 of $0.6 million and $0.4 million, respectively, to
several states, Canada and the U.S. for the Alternative Minimum Tax.
The Company reported net income of $2.1 million, or $0.02 per share, for 1995
compared to a net loss of ($81.0) million, or ($3.47) per share, for 1994.
(D) CAPITAL RESOURCES AND LIQUIDITY
The Company has historically funded its operations, acquisitions, exploration
and development expenditures from cash flows from operating activities, bank
borrowings, sales of common and preferred stock, issuance of senior subordinated
notes, sales of non-strategic oil and natural gas properties, sales of partial
interests in exploration
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concessions and project finance borrowings.
The primary sources of cash for the Company during the year ended December 31,
1996, included proceeds from the November 1996 offering of common stock, funds
generated from operations, bank borrowings, proceeds from asset sales and
exercise of stock options and warrants. In the comparable period of 1995, the
primary sources of cash included the issuance of the Notes, funds generated from
operations, proceeds from sales of certain oil and gas properties, project
financing borrowings and the issuance of the Series F preferred stock. For the
year ended December 31, 1994, the primary sources of cash included utilization
of long-term debt and funds generated from operations. Primary cash uses for
the years ended December 31, 1996 and 1995 included capital expenditures
(including exploration expenses) which totaled $185.9 million and $160.8
million, respectively. In the comparable period of 1994, the primary cash uses
included capital expenditures (including exploration expenses) of $53.4 million
and the acquisition of GARI.
Discretionary cash flow, a measure of performance for exploration and
production companies, is derived by adjusting net income to eliminate the
effects of exploration expenses, including dry hole costs and impairments, DD&A,
deferred income tax, gain (loss) on sale of assets and non-cash amortization of
debt issue costs. The effects of working capital changes are not taken into
account. This measure reflects an amount that is available for capital
expenditures, debt repayment or dividend payments. The Company generated
discretionary cash flow for the years ended December 31, 1996, 1995, and 1994 of
approximately $121.0 million, $45.8 million, and $39.0 million, respectively.
The 164% increase in discretionary cash flow in 1996 as compared to 1995 is
primarily due to increased production levels, as a result of a full-year of
production in Cote d'Ivoire, commencement of production in Equatorial Guinea,
and the improvements in oil and natural gas prices.
The Company has used the Credit Facility (see Note 5 of the Notes to
Consolidated Financial Statements) to partially finance its expenditures. As of
December 31, 1996, the borrowing base under the Credit Facility was $200
million, and the Company had no outstanding loans thereunder and outstanding
letters of credit of approximately $0.6 million. Resulting liquidity
(including cash) exceeded $254 million as compared to $124 million at December
31, 1995. The Company recently completed negotiations to expand the Credit
Facility to $300 million with an initial borrowing base of $275 million. The
new Credit Facility should be in place by the end of March 1997. Assuming the
new Credit Facility, liquidity (including cash) will increase to approximately
$325 million.
In July 1995, a subsidiary of the Company entered into a loan agreement (the
Cote d'Ivoire Facility) with the International Finance Corporation (IFC), an
affiliate of the World Bank, in connection with the development of Block CI-11
offshore Cote d'Ivoire. The Cote d'Ivoire Facility provided for borrowings up
to $35.0 million by the Company's subsidiary which holds UMC's interest in Block
CI-11. In November 1996, the Cote d'Ivoire Facility was purchased by the
Company paying off the IFC in full with a portion of the proceeds of the
November 1996 offering of common stock.
Effective January 18, 1994, the Company entered into five-year fixed LIBOR
interest rate swap contracts that provide for fixed interest rates to be
realized on notional amounts of $30.0 million in 1994 and $45.0 million through
1998. The agreement includes varying annual fixed interest rates ranging from
3.66% in 1994 to 6.40% in 1998, plus interest rate margins. Additionally, the
Company entered into a two-year LIBOR interest rate cap contract on an
additional notional amount of $45.0 million for 1995 and 1996 at interest rate
caps of 7.60% and 8.30%, respectively, plus interest rate margins.
Equity financings have represented a significant source of funds for the
Company. Since its inception, over $197 million of private equity capital and
approximately $343 million of public equity capital has been raised to support
its growth. The Company completed its initial public offering in July 1993,
resulting in net proceeds to the Company of $68.7 million. In November 1994,
the Company issued approximately $64 million in common equity as partial
consideration for the GARI acquisition. In June and July 1995, the Company sold
an aggregate $35.0 million of Series F Preferred Stock in a private placement to
institutional investors. In July 1996, the Series F Preferred Stock was
converted to 1.845 million common shares in accordance with its automatic
conversion terms. In November 1996, the Company issued 4.089 million common
shares for $182.7 million in cash to be used to fund planned capital
expenditures and for general corporate purposes.
On October 30, 1995, the Company closed a public offering of $150 million of
Notes at an initial price of 99.5%
-19-
of face value. Proceeds of $144.9 million (after deducting underwriting
discounts, commission and expenses of the offering) were used to reduce debt
under the Credit Facility.
As part of its on-going operations, the Company periodically sells interests
in proved reserves and enhanced exploration prospects. This practice continued
in 1996 and 1995, with net cash proceeds from sales of assets of $50.2 million
and $78.1 million, respectively. The 1996 proceeds consisted of (i) $18.1
million in cash received in 1996 related to the 1995 Mobil purchase of an
additional 10% interest in Block B in Equatorial Guinea, (ii) $28.8 million
received from the sales of various non-strategic North American properties, and
(iii) $3.3 million received from Shell for a 55% contract interest in Block CI-
105 in Cote d'Ivoire. These proceeds were used to pay-down debt and to redeploy
capital to domestic and international opportunities which management believes
represent higher rates of return.
The Company's capital expenditure budget for 1997 is expected to be
approximately $250 million, consisting of approximately $84 million for
exploration, approximately $159 million for development and approximately $7
million of other capital expenditures. Primary areas of emphasis will be East
Texas, the Gulf of Mexico and Western Africa. If the Company has successful
exploration results during 1997, the operating capital budget could be expanded
by approximately $50 million for follow-up appraisal or development
expenditures. In addition, the Company will evaluate its level of capital
spending throughout the year based upon drilling results, commodity prices, cash
flows from operations and property acquisitions. Actual capital spending may
vary from the initial capital expenditure budget.
Due to the aforementioned expanded credit facility and the equity offering
completed in November 1996, the Company's financial structure has been
significantly strengthened. The Company's debt to total capitalization ratio
has decreased to 26.7% at December 31, 1996, from 53.9% at December 31, 1995.
Combined with cash flows from operating activities, the Company has the
financial strength, leverage and liquidity that will allow it to fund the 1997
capital expenditure program, including the international exploration and
development opportunities in Cote d'Ivoire and Equatorial Guinea, and continue
to selectively pursue strategic corporate and property acquisitions.
The Company's interest coverage ratio (calculated as the ratio of income from
operations plus DD&A, impairment of proved oil and gas properties and
exploration expense to interest plus capitalized interest less non-cash
amortization of debt issue costs) was 7.56 to 1 for 1996, compared with 5.26 to
1 for 1995.
(E) NET OPERATING LOSS CARRYFORWARDS AND CANADIAN TAX POOLS
At December 31, 1996, the Company had $98.0 million of United States NOL
carryforwards, $52.0 million of Equatorial Guinea NOL carryforwards and $17.6
million of Canadian federal tax pools which it expects to use in sheltering
future taxable income in the U.S., Equatorial Guinea and Canada, respectively,
as compared to December 31, 1995 amounts of $116.0 million, $21.0 million and
$21.9 million for the United States, Equatorial Guinea and Canada, respectively.
The decrease in the United States and Canada results primarily from the 1996
usage of NOL and tax pool carryforwards to shelter taxable income. The increase
in Equatorial Guinea results from expensing some up-front costs and production
not starting until August 1996.
The Company's U.S. NOL carryforward is subject to certain limitations. Under
Section 382 of the Internal Revenue Code, the taxable income of UMC available
for offset by pre-ownership change NOL carryforwards and certain built-in losses
is subject to an annual limitation (the 382 Limitation) if an "ownership change"
occurs. The Company has determined that an ownership change occurred for
purposes of Section 382 in 1994. As a result of this ownership change, the
total amount of UMC's NOL carryforwards will not be affected, but the annual 382
Limitation will equal the fair market value of the Company immediately before
the ownership change multiplied by the long-term tax exempt interest rate,
subject to adjustment for certain built-in gains of the Company. To the extent
the 382 Limitation exceeds the federal taxable income of the post-merger company
for a given year, the 382 Limitation for the subsequent year will be increased
by such excess. NOL carryforwards of the Company will be disallowed entirely if
certain continuity of business enterprise requirements are not met. It is
expected these requirements will be met. The effect of the 382 Limitation may
be to defer the use of the Company's existing NOL carryforwards.
As shown in Note 7 of the Notes to the Consolidated Financial Statements, $8.0
million of the Company's U.S. federal NOLs will expire in 1997. Management
believes that the 1997 taxable income of the consolidated group will
-20-
exceed $8.0 million, and that no NOLs will expire unused.
(F) FOREIGN CURRENCY TRANSACTIONS
The financial position and results of operations attributable to the Company's
Canadian operations are translated into U.S. currency in accordance with SFAS
52, Foreign Currency Translation. Accordingly, the assets and liabilities of the
financial statements are translated using the currency exchange rate in effect
at the balance sheet date while the revenues, expenses, gains and losses are
translated using the exchange rate for the periods in which they occurred. The
effect of such translations are reflected as adjustments to stockholders' equity
as shown in the Statement of Changes in Stockholders' Equity in the Company's
Consolidated Financial Statements.
Essentially all revenues and expenditures for the Company's West African
operations are settled, and all books and records are maintained, in U.S.
dollars.
(G) CHANGES IN PRICES AND INFLATION
The Company's revenues and the value of its oil and natural gas properties
have been, and will continue to be, affected by changes in oil and natural gas
prices. The Company's ability to maintain current borrowing capacity and to
obtain additional capital on attractive terms is also substantially dependent on
oil and natural gas prices. Oil and natural gas prices are subject to
significant seasonal and other fluctuations that are beyond the Company's
ability to control or predict. Although certain of the Company's costs and
expenses are affected by the level of inflation, inflation did not have a
significant effect on the Company's results of operations during 1996 and 1995.
(H) FORWARD-LOOKING STATEMENTS
Certain statements in this report, including statements of the Company's and
management's expectations, intentions, plans and beliefs, including those
contained in or implied by "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and the Notes to Consolidated Financial
Statements, are forward-looking statements, as defined in Section 21E of the
Securities Exchange Act of 1934, that are dependent on certain events, risk and
uncertainties that may be outside the Company's control. These forward-looking
statements include statements of management's plans and objectives for the
Company's future operations and statements of future economic performance;
information regarding drilling schedules, expected or planned production or
transportation capacity, future production levels of international and domestic
fields, the Company's capital budget and future capital requirements, the
Company's meeting its future capital needs, the Company's realization of its
deferred tax assets, the level of future expenditures for environmental costs
and the outcome of regulatory and litigation matters; and the assumptions
described in this report underlying such forward-looking statements. Actual
results and developments could differ materially from those expressed in or
implied by such statements due to a number of factors, including, without
limitation, those described in the context of such forward-looking statements,
fluctuations in the price of crude oil and natural gas, the success rate of
exploration efforts, timeliness of development activities, and the risk factors
described from time to time in the Company's other documents and reports filed
with the Securities and Exchange Commission.
(I) IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS
The FASB issued SFAS 123, Accounting for Stock-Based Compensation, during
1996. The Company has reported the impact of SFAS 123 on a proforma basis as
allowed under the pronouncement. See Note 8 of the Notes to Consolidated
Financial Statements.
In October 1996, the American Institute of Certified Public Accountants issued
Statement of Position No. 96-1, Environmental Remediation Liabilities, which
establishes new accounting and reporting standards for the recognition and
disclosure of environmental remediation liabilities. The provisions of the
statement are effective for fiscal years beginning after December 15, 1996. The
impact of this new standard is not expected to have a significant effect on the
Company's financial position or results of operations.
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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
Page
...............................................................................................................
Report of Independent Public Accountants.......................................................................... 23
Consolidated Statement of Income, Years Ended December 31, 1996, 1995 and 1994.................................... 24
Consolidated Balance Sheet, December 31, 1996 and 1995............................................................ 25
Consolidated Statement of Changes in Stockholders' Equity, Years Ended December 31,
1996, 1995 and 1994.............................................................................................. 27
Consolidated Statement of Cash Flows, Years Ended December 31, 1996, 1995 and 1994................................ 28
Notes to Consolidated Financial Statements........................................................................ 29
-22-
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders,
United Meridian Corporation:
We have audited the accompanying consolidated balance sheets of United
Meridian Corporation (a Delaware corporation) and subsidiaries as of December
31, 1996 and 1995, and the related consolidated statements of income, changes in
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1996. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of United Meridian Corporation and
subsidiaries as of December 31, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1996, in conformity with generally accepted accounting principles.
As discussed in Note 3 to the Consolidated Financial Statements, during 1995,
the Company adopted the provisions of Statement of Financial Accounting
Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of.
ARTHUR ANDERSEN LLP
Houston, Texas
February 20, 1997
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UNITED MERIDIAN CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEARS ENDED DECEMBER 31,
-------------------------------------------
1996 1995 1994
-------- -------- --------
Operating revenues:
Gas sales..................................................... $114,498 $ 68,228 $ 67,763
Oil sales..................................................... 92,031 45,122 26,675
Contract settlements and other................................ 854 2,507 2,703
Gain on sale of assets........................................ 29,021 31,184 676
-------- -------- --------
236,404 147,041 97,817
-------- -------- --------
Costs and expenses:
Production costs.............................................. 51,298 42,891 36,938
General and administrative.................................... 12,727 10,425 12,504
Exploration, including dry holes and impairments.............. 40,325 15,682 16,187
Depreciation, depletion and amortization...................... 84,979 53,942 50,727
Impairment of proved oil and gas properties................... - 8,317 94,793
-------- -------- --------
189,329 131,257 211,149
-------- -------- --------
Income (loss) from operations.................................. 47,075 15,784 (113,332)
Other income, expenses and deductions:
Interest and other income (expense)........................... (844) 375 (141)
Interest and debt expense..................................... (22,811) (17,945) (9,040)
-------- -------- --------
Net income (loss) before income taxes.......................... 23,420 (1,786) (122,513)
Income tax benefit (provision):
Current....................................................... (785) (332) (25)
Deferred...................................................... (5,231) 4,217 41,549
-------- -------- --------
Net income (loss).............................................. $ 17,404 $ 2,099 $(80,989)
======== ======== ========
Net income (loss) per common share............................. $ 0.51 $ 0.02 $ (3.47)
======== ======== ========
Weighted average number of common shares and
common share equivalents outstanding......................... 31,428 29,259 23,330
======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
-24-
UNITED MERIDIAN CORPORATION
CONSOLIDATED BALANCE SHEET
(IN THOUSANDS)
DECEMBER 31,
---------------------------------
1996 1995
ASSETS -------- ---------
Current assets:
Cash and cash equivalents.............................................. $ 54,942 $ 13,586
Accounts receivable, net of allowance for doubtful accounts of
$1,190 and $1,266 at December 31, 1996 and 1995, respectively:
Oil and gas sales................................................... 36,238 18,188
Joint interest and other............................................ 45,447 22,522
Deferred income taxes.................................................. 2,839 3,875
Inventory.............................................................. 11,389 15,313
Prepaid expenses and other............................................. 5,306 2,529
--------- ---------
156,161 76,013
--------- ---------
Property and equipment, at cost:
Oil and gas (successful efforts method)
Proved properties.................................................... 851,818 759,695
Unproved properties.................................................. 14,667 12,369
Other property and equipment........................................... 8,295 6,231
--------- ---------
874,780 778,295
Accumulated depreciation, depletion and amortization................... (350,591) (309,622)
--------- ---------
524,189 468,673
--------- ---------
Other assets:
Gas imbalances receivable.............................................. 5,702 5,852
Deferred income taxes.................................................. 23,035 17,140
Debt issue cost........................................................ 8,370 9,905
Other.................................................................. 836 867
--------- ---------
37,943 33,764
--------- ---------
TOTAL ASSETS...................................................... $ 718,293 $ 578,450
========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
-25-
UNITED MERIDIAN CORPORATION
CONSOLIDATED BALANCE SHEET
(IN THOUSANDS, EXCEPT FOR SHARE AMOUNTS)
DECEMBER 31,
--------------------------------
1996 1995
------------- ------------
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable............................. $ 80,593 $ 58,137
Advances from joint owners................... 5,575 8,238
Interest payable............................. 3,800 4,494
Accrued liabilities.......................... 7,525 6,202
Notes payable................................ - 10,639
Current maturities of long-term debt......... 899 3,100
--------- ---------
98,392 90,810
--------- ---------
Long-term debt:
Revolving loan............................... - 61,049
Cote d'Ivoire project loan................... - 33,750
10-3/8% senior subordinated notes............ 150,000 150,000
Other........................................ 6,832 -
--------- ---------
156,832 244,799
--------- ---------
Deferred credits and other liabilities:
Deferred income taxes........................ 20,797 18,499
Gas imbalances payable....................... 3,994 6,377
Other........................................ 6,042 5,653
--------- ---------
30,833 30,529
--------- ---------
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value,
32,000,000 shares authorized,
no shares issued and outstanding
at December 31, 1996 and 1995.............. - -
Series F preferred stock, $.01 par value,
1,166,667 shares authorized, issued
and outstanding at December 31, 1995....... - 12
Common stock, $.01 par value,
46,000,000 shares authorized,
35,217,206 and 28,150,224 shares issued
and outstanding at December 31, 1996
and 1995, respectively..................... 352 281
Additional paid-in capital................... 540,661 336,469
Foreign currency translation adjustment...... (4,257) (4,057)
Retained earnings (deficit).................. (104,520) (120,393)
--------- ---------
432,236 212,312
--------- ---------
TOTAL LIABILITIES AND
STOCKHOLDERS' EQUITY.................... $ 718,293 $ 578,450
========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
-26-
UNITED MERIDIAN CORPORATION
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
SERIES F
PREFERRED STOCK COMMON STOCK ADDITIONAL FOREIGN RETAINED
----------------- ----------------- PAID-IN CURRENCY EARNINGS
SHARES AMOUNT SHARES AMOUNT CAPITAL ADJUSTMENT (DEFICIT) TOTAL
------ ------ ------ ------ ---------- ---------- --------- -----
Balance, December 31, 1993.. - - 22,558,562 $226 $ 231,372 $ (1,907) $ (40,019) $ 189,672
Adjustment resulting
from recording the
acquisition of GARI in
accordance with the
purchase method........... (82) (82)
Foreign currency
translation adjustment.... (2,092) (2,092)
Exercise of common stock
options................... 144,375 1 1,404 1,405
Issuance of stock as
partial purchase in
GARI merger............... 5,018,944 50 63,474 63,524
Net loss................... (80,989) (80,989)
----------------------------------------------------------------------------------------------------
Balance, December 31, 1994.. - - 27,721,881 277 296,168 (3,999) (121,008) 171,438
Foreign currency
translation adjustment.... (58) (58)
Preferred stock issuance
- June 30................. 833,333 $ 8 24,992 25,000
- July 24................. 333,334 4 9,902 9,906
Exercise of common stock
options................... 428,343 4 5,407 5,411
Preferred stock dividends.. (1,484) (1,484)
Net income................. 2,099 2,099
----------------------------------------------------------------------------------------------------
Balance, December 31, 1995.. 1,166,667 12 28,150,224 281 336,469 (4,057) (120,393) 212,312
Foreign currency
translation adjustment.... (200) (200)
Automatic conversion of
Series F preferred to
common stock.............. (1,166,667) (12) 1,845,284 19 (7) -
Common stock offering...... 4,088,942 41 182,629 182,670
Exercise of common stock
options................... 897,007 9 17,951 17,960
Exercise of warrants....... 235,749 2 3,619 3,621
Preferred stock dividends.. (1,531) (1,531)
Net income................. 17,404 17,404
----------------------------------------------------------------------------------------------------
Balance, December 31, 1996.. - $ - 35,217,206 $352 $ 540,661 $ (4,257) $(104,520) $432,236
====================================================================================================
The accompanying notes are an integral part of these consolidated financial
statements.
-27-
UNITED MERIDIAN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(IN THOUSANDS)
YEARS ENDED DECEMBER 31,
---------------------------------------------
1996 1995 1994
---------- --------- ----------
Cash flows from operating activities:
Net income (loss)................................................... $ 17,404 $ 2,099 $ (80,989)
Adjustments to reconcile net income (loss) to cash from
operating activities:
Exploration, including dry holes and impairments.................. 40,325 15,682 16,187
Depreciation, depletion and amortization.......................... 84,979 53,942 50,727
Impairment of proved oil and gas properties....................... - 8,317 94,793
Amortization of debt issue cost................................... 2,127 1,173 532
Deferred income tax provision (benefit)........................... 5,231 (4,217) (41,549)
Gain on sale of assets............................................ (29,021) (31,184) (676)
--------- --------- ---------
121,045 45,812 39,025
Changes in assets and liabilities:
Decrease (increase) in receivables............................... (22,868) (9,618) 6,118
Decrease (increase) in inventory................................. (6,715) 1,773 (5,622)
Increase (decrease) in payables and accrued liabilities.......... (1,495) 8,150 (7)
Increase (decrease) in net gas imbalances........................ (2,233) 729 (408)
Other............................................................ (4,300) (840) 4,458
--------- --------- ---------
Net cash provided by operating activities...................... 83,434 46,006 43,564
--------- --------- ---------
Cash flows from investing activities:
Exploration......................................................... (64,191) (32,914) (21,169)
Development......................................................... (112,639) (97,934) (30,968)
Acquisition of properties........................................... (6,686) (28,538) (798)
Additions to other property and equipment........................... (2,385) (1,441) (419)
Corporate acquisitions (net of cash acquired)....................... - - (129,182)
Net proceeds from the sale of assets................................ 50,152 78,119 2,376
--------- --------- ---------
Net cash used in investing activities........................... (135,749) (82,708) (180,160)
Cash flows from financing activities:
Repayment of long-term debt......................................... (274,831) (337,033) (90,299)
Additions to total debt............................................. 176,932 345,298 237,784
Debt issue cost..................................................... (251) (6,089) (964)
Net proceeds from issuance of preferred stock....................... - 34,906 -
Net proceeds from common stock offering............................. 182,670 - -
Preferred stock dividends........................................... (1,531) (1,484) -
Proceeds from common stock options and warrants exercised........... 10,682 2,865 1,405
--------- --------- ---------
Net cash provided by financing activities....................... 93,671 38,463 147,926
--------- --------- ---------
Net increase in cash and cash equivalents............................ 41,356 1,761 11,330
Cash and cash equivalents at beginning of period..................... 13,586 11,825 495
--------- --------- ---------
Cash and cash equivalents at end of period........................... $ 54,942 $ 13,586 $ 11,825
========= ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
-28-
UNITED MERIDIAN CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 ORGANIZATION
The accompanying consolidated financial statements of United Meridian
Corporation (UMC or the Company), a Delaware corporation, have been prepared
pursuant to the rules and regulations of the Securities and Exchange Commission
(SEC). The 1994 Statement of Income includes the results of operations of
General Atlantic Resources, Inc. (GARI) beginning September 19, 1994. This
consolidation reflects the Company's 51% ownership of GARI as of September 19,
1994 and 100% ownership as of November 15, 1994. See Note 4 below for
additional information concerning acquisitions and dispositions.
The Company is an independent energy company engaged in the acquisition,
exploration, development and production of natural gas and crude oil across
North America and in the West African oil and natural gas producing regions of
Cote d'Ivoire and Equatorial Guinea.
The financial statements reflect all adjustments that, in the opinion of
management, are necessary for a fair presentation.
NOTE 2 SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company and
its majority-owned affiliates. All significant intercompany balances and
transactions have been eliminated in consolidation.
Certain reclassifications of amounts previously reported have been made to
conform to current year presentation.
CASH AND CASH EQUIVALENTS
The Company considers all highly liquid investments with a maturity of three
months or less to be cash equivalents.
INVENTORY
UMC conducts a portion of its oil and gas activities with a small group of
institutional and corporate investors. In connection therewith, the Company
periodically acquires oil and gas properties with the intention of selling a
portion of its interests to such investors. To the extent those properties are
to be resold to investors, costs are carried as a current asset and classified
as inventory. No gain or loss is recognized on inventoried properties. At
December 31, 1996 and 1995, costs of properties to be resold included in
inventory totaled $2,270,000 and $12,410,000, respectively. The remaining
inventory consists of tubular goods and other equipment.
OIL AND GAS PROPERTIES
The Company and its subsidiaries follow the successful efforts method of
accounting for oil and gas producing activities. Under this method, all costs
to acquire mineral interests in oil and gas properties, to acquire production
sharing contracts with foreign governments, to drill and equip exploratory wells
which find proved reserves and to drill and equip development wells are
capitalized. Geological and geophysical costs, delay rentals and technical
support costs are expensed as incurred except in those circumstances where the
Company has a contractual right to recover such costs from proved reserves, in
which case they are capitalized. Other internal costs related to oil and gas
acquisitions, exploration and development activities are generally expensed as
general and administrative, exploration or production expenses. The costs of
drilling exploratory wells which do not find proved reserves are expensed upon
determination that a well does not justify commercial development. The
capitalized costs of producing oil and gas properties are depreciated and
depleted by the units-of-production method based upon estimated proved reserves.
Unproved oil and gas properties are periodically assessed for impairment of
value and a loss is recognized as appropriate.
-29-
OTHER PROPERTY AND EQUIPMENT
Other property consists primarily of furniture, office equipment, leasehold
improvements and computers. The majority of these assets are depreciated on a
straight-line basis with useful lives of three to seven years.
GAS IMBALANCES
The Company follows the entitlements method of accounting for production
imbalances. Under this method, the Company recognizes revenues based on its
interest in production from a well. Imbalance payables are recorded at
historical amounts and imbalance receivables are valued at the lower of (i) the
price in effect at the time of production, (ii) the current market value or
(iii) the contract price net of selling expenses. Gas imbalances arise when a
purchaser takes delivery of more or less gas volume from a well than UMC's
actual interest in the production from that well. Such imbalances are reduced
either by subsequent recoupment of over and under deliveries or by cash
settlement, as required by applicable contracts. Under-deliveries are included
in Other Assets and over-deliveries are included in Deferred Credits and Other
Liabilities.
HEDGING
UMC periodically enters into contracts in order to hedge against the
volatility in oil and gas prices. The Company enters into such transactions for
the purpose of insuring against a possible decline in the short-term (3 to 12
months) price of oil or natural gas. The contracts generally take the form of
swaps or price collars, and are placed with major financial institutions. The
results of such transactions are included as Oil or Gas Sales in the
Consolidated Statement of Income as the related production volumes are sold.
The Company may also enter into interest rate hedge contracts from time to
time with major financial institutions. These transactions are made to protect
against higher future interest costs on the Company's long-term debt. The
results of interest rate hedges are included in Interest Expense on the
Consolidated Statement of Income.
FEDERAL INCOME TAXES
The Company follows the provisions of Statement of Financial Accounting
Standards (SFAS) 109, Accounting for Income Taxes, under which deferred tax
assets or liabilities are estimated at the financial statement date based upon
(i) temporary differences between the tax basis of assets and liabilities and
their reported amounts in the financial statements and (ii) net operating loss
and tax credit carryforwards for tax purposes.
EARNINGS PER SHARE
Earnings per share have been computed by dividing net income available to
common stockholders by the weighted average number of shares of Common Stock
outstanding during the period, increased by the effect of common stock
equivalents from stock options and warrants, when dilutive. Fully-diluted
earnings per share are not shown as the difference is either immaterial or
antidulitive in all periods presented.
STATEMENT OF CASH FLOWS
Cash flows from operating activities for 1996, 1995 and 1994, include cash
payments for interest of $22,032,000, $14,642,000, and $8,042,000 and income
taxes of $446,000, $553,000 and $408,000, respectively.
FOREIGN CURRENCY TRANSLATION
The financial position and results of operations attributable to the Company's
Canadian operations are translated into U.S. currency in accordance with SFAS
52, Foreign Currency Translation. Accordingly, the assets and liabilities of
the financial statements are translated using the currency exchange rate in
effect at the balance sheet date while the revenues, expenses, gains and losses
are translated using the exchange rate for the periods in which they occurred.
The effect of such translations are reflected as adjustments to stockholders'
equity as shown in the Statement of Changes in Stockholders' Equity in the
Company's Consolidated Financial Statements.
-30-
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates.
NOTE 3 CHANGES IN METHOD OF ACCOUNTING FOR ASSESSING RECOVERABILITY OF PROVED
OIL AND GAS PROPERTIES
During 1995, the Financial Accounting Standards Board issued SFAS 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of. The Company adopted the provisions of SFAS 121 and recorded a
pre-tax impairment of $8,317,000 (after-tax effect: $5,125,000) during the
fourth quarter of 1995. No such provision was required in 1996.
Prior to its adoption of SFAS 121, the Company assessed recoverability of its
proved properties by individual property groups having similar geological or
operating characteristics utilizing estimates of undiscounted future net
revenues attributable to proved reserves based on current prices. A precipitous
decline in natural gas prices at year-end 1994 and continuing into 1995 required
an adjustment to costs attributable to proved properties of $94,793,000 before
tax (after-tax effect: $58,772,000).
NOTE 4 ACQUISITIONS AND DISPOSITIONS
As part of its on-going operations, the Company continually sells producing
and undeveloped reserves and related assets. Significant acquisitions and
dispositions for the years ending December 31, 1996, 1995 and 1994 are shown
below.
1996 TRANSACTIONS
In 1995, the Company agreed to assign to Yukong Limited a portion of its
interests in Blocks CI-01 and CI-02 in Cote d'Ivoire and Blocks B, C and D in
Equatorial Guinea. Mobil subsequently exercised its preferential right to
purchase the interest in Block B in lieu of the proposed assignment to Yukong
Limited. Under the agreements, the Company received $40,135,000 in cash in 1996
and 1995, resulting in pre-tax gains of $15,774,000 and $18,278,000,
respectively.
In June 1996, UMC Resources Canada Ltd. (Resources), the Company's wholly-
owned Canadian subsidiary, sold all of its interest in the Rocanville area in
the province of Saskatchewan, effective May 1, 1996. Net proceeds from the sale
were $6,722,000 and a pre-tax gain of $4,679,000 was recognized. Total proved
reserves attributable to the interests sold were 728 MBOE at December 31, 1995.
In September 1996, the Company executed an agreement with Shell to sell a 55%
contract interest in Block CI-105 in Cote d'Ivoire. The sale resulted in the
Company recognizing a pre-tax gain of $3,260,000 on cash proceeds of $3,260,000.
An additional $900,000 was received relating to reimbursement of exploration
expense previously incurred by the Company.
In December 1996, the Company sold its interests in the Elk City and Arapaho
fields. Net proceeds from the sale were $9,064,000 and a pre-tax gain of
$3,607,000 was recognized.
During 1996, the Company sold various other non-strategic North American
properties for total proceeds of $13,029,000 resulting in pre-tax gains of
$1,701,000.
-31-
1995 TRANSACTIONS
In February 1995, UMC sold all of its interest in oil and gas properties in
West Virginia, effective January 1, 1995. Net proceeds from the sale were
$41,200,000 and a pre-tax gain of $7,000,000 was recognized. Total proved
reserves at December 31, 1994 attributable to the sold properties were 10,286
MBOE.
In March 1995, UMC sold all of its interest in the Main Pass 108 offshore
Louisiana field effective February 1, 1995. Net proceeds from the sale were
$6,900,000 with a recognized pre-tax gain of $4,700,000. Total proved reserves
at December 31, 1994 associated with the Company's interest in Main Pass 108
were 351 MBOE.
In October 1995, the Company and its institutional partners acquired certain
oil and natural gas properties at a cost of $58,626,000 (approximately
$21,300,000 net to the Company). The acquired interests relating to one of the
institutional partners (in an additional amount of approximately $10,250,000)
were included in inventory until January 1996, at which time the partner
reimbursed UMC for its proportionate share of the acquisition, including
carrying costs. A separate short-term facility was negotiated for the financing
of this interest in the properties and was paid at closing in January 1996.
1994 TRANSACTIONS
On November 15, 1994 the Company and its wholly-owned subsidiary, UMC Merger
Corporation, a Delaware corporation, completed the acquisition of all
outstanding common stock of GARI, 51% of which was purchased for cash and the
remainder of which was acquired in exchange for the issuance of 5,018,944 shares
of UMC common stock. The acquisition was accounted for under the purchase
method and, as a result, the assets and liabilities of GARI were added to the
Company's balance sheet as of September 19, 1994 at amounts that reflect the
purchase price of 51% of GARI's equity. On November 15, 1994, the remainder of
GARI's equity was acquired by exchange of stock and was recorded as additional
basis in the assets acquired.
NOTE 5 DEBT
Long-term debt consisted of the following at December 31, 1996 and 1995 (in
thousands):
1996 1995
----------- ----------
Revolving loan........................ $ - $ 61,049
10-3/8% senior subordinated notes..... 150,000 150,000
Cote d'Ivoire project loan............ - 35,000
Unsecured notes....................... - 1,850
Other................................. 7,731 -
-------- --------
157,731 247,899
Less: current maturities............. (899) (3,100)
-------- --------
Long-term debt........................ $156,832 $244,799
======== ========
Current maturities at December 31, 1996 include the annual amortization of
the Other Long-Term Debt. The 10-3/8% Senior Subordinated Notes are due 2005.
Maturities of long-term debt by calendar year are as follows (in thousands):
1997.................................. $ 899
1998.................................. 899
1999.................................. 899
2000.................................. 899
2001.................................. 899
Thereafter............................ 153,236
--------
$157,731
========
-32-
REVOLVING LOAN
At the beginning of 1996 the Credit Facility provided a borrowing base amount
of $190,000,000. On November 1, 1996, the borrowing base was increased to
$200,000,000.
The Credit Facility, which is with a group of commercial banks, currently
consists of two parts: (i) a credit facility among UMC, certain of its
subsidiaries and certain lenders (the U.S. Lenders) pursuant to which the U.S.
Lenders agree to make a portion of the Revolving Loan (subject to Borrowing Base
limitations) to UMC (Credit Facility) and (ii) a credit facility between UMC and
certain lenders (the Canadian Lenders) pursuant to which the Canadian Lenders
agree to make the remaining part of the Revolving Loan (subject to aggregate
Borrowing Base limitations under the Credit Facility and a specific Canadian
Borrowing Base sub-limit) to UMC (the Canadian Credit Facility). The amount of
the Borrowing Base, which governs the aggregate Revolving Loan jointly under
both the U.S. Credit Facility and the Canadian Credit Facility, and the sub-
limit on the portion of the Revolving Loan that will be made by the Canadian
Lenders, are both determined from time to time jointly by the U.S. Lenders and
the Canadian Lenders. The Company recently received commitments to expand the
Credit Facility to $300,000,000 with an initial borrowing base of $275,000,000.
The new Credit Facility should be in place by the end of March 1997.
The Revolving Loan has a term of seven years with amortization of the
Borrowing Base to begin in 1997, unless extended or modified by the Company and
the Lenders. At December 31, 1996, there were no outstanding borrowings.
During 1996, 1995 and 1994, the Credit Facility provided the Company with
various interest rate options based upon prime and LIBOR rates.
10-3/8% SENIOR SUBORDINATED NOTES
On October 30, 1995, the Company closed a public offering of $150,000,000 of
10-3/8% Senior Subordinated Notes (Notes) due 2005 at an initial price of 99.5%
of face value. Proceeds of $144,933,000 (after deducting underwriting discounts,
commission and expenses of the offering) were used to reduce debt under the
Revolving Loan. Interest is payable semiannually on April 15 and October 15 of
each year, commencing April 15, 1996. The Notes are general unsecured senior
obligations of the Company and are guaranteed by UMC Petroleum Corporation
(Petroleum) but are subordinate to the Revolving Loan (see Note 19). The Notes
are redeemable at the option of the Company, in whole or in part, at anytime
after October 15, 2000 at certain premiums to face value.
COTE d'IVOIRE PROJECT LOAN
In July 1995, a subsidiary of the Company entered into the Cote d'Ivoire
Facility with the International Finance Corporation (IFC) in connection with the
development of Block CI-11 offshore Cote d'Ivoire. As of December 31, 1995,
$35,000,000 was outstanding under the Cote d'Ivoire Facility and was fully
guaranteed by UMC and Petroleum. In November 1996, the Cote d'Ivoire Facility
was purchased by the Company paying off the IFC in full with a portion of the
proceeds of the November 1996 offering of common stock. As a result, in November
1996, unamortized debt issue costs of $607,000 were expensed.
UNSECURED NOTES
Unsecured notes payable in the amount of $1,850,000 were outstanding at
December 31, 1995. The notes were paid in full in August 1996.
OTHER LONG-TERM DEBT
Havre Pipeline Company LLC, a limited liability corporation in which the
Company had a 55% interest at December 31, 1996, has previously entered into a
Credit Agreement which provided a Term Loan due September 30, 2005. The
Company's proportionate share outstanding at December 31, 1996 is $7,731,000.
Principal installments are due at the end of each quarter. Additional principal
payments may be required under the Credit Agreement if operating cash flows of
the limited liability corporation exceed predetermined levels.
-33-
OTHER DISCLOSURES
During 1996, 1995 and 1994, $2,109,000, $1,049,000 and $321,000, respectively,
of total interest incurred was capitalized.
Effective January 18, 1994, UMC entered into five-year fixed LIBOR interest
rate swap contracts that provide for fixed interest rates to be realized on
notional amounts of $30,000,000 in 1994 and $45,000,000 from 1995 through 1998.
The agreement includes varying annual fixed interest rates ranging from 3.66% in
1994 to 6.40% in 1998, plus interest rate margins. Additionally, the Company
entered into a two-year LIBOR interest rate cap contract on an additional
notional amount of $45,000,000 for 1995 and 1996 at interest rate caps of 7.60%
and 8.30%, respectively, plus interest rate margins. Due to the November 1996
pay-down of amounts outstanding under the Credit Facility, the Company did not
have notional amounts of floating rate debt totalling $45,000,000 and therefore
could no longer apply hedge accounting. As such, a loss of $254,000 was
recorded as other expense in the 1996 Consolidated Statement of Income.
The Company's actual average interest rate for 1996, 1995 and 1994 was 9.17%,
7.47%, and 5.95%, respectively. Additionally, a facility fee of 0.25% to 0.375%
per annum on the unused portion of the Credit Facility is payable quarterly by
UMC.
NOTE 6 CAPITAL STOCK
COMMON STOCK
The authorized shares of Series A Voting Common Stock and Series B Nonvoting
Common Stock at December 31, 1996, and December 31, 1995, were 45,000,000 and
1,000,000, respectively. Of the 1,000,000 shares of Series B stock authorized,
none were outstanding at December 31, 1996 and 1995.
On June 11, 1993, the Company issued warrants to purchase 250,004 shares of
the Company's Common Stock in connection with the acquisition of KPX, Inc. The
exercise price of the warrants was $15.36 per share for a three year term ending
June 11, 1996. During 1996, proceeds of $3,621,000 for the exercise of warrants
were received and 235,749 shares of common stock were issued. The remaining
unexercised warrants expired in June 1996.
In connection with the GARI merger discussed in Note 4, the Company issued
5,018,944 new shares of UMC Common Stock pursuant to an Agreement and Plan of
Merger dated as of August 9, 1994 in exchange for the 4,562,662 remaining Common
Shares of GARI (1.1 shares of UMC Common Stock were issued for each remaining
share of GARI Common Stock). The value of this stock, based on UMC's closing
price on November 15, 1994, was $63,524,000.
On February 14, 1996, the Company granted one shareholder's right (Rights) for
each share of Series A Voting Common Stock to holders of record at the close of
business on February 29, 1996. The Rights will automatically become part of and
trade with existing and future shares of UMC's Series A Voting Common Stock.
The Rights will become exercisable only in the event, with certain exceptions,
an acquiring party accumulates 15% or more of UMC's voting stock, or if a party
announces an offer to acquire 30% or more of UMC's voting stock. No separate
right certificates will be issued until after these thresholds are met. The
Rights will expire on February 28, 2006. Each Right will entitle the holder,
other than the acquiring party, to purchase either United Meridian stock or
shares in an "acquiring entity" at a 50% discount to the then current market
value. The Company generally will be entitled to redeem the Rights at $0.01 per
Right at any time until the tenth day following the acquisition of a 15%
position in its voting stock.
During November 1996, the Company completed a November 1996 offering of
4,088,942 shares of the Company's Series A Voting Common Stock and received
$182,670,000 in proceeds after underwriting fees and offering expenses.
-34-
Series F CONVERTIBLE PREFERRED STOCK
In June and July 1995, the Company sold an aggregate $35,000,000 of Series F
Convertible Preferred Stock in a private placement to institutional investors.
The Series F Convertible Preferred Stock had an 8.75% cumulative dividend,
payable quarterly commencing on September 30, 1995. A total of 1,166,667
authorized shares were sold at $30 per share. On July 25, 1996, the Company
converted $35,000,000 of Series F Convertible Preferred Stock to 1,845,000
shares of common stock in accordance with the automatic conversion terms of the
original private offering. The conversion eliminates the 8.75% dividend on the
preferred stock. Had the conversion of the Series F Convertible Preferred Stock
occurred at January 1, 1996, the reported earnings per share would have been
$0.54 for the year ended December 31, 1996.
NOTE 7 INCOME TAXES
Under the provisions of SFAS 109 the components of the net deferred income tax
assets and liabilities recognized in the Company's Consolidated Balance Sheet at
December 31, 1996 and 1995, were as follows (in thousands):
1996 1995
-------------------------------------- ----------------------------------------
FEDERAL FOREIGN STATE TOTAL FEDERAL FOREIGN STATE TOTAL
-------- --------- ------- -------- --------- ---------- -------- --------
Deferred tax assets -
Net operating loss
carryforward................ $34,177 $ 13,115 $4,520 $51,812 $40,610 $ 5,338 $ 3,713 $49,661
Percentage depletion
carryforward................ 2,333 - 229 2,562 2,158 - 174 2,332
Investment tax credit
carryforward................ 1,720 - - 1,720 2,619 - - 2,619
Alternative minimum tax
credit carryforward......... 3,662 - - 3,662 3,276 - - 3,276
Deferred foreign tax
credit carryforward......... 3,790 - - 3,790 1,138 - - 1,138
Other......................... 50 - 4 54 891 - 51 942
Valuation allowance........... (3,551) - (151) (3,702) (4,257) - (79) (4,336)
------- -------- ------ ------- ------- -------- ------- -------
42,181 13,115 4,602 59,898 46,435 5,338 3,859 55,632
------- -------- ------ ------- ------- -------- ------- -------
Deferred tax liabilities -
Excess of basis in oil
and gas properties
for financial reporting
purposes over the tax
basis....................... 15,551 33,912 4,042 53,505 24,382 22,715 4,723 51,820
Other......................... 1,186 - 130 1,316 1,186 - 110 1,296
------- -------- ------ ------- ------- -------- ------- -------
16,737 33,912 4,172 54,821 25,568 22,715 4,833 53,116
------- -------- ------ ------- ------- -------- ------- -------
Net deferred tax asset
(liability)................... 25,444 (20,797) 430 5,077 20,867 (17,377) (974) 2,516
Current portion of deferred
tax assets classified as
current asset................. 2,836 - 3 2,839 3,727 - 148 3,875
------- -------- ------ ------- ------- -------- ------- -------
Total non-current deferred tax
asset (liability)............. $22,608 $(20,797) $ 427 $ 2,238 $17,140 $(17,377) $(1,122) $(1,359)
======= ======== ====== ======= ======= ======== ======= =======
As of December 31, 1996 and 1995, the Company and its subsidiaries had U.S.
federal net operating loss (NOL) carryforwards of approximately $98,000,000 and
$116,000,000, respectively, and Equatorial Guinea NOL carryforwards of
approximately $52,000,000 and $21,000,000, respectively. The Company's Canadian
subsidiary also had $17,600,000 and $21,900,000 in Canadian Tax Pool
carryforwards as of December 31, 1996 and 1995, respectively.
The Company is subject to taxation under the laws of Cote d'Ivoire and
Equatorial Guinea. Income taxes in these jurisdictions will be taken as a
credit or deduction against the Company's United States tax liability.
-35-
Management believes the Company will realize the benefit of all NOLs. The
Company has recognized a deferred tax asset relating to these carryforwards.
The U.S. federal NOLs expire as follows (in thousands):
1997................... $ 8,000
1998................... 5,000
1999................... 1,000
2000................... 24,000
2001................... 16,000
2002................... 6,000
2003................... 1,000
2004................... 19,000
Beyond 2004............ 18,000
-------
$98,000
=======
For federal income tax purposes, certain limitations are imposed on an
entity's ability to utilize its NOLs in future periods if a "change of control",
as defined for federal income tax purposes, has taken place. In general terms,
the limitation on utilization of NOLs and other tax attributes during any one
year is determined by the value of an acquired entity at the date of the "change
of control" multiplied by the then-existing long-term, tax-exempt interest rate.
The manner of determining an acquired entity's "value" has not yet been
addressed by the Internal Revenue Service. The Company has determined that, for
federal income tax purposes, a "change of control" occurred in 1994 as a result
of the stock purchases made by the Company's shareholders in 1994 and in
previous years, and future utilization of NOLs will be limited in the manner
described above. The use of NOLs acquired as a result of corporate acquisitions
prior to 1994 were already subject to limitations computed at the time of each
acquisition. While the effect of such limitations may be to defer the use of
existing NOL carryforwards, the Company does not believe such limitations will
impact the Company's ability to fully utilize the NOLs.
As of December 31, 1996 and 1995, the Company and its subsidiaries had
investment tax credit carryforwards of approximately $1,700,000 and $2,600,000,
respectively. To the extent not utilized, these carryforwards will expire in
the years 1997 through 2001. For purposes of computing the net deferred tax
liability as of December 31, 1996 and 1995, none of these carryforwards were
utilized.
The components of the Income Tax Provision (Benefit) recognized in the
Consolidated Statement of Income are as follows (in thousands):
1996 1995 1994
-------- -------- --------
CURRENT TAXES-
Federal ............................. $ 455 $ 340 $ (323)
Foreign ............................. 98 (370) 409
State ............................... 232 362 (61)
-------- -------- --------
785 332 25
-------- -------- --------
DERERRED TAXES-
Federal ............................. 3,136 (2,762) (38,251)
Foreign ............................. 3,496 (339) 1,157
State ............................... (1,401) (1,116) (4,455)
-------- -------- --------
5,231 (4,217) (41,549)
-------- -------- --------
TOTAL INCOME TAX PROVISION (BENEFIT) .. $ 6,016 $ (3,885) $(41,524)
======== ======== ========
-36-
The following is a reconciliation of the income tax provision (benefit)
computed by applying the federal statutory income tax rate to net income (loss)
before income taxes to the Income Tax Provision (Benefit) shown in the
Consolidated Statement of Income (in thousands):
1996 1995 1994
--------- -------- --------
Income tax provision (benefit)
computed at the federal
statutory rate of 35% ............ $ 8,197 $ (625) $(42,880)
State and local taxes (net of
federal effect) .................. (760) (490) (2,935)
Tax effect of:
Provision (benefit) for net
book deductions not available
for tax due to differences in
book/tax basis ................. 1,169 (927) 9,486
Excess of taxes on foreign income
over fedral statutory rate ..... 291 165 381
Benefit resulting from adjustments
from estimate to actual in
estimating taxable income ...... (2,139) (181) (6,227)
Benefit of deferred foreign tax
credit carryforward ............ - (1,138) -
Alternative minimum tax credit
carryforward provision
(benefit) ...................... (193) (321) 141
Other ............................ (549) (368) 510
--------- -------- --------
$ 6,016 $ (3,885) $(41,524)
========= ======== ========
NOTE 8 EMPLOYEE BENEFIT PLANS
STOCK OPTION PLANS
At December 31, 1996, UMC had three non-qualified stock option plans:
AUTHORIZED SHARES
-----------------
1987 Employee Plan ............. 1,555,625
1994 Employee Plan ............. 2,850,000
1994 Outside Directors Plan .... 250,000
---------
4,655,625
=========
The two 1994 plans were approved by the shareholders of the Company on
May 17, 1994. The 1994 Employee Plan was amended on November 15, 1994 and
May 22, 1996 by the shareholders to increase authorized shares by 1,500,000
shares and 500,000 shares, respectively. The 1994 Outside Director's Plan was
amended on May 22, 1996 by the shareholders to increase authorized shares by
100,000.
The plans provide that directors, officers and key employees may be awarded
options to purchase Common Stock of the Company at a price equal to the market
value of UMC Common Stock on the award date. Options generally vest over a
five-year period. The following table reflects summarized information about
stock options outstanding at December 31, 1996:
Options Outstanding Options Exercisable
-------------------- -------------------------
Weighted Avg
Number Remaining Weighted Avg Number Weighted Avg
Range of Outstanding Contractual Exercise Exercisable Exercise
Exercise Price at 12/31/96 Life (in years) Price at 12/31/96 Price
- ------------------- ----------- -------------------- ------------ ----------- ------------
$2.75 to $6.64 331,247 4.3 $ 4.80 326,014 $ 4.77
$9.875 to $15.50 1,794,934 5.5 11.87 1,018,960 10.62
$16.75 to $23.875 387,000 10.2 23.36 2,500 17.88
$29.50 to $30.50 38,000 10.3 29.63 - -
$44.125 to $47.50 257,000 10.8 44.19 125,000 44.13
--------- ---------
2,808,181 1,472,474
========= =========
-37-
Options that had been granted by GARI to its directors, officers and employees
that were outstanding on November 15, 1994 were converted to UMC stock options
at the ratio of 1.1 UMC shares for each GARI share. Options that had vested
under the GARI option plan were converted as vested options under the UMC plan.
The total new option shares of UMC resulting from the GARI conversion were
1,427,940.
A summary of actual options granted and exercised follows:
1996 1995 1994
-------- -------- --------
Option shares outstanding -
Beginning of year 3,148,612 3,185,065 1,647,500
Granted 683,000 446,000 1,711,940
Exercised (897,999) (428,354) (144,375)
Canceled (125,432) (54,099) (30,000)
--------- --------- ---------
End of year 2,808,181 3,148,612 3,185,065
========= ========= =========
Shares available for grant at
end of year 521,091 478,659 870,560
Shares exercisable at end of year 1,472,474 2,070,664 2,205,047
Average price of options exercised
during the year $ 7.88 $ 6.69 $ 9.96
Average exercise price of options
outstanding at end of year $ 15.82 $ 10.05 $ 9.20
Weighted average fair value of
options granted during the year $ 16.93 $ 7.33 -
Weighted average exercise price for
options granted during the year $ 31.64 $ 13.47 -
The Company accounts for these plans under APB Opinion No. 25, Accounting for
Stock Issued to Employees, under which no compensation cost has been recognized.
Had compensation cost for these plans been determined consistent with SFAS 123,
Accounting for Stock-Based Compensation, the Company's reported net income and
earnings per share would have been adjusted to the following proforma amounts
(in thousands, except per share amounts):
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------
1996 1995
--------- --------
Net Income: As Reported $17,404 $2,099
Pro Forma $14,487 $1,769
Primary EPS: As Reported $ 0.51 $ 0.02
Pro Forma $ 0.43 $ 0.01
Fully Diluted EPS: As Reported $ 0.50 $ 0.02
Pro Forma $ 0.43 $ 0.01
Because SFAS 123 has not been applied to options granted prior to
January 1, 1995, the resulting proforma compensation cost may not be
representative of that expected in future years. The fair value of each option
granted since January 1, 1995 is estimated on the date of grant using the Black-
Scholes option pricing model, with the following assumptions used for grants in
1996 and 1995, respectively; risk-free interest rates of 5.40% to 6.76% and
6.14% to 7.13%; expected dividend yields of 0% and 0%; expected lives of 6.5
years and 6.5 years; and, expected volatility of 39.34% to 43.14% and 44.70% to
45.53%.
-38-
SAVINGS PLAN
The Company maintains a defined contribution savings plan for the benefit of
its U.S. employees. Under the Plan, employees may contribute up to 16% of their
base salary to a trust for investments (including UMC stock) selected by each
participating employee. The Company makes a 75% matching contribution up to a
maximum of 8% of each participant's qualified salary, resulting in a maximum
Company contribution of 6% of salary as a result of an amendment to the Plan,
effective January 1, 1994. The Plan was also amended to provide for the
inclusion of total compensation paid during the year as qualified salary for
purposes of making contributions and computing matching contributions.
During 1996, 1995 and 1994, the Company made contributions to the Plan on
behalf of all participants totaling $780,000, $696,000, and $434,000,
respectively.
Resources maintains a separate group savings plan for its employees. During
1996, 1995 and 1994, this subsidiary contributed $67,000, $63,000, and $62,000,
respectively, to the Plan for the benefit of its employees.
NOTE 9 COMMITMENTS AND CONTINGENCIES
The Company has entered into operating leases for office space and equipment
for which $1,174,000, $1,547,000 and $1,399,000 in rental expense has been
included in the accompanying financial statements for the years ended December
31, 1996, 1995 and 1994, respectively. Future minimum rental payments required
for the years ending December 31, 1997 through 2001 are $1,416,000, $1,411,000,
$1,391,000, $1,148,000 and $1,166,000, respectively.
Resources has an agreement with Nova Corporation, a natural gas pipeline
company, to transport specified quantities of natural gas. Future minimum
transportation expense payments required for years ending December 31, 1997 and
1998 are $314,000 and $166,000, respectively.
The Company has entered into agreements for transportation of natural gas
across Canada for sales to the Great Lakes region for up to 35 MMCFD expiring at
various dates through 2002 and has applied for an additional 8 MMCFD of ten year
firm transport capacity beginning in November 1997. Future minimum
transportation expense payments required are $5,296,000 and $5,930,000 per annum
for years ending December 31, 1997 and 1998, respectively.
NOTE 10 OIL AND GAS PROPERTY COSTS
Capitalized costs at December 31, 1996 and 1995 relating to the
Company's oil and gas activities are shown below (in thousands):
EQUATORIAL
GUINEA
UNITED COTE AND OTHER
STATES CANADA d'IVOIRE FOREIGN TOTAL
-------- ------- -------- ---------- --------
AS OF DECEMBER 31, 1996
Proved properties.......... $590,879 $92,545 $72,590 $95,804 $851,818
Unproved oil and gas
interests................. 12,656 50 1,072 889 14,667
-------- ------- ------- ------- --------
Total capitalized costs.. 603,535 92,595 73,662 96,693 866,485
Less: Accumulated
depreciation,
depletion and
amortization............ 309,401 25,792 7,006 2,884 345,083
-------- ------- ------- ------- --------
Net capitalized costs.... $294,134 $66,803 $66,656 $93,809 $521,402
======== ======= ======= ======= ========
AS OF DECEMBER 31, 1995
Proved properties.......... $581,566 $96,198 $55,743 $26,188 $759,695
Unproved oil and gas
interests................. 10,815 50 1,072 432 12,369
-------- ------- ------- ------- --------
Total 592,381 96,248 56,815 26,620 772,064
Less: Accumulated
depreciation,
depletion and
amortization............ 280,834 22,858 1,384 - 305,076
-------- ------- ------- ------- --------
Net capitalized costs.... $311,547 $73,390 $55,431 $26,620 $466,988
======== ======= ======= ======= ========
-39-
Costs incurred during 1996, 1995 and 1994 in the Company's oil and gas
activities were as follows (in thousands):
EQUATORIAL
GUINEA
UNITED COTE AND OTHER
STATES CANADA d'IVOIRE FOREIGN TOTAL
-------- ------- -------- --------- --------
YEAR ENDED DECEMBER 31, 1996
Property acquisition costs:
Proved....................... $ 6,239 $ 447 $ - $ - $ 6,686
Unproved..................... 4,277 865 - 457 5,599
Exploration costs............. 28,943 2,370 9,219 30,882 71,414
Development costs............. 36,057 4,572 9,369 56,707 106,705
-------- ------- ------- ------- --------
Total costs incurred......... $ 75,516 $ 8,254 $18,588 $88,046 $190,404
======== ======= ======= ======= ========
YEAR ENDED DECEMBER 31, 1995
Property acquisition costs:
Proved....................... $ 24,819 $ 376 $ - $ - $ 25,195
Unproved..................... 3,032 311 - - 3,343
Exploration costs............. 21,561 1,599 2,912 11,948 38,020
Development costs............. 31,252 2,519 42,900 19,798 96,469
-------- ------- ------- ------- --------
Total costs incurred......... $ 80,664 $ 4,805 $45,812 $31,746 $163,027
======== ======= ======= ======= ========
YEAR ENDED DECEMBER 31, 1994
Property acquisition costs:
Proved....................... $ 131 $ 667 $ - $ - $ 798
Unproved..................... 1,966 118 - - 2,084
Corporate acquisition costs:
Purchase price............... 184,425 20,520 - - 204,945
Deferred taxes............... 31,784 3,224 - - 35,008
Exploration costs............. 10,424 2,369 899 3,522 17,214
Development costs............. 18,898 5,014 7,598 - 31,510
-------- ------- ------- ------- --------
Total costs incurred......... $247,628 $31,912 $ 8,497 $ 3,522 $291,559
======== ======= ======= ======= ========
NOTE 11 RELATED PARTY TRANSACTIONS
UMC currently conducts a portion of its oil and gas activities in conjunction
with a group of institutional and corporate investors that participate in UMC's
acquisition, development and exploration programs, and provide the Company with
certain carried interests and management fees. Management fee income of
$1,826,000 and $1,286,000, related to the year ended December 31, 1996 and 1995,
respectively, is included in the Consolidated Statement of Income.
UMC is participating with Aspect Resources Limited-Liability Company (Aspect),
a company controlled by a former director of UMC, as co-venturers in the
generation of certain oil and gas exploration prospects. The activities
regarding this venture in 1994 and 1995 were negligible. UMC and Aspect are also
each 40% owners of Energy Arrow Exploration L.L.C. (Arrow), whose purpose is
also the generation of oil and gas exploration prospects. UMC and Aspect each
reimburse Arrow for a portion of its monthly general and administrative expenses
and prospect acquisition costs. In 1994, UMC paid Arrow $75,000 for general and
administrative costs and $226,000 for prospect acquisition costs. Total
payments to Arrow in 1996 and 1995 were $5,309,000 and $2,477,000, respectively,
most of which related to lease acquisitions, seismic and drilling costs. In
July 1996, UMC was named Manager of Arrow and assumed responsibilities for its
operations.
In late 1995, UMC executed separate farm-out agreements with Aspect and MB
Exploration LLC (MB) (a 20% owner of Arrow) whereby UMC acquired additional 10%
and 5% working interests from Aspect and MB, respectively, in two outside-
operated wells. During 1996, one of the wells was completed and the other was
plugged and abandoned.
-40-
A substitute well is being drilled by another operator and if that well is
completed, Aspect and MB will revert to a 5% and 2.5% working interest,
respectively, in the replacement well.
UMC also conducts joint interest operations with Brigham Oil & Gas LP
(Brigham), a partnership owned in part by General Atlantic Partners LLC for
which Steven Denning, a director of UMC, acts as Executive Managing Member.
Total payments to Brigham for the operation of jointly owned properties operated
by Brigham during 1996, 1995 and 1994 were $430,000, $75,000, and $1,240,000,
respectively. UMC billings to Brigham for the operation of jointly owned
properties operated by UMC during 1996, 1995 and 1994 were $286,000, $596,000,
and $930,000, respectively. UMC's receivable from Brigham was $397,000 and
payables to Brigham were less than $100,000 at December 31, 1996. At December
31, 1995, the Company's receivables and payables from/to Brigham were each less
than $100,000.
In 1996, UMC executed agreements with Xpronet regarding a co-venture in
Pakistan and possible other international exploration opportunities. Xpronet
is controlled by Ralph Bailey and Khalid Alireza, former directors of UMC.
Also, in 1996, UMC executed an agreement with Xenel Industries regarding a co-
venture in Bangladesh and possible other international exploration
opportunities. Xenel Industries is controlled by Mr. Alireza.
All transactions with the aforementioned entities are under normal industry
terms and conditions.
NOTE 12 LITIGATION
The Company is a named defendant in lawsuits and is a party in governmental
proceedings from time to time arising in the ordinary course of business. While
the outcome of such lawsuits or other proceedings against the Company cannot be
predicted with certainty, management does not expect these matters to have a
material adverse effect on the financial position or results of operations of
the Company.
NOTE 13 MAJOR CUSTOMERS
The Company markets its oil and gas production to numerous purchasers under a
combination of short and long-term contracts. During 1996, 1995 and 1994,
Northern Natural Gas Company, a subsidiary of Enron Corporation, accounted for
0.9%, 9.0%, and 10.7%, respectively, of oil and gas revenues of the Company. In
addition, during 1996, Mobil Sales and Supply Corporation and H&N Gas Limited,
Inc. accounted for 10.4% and 15.5%, respectively, of the Company's oil and gas
revenues. Sales to H&N Gas Limited, Inc. are backed by an irrevocable standby
letter of credit. The Company had no other purchasers that accounted for
greater than 10.0% of its oil and gas revenues. The Company believes that the
loss of any single customer would not have a material adverse effect on the
results of operations of the Company.
NOTE 14 GAS CONTRACT SETTLEMENTS
From time to time, the Company has had disagreements with certain purchasers
of the Company's natural gas production concerning the contractual obligations
of such purchasers to take specified quantities of gas at contract prices. In
order to resolve such disagreements, the Company has entered into gas contract
settlements, wherein, for a nonrefundable cash payment, the Company has released
the purchaser from its contractual obligations and, in some cases, the contract
itself. During 1996, 1995 and 1994, contract settlements of $266,000,
$1,872,000, and $1,981,000, respectively, were included in revenues.
NOTE 15 CREDIT RISK AND PRICE PROTECTION AGREEMENTS
TRADE RECEIVABLES AND PAYABLES
Substantially all of the Company's accounts receivable at December 31, 1996,
result from oil and gas sales and joint interest billings to other companies in
the oil and gas industry and institutional partners. This concentration of
customers and joint interest owners may impact the Company's overall credit
risk, either positively or negatively, in that these entities may be similarly
affected by industry-wide changes in economic or other conditions. Such
receivables are generally not collateralized. Credit losses incurred by the
Company on receivables generally have not been significant in prior years.
-41-
OIL AND GAS MARKET HEDGE
The Company's revenues are primarily the result of sales of its oil and
natural gas production. Market prices of oil and natural gas may fluctuate and
adversely affect operating results. To mitigate this risk, the Company has,
from time to time, entered into crude oil and natural gas price hedging
contracts to reduce its exposure to price reductions on its production. These
transactions have been entered into with major financial institutions, thereby
minimizing credit risk. The Company hedged a portion of its natural gas and oil
production in 1996, 1995 and 1994, the results of which were included in natural
gas or oil revenues.
At December 31, 1996, the Company had oil collar contracts on 200,000 barrels
of oil per month for January 1997 through June 1997, with a "floor" price of
$21.00 and an average "cap" price of $24.69. If the index price is between the
floor and cap, UMC and third parties owe nothing and if the index price is below
the floor, UMC receives the difference. If the index price is higher than the
cap, UMC pays the difference. UMC's current hedging agreements are settled on a
monthly basis. All of UMC's current contracts specify the third-party index to
be the New York Mercantile Exchange (NYMEX) futures contract prices for the
applicable commodity, matching the appropriate basis risk. There was no deferred
hedge gain or loss for crude oil at year end 1996.
INTEREST RATE MARKET HEDGE
UMC has interest rate hedge contracts currently outstanding. The hedge
transactions have been entered into with major financial institutions,
minimizing credit risk associated with these agreements. See Note 5 for further
discussion of these contracts.
NOTE 16 FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company's financial instruments consist of cash and cash equivalents,
short-term trade receivables and payables, long-term debt, interest rate hedging
agreements and natural gas and crude oil hedging agreements. As of December 31,
1996 and 1995, the fair market values of the Company's financial instruments are
shown below:
CASH, TRADE RECEIVABLES AND PAYABLES: The carrying amount approximates fair
market value due to the highly liquid nature of these short-term instruments.
LONG-TERM DEBT: As of December 31, 1996, the carrying amount of the Notes was
$150,000,000 and the fair value was $163,875,000. The fair value was estimated
based on the market price of the publicly traded Notes. As of December 31, 1995,
the carrying amount of the Company's long-term debt approximates fair value due
to (i) the nature of UMC's Senior Revolver Credit Facility, whereby the interest
rates offered by the member banks are floating rates which reflect market rate
and (ii) the Notes issuance on October 30, 1995.
INTEREST RATE HEDGING AGREEMENTS: The fair market value of the interest rate
swap contracts at December 31, 1996 and 1995 was ($254,000) and ($838,000),
respectively. The fair market value at December 31, 1996 and 1995 was
determined by the institutional holders of the hedges.
NATURAL GAS AND CRUDE OIL HEDGING AGREEMENTS: The fair market value of the
natural gas and crude oil swap contracts at December 31, 1996 and 1995
approximate ($942,000) and ($305,000), respectively, as determined by the
institutional holders of the hedges.
-42-
NOTE 17 GEOGRAPHIC DATA
UMC is an independent oil and gas company engaged in the acquisition,
development and exploration of oil and natural gas properties. Information
about the Company's operations by geographic area for the years ended December
31, 1996, 1995, and 1994 is as follows (in thousands):
EQUATORIAL
GUINEA
UNITED AND OTHER
STATES CANADA COTE d'IVOIRE INTERNATIONAL TOTAL
---------- -------- ------------- ------------- ----------
YEAR ENDED DECEMBER 31, 1996
Revenues..................... $ 150,248 $ 23,011 $ 25,940 $37,205 $ 236,404
Depreciation, depletion
and amortization........... $ 66,832 $ 9,482 $ 5,689 $ 2,976 $ 84,979
Operating profit............. $ 14,516 $ 4,318 $ 13,243 $14,998 $ 47,075
Capital expenditures......... $ 75,516 $ 8,254 $ 18,588 $88,046 $ 190,404
Identifiable assets.......... $ 586,410 $ 65,167 $ 21,279 $45,437 $ 718,293
YEAR ENDED DECEMBER 31, 1995
Revenues..................... $ 107,112 $ 16,922 $ 7,106 $15,901 $ 147,041
Depreciation, depletion
and amortization............ $ 44,265 $ 8,208 $ 1,420 $ 49 $ 53,942
Impairment of proved oil
and gas properties.......... $ 8,317 - - - $ 8,317
Operating profit (loss)...... $ 2,269 $ (125) $ 502 $13,138 $ 15,784
Capital expenditures......... $ 80,664 $ 4,805 $ 45,812 $31,746 $ 163,027
Identifiable assets.......... $ 392,490 $ 80,151 $ 77,875 $27,934 $ 578,450
YEAR ENDED DECEMBER 31, 1994
Revenues..................... $ 81,339 $ 16,478 - - $ 97,817
Depreciation, depletion
and amortization............ $ 44,759 $ 5,968 - - $ 50,727
Impairment of proved oil
and gas properties.......... $ 94,793 - - - $ 94,793
Operating loss............... $(110,895) $ (2,437) - - $(113,332)
Capital expenditures/(1)/.... $ 216,262 $ 28,689 $ 8,497 $ 3,522 $ 256,970
Identifiable assets.......... $ 401,421 $ 85,407 $ 23,020 $ 1,366 $ 511,214
- ----------------
/(1)/ Total includes Corporate Acquisitions of $204,945.
-43-
NOTE 18 DISCLOSURES OF OIL AND GAS OPERATIONS (UNAUDITED)
PROVED RESERVES
Substantially all reserve estimates presented herein were prepared by either
Ryder Scott Company, Netherland, Sewell & Associates, Inc., or McDaniel &
Associates Consultants Ltd., independent petroleum engineers. The Company
cautions that there are many uncertainties inherent in estimating proved reserve
quantities, and in projecting future production rates and the timing of future
development expenditures. In addition, reserve estimates of new discoveries are
more imprecise than those of properties with a production history. Accordingly,
these estimates are subject to change as additional information becomes
available.
Proved oil and gas reserves are the estimated quantities of crude oil,
condensate, natural gas and natural gas liquids that geological and engineering
data demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions. Proved
developed oil and gas reserves are those reserves expected to be recovered
through existing wells with existing equipment and operating methods.
Information presented for the Company's international locations relates to
contract interests held in multiple production sharing contracts between the
Company, its joint venture partners and the governments of Cote d'Ivoire and
Equatorial Guinea. The Company has no ownership interest in the oil and gas
reserves but does have the right to share revenues and/or production and is
entitled to recover most field and other operating costs. The reserve estimates
are subject to revision as prices fluctuate due to the cost recovery feature
under the production sharing contract.
Net quantities of proved reserves and proved developed reserves of crude oil
(including condensate and natural gas liquids) and natural gas, as well as the
changes in proved reserves during the periods indicated, are set forth in the
tables below:
IN THOUSANDS
---------------------------------------------------------------------------
UNITED COTE EQUATORIAL
STATES CANADA d'IVOIRE GUINEA TOTAL
----------- ----------- ------------- --------------- -----------
NATURAL GAS (MCF)
PROVED:
December 31, 1993.............................. 276,791 64,052 - - 340,843
Revisions of previous estimates............... (463) (6,310) - - (6,773)
Extensions, discoveries and other additions... 16,956 76 32,612 - 49,644
Purchases..................................... 84,409 14,508 - - 98,917
Sales of reserves-in-place.................... (3,546) (4) - - (3,550)
Production.................................... (35,182) (4,487) - - (39,669)
--------- --------- --------- --------- ---------
December 31, 1994.............................. 338,965 67,835 32,612 - 439,412
Revisions of previous estimates............... 4,655 (1,060) 5,746 - 9,341
Extensions, discoveries and other additions... 35,558 2,060 58,290 - 95,908
Purchases..................................... 21,839 - - - 21,839
Sales of reserves-in-place.................... (68,113) (1,014) (13,995) - (83,122)
Production.................................... (38,878) (5,383) (192) - (44,453)
--------- --------- --------- --------- ---------
December 31, 1995.............................. 294,026 62,438 82,461 - 438,925
Revisions of previous estimates............... 19,705 (3,764) 7,848 - 23,789
Extensions, discoveries and other additions... 22,900 8,567 2,488 - 33,955
Purchases..................................... 17,869 894 - - 18,763
Sales of reserves-in-place.................... (9,249) (15) - - (9,264)
Production.................................... (47,719) (5,339) (2,387) - (55,445)
--------- --------- --------- --------- ---------
December 31, 1996.............................. 297,532 62,781 90,410 - 450,723
========= ========= ========= ========= =========
PROVED DEVELOPED:
December 31, 1994.............................. 256,348 66,997 - - 323,345
========= ========= ========= ========= =========
December 31, 1995.............................. 245,860 62,438 21,722 - 330,020
========= ========= ========= ========= =========
December 31, 1996.............................. 245,847 62,781 21,433 - 330,061
========= ========= ========= ========= =========
-44-
IN THOUSANDS
-----------------------------------------------------------------
UNITED COTE EQUATORIAL
STATES CANADA d'IVOIRE GUINEA TOTAL
---------- ------------ ------------ ------------- ----------
CRUDE OIL (BBLS)
PROVED:
December 31, 1993.................................. 5,037 5,535 - - 10,572
Revisions of previous estimates................... 609 (712) - - (103)
Extensions, discoveries and other additions....... 262 391 4,626 - 5,279
Purchases......................................... 8,455 980 - - 9,435
Sales of reserves-in-place........................ (725) (13) - - (738)
Production........................................ (1,160) (618) - - (1,778)
--------- --------- --------- --------- ---------
December 31, 1994.................................. 12,478 5,563 4,626 - 22,667
Revisions of previous estimates................... 1,099 (201) 1,905 - 2,803
Extensions, discoveries and other additions....... 801 151 1,440 5,258 7,650
Purchases......................................... 4,757 - - - 4,757
Sales of reserves-in-place........................ (762) (82) (332) (1,502) (2,678)
Production........................................ (1,826) (649) (285) - (2,760)
--------- --------- --------- --------- ---------
December 31, 1995.................................. 16,547 4,782 7,354 3,756 32,439
Revisions of previous estimates................... 2,805 (297) (2,538) 1,564 1,534
Extensions, discoveries and other additions....... 101 530 228 15,587 16,446
Purchases......................................... 100 4 - - 104
Sales of reserves-in-place........................ (590) (1,009) - - (1,599)
Production........................................ (2,022) (511) (894) (967) (4,394)
--------- --------- --------- --------- ---------
December 31, 1996.................................. 16,941 3,499 4,150 19,940 44,530
========= ========= ========= ========= =========
PROVED DEVELOPED:
December 31, 1994.................................. 11,109 5,531 - - 16,640
========= ========= ========= ========= =========
December 31, 1995.................................. 14,967 4,735 3,302 - 23,004
========= ========= ========= ========= =========
December 31, 1996.................................. 14,801 3,499 1,926 4,353 24,579
========= ========= ========= ========= =========
-45-
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
The following table sets forth the standardized measure of the discounted
future net cash flows attributable to the Company's proved oil and gas reserves.
Future cash inflows were computed by applying year-end prices of oil and gas to
the estimated future production of proved oil and gas reserves. Gas prices were
escalated only where existing contracts contained fixed and determinable
escalation clauses. Contractually provided gas prices in excess of estimated
market clearing prices were used in computing the future cash inflows only if
the Company expects to continue to receive higher prices under legally
enforceable contract terms. Future prices actually received may differ from the
estimates in the standardized measure.
Future production and development costs represent the estimated future
expenditures (based on current costs) to be incurred in developing and producing
the proved reserves, assuming continuation of existing economic conditions.
Future income tax expenses were computed by applying statutory income tax rates
to the difference between pre-tax net cash flows relating to the Company's
proved oil and gas reserves and the tax basis of proved oil and gas properties.
In addition, the effects of statutory depletion in excess of tax basis,
available net operating loss carryforwards and investment tax credit
carryforwards were used in computing future income tax expense. The resulting
annual net cash inflows were then discounted using a 10% annual rate.
IN THOUSANDS
-----------------------------------------------------------------------------------------
UNITED COTE EQUATORIAL
STATES CANADA d'IVOIRE GUINEA TOTAL/(2)(3)/
----------- ------------ ----------- ----------- ------------
AT DECEMBER 31, 1996
Future cash inflows..................... $1,445,872 $206,041 $305,988 $450,785 $2,408,686
---------- -------- -------- -------- ----------
Future production costs................. 379,096 55,993 53,927 102,275 591,291
Future development costs................ 53,067 4,501 74,957 152,780 285,305
Future income taxes..................... 221,053 44,263 45,833 49,782 360,931
---------- -------- -------- -------- ----------
Total future costs..................... 653,216 104,757 174,717 304,837 1,237,527
---------- -------- -------- -------- ----------
Future net cash inflows................. 792,656 101,284 131,271 145,948 1,171,159
Discount at 10% per annum............... (253,431) (42,431) (40,465) (40,810) (377,137)
---------- -------- -------- -------- ----------
Standardized measure of discounted
future net cash flows.................. $ 539,225 $ 58,853 $ 90,806 $105,138 $ 794,022
========== ======== ======== ======== ==========
AT DECEMBER 31, 1995
Future cash inflows..................... $ 821,122 $157,548 $317,580 $ 65,789 $1,362,039
---------- -------- -------- -------- ----------
Future production costs................. 268,790 65,859 59,307 26,625 420,581
Future development costs................ 35,782 5,337 103,538 16,250 160,907
Future income taxes..................... 50,573 19,448 37,232 7,562 114,815
---------- -------- -------- -------- ----------
Total future costs..................... 355,145 90,644 200,077 50,437 696,303
---------- -------- -------- -------- ----------
Future net cash inflows................. 465,977 66,904 117,503 15,352 665,736
Discount at 10% per annum............... (133,051) (24,011) (43,215) (1,458) (201,735)
---------- -------- -------- -------- ----------
Standardized measure of discounted
future net cash flows.................. $ 332,926 $ 42,893 $ 74,288 $ 13,894 $ 464,001
========== ======== ======== ======== ==========
AT DECEMBER 31, 1994/(1)/
Future cash inflows..................... $ 727,738 $167,486 $128,401 $ - $1,023,625
---------- -------- -------- -------- ----------
Future production costs................. 259,826 73,670 19,070 - 352,566
Future development costs................ 68,739 5,641 56,131 - 130,511
Future income taxes..................... 16,656 18,692 16,203 - 51,551
---------- -------- -------- -------- ----------
Total future costs..................... 345,221 98,003 91,404 - 534,628
---------- -------- -------- -------- ----------
Future net cash inflows................. 382,517 69,483 36,997 - 488,997
Discount at 10% per annum............... (142,214) (24,872) (18,601) - (185,687)
---------- -------- -------- -------- ----------
Standardized measure of discounted
future net cash flows.................. $ 240,303 $ 44,611 $ 18,396 $ - $ 303,310
========== ======== ======== ======== ==========
- --------------
/(1)/ Included in the United States and Total columns at December 31, 1994 are
future net cash inflows of $132,297,000, future production costs of
$43,522,000 and future development costs of $15,241,000, from Appalachia
properties which were sold in February 1995.
/(2)/ Total future net cash flows before income taxes are $1,532,090,000,
$780,551,000 and $540,548,000 as of December 31, 1996, 1995 and 1994,
respectively.
/(3)/ Total future net cash flows before income taxes discounted at 10% per
annum are $966,895,000, $505,153,000 and $318,416,000 as of
December 31, 1996, 1995 and 1994, respectively.
-46-
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
The following are the principal sources of change in the standardized measure
of discounted future net cash flows (in thousands):
1996 1995 1994
---------- ---------- ---------
Beginning balance....................................... $ 464,001 $303,310 $ 300,550
--------- -------- ---------
Revisions to reserves proved in prior years -
Net changes in prices and production costs............ 304,349 58,564 (115,800)
Net changes due to revisions in quantity estimates.... 53,235 24,357 (2,818)
Net changes in estimated future development costs..... 9,245 59,821 (705)
Accretion of discount................................. 50,495 32,247 32,357
Changes in production rates (timing) and other........ (40,147) (10,462) (8,145)
--------- -------- ---------
Total revisions................................... 377,177 164,527 (95,111)
New field discoveries and extensions, net of future
production and development costs...................... 222,271 93,643 39,874
Purchases of reserves in-place.......................... 29,871 38,631 112,508
Sale of reserves in-place............................... (13,560) (46,410) (5,458)
Sales of oil and gas produced, net of production costs.. (155,231) (69,918) (56,966)
Net change in income taxes.............................. (130,507) (19,782) 7,913
--------- -------- ---------
Net change in standardized measure of discounted
future net cash flows............................... 330,021 160,691 2,760
--------- -------- ---------
Ending balance.......................................... $ 794,022 $464,001 $ 303,310
========= ======== =========
-47-
SUPPLEMENTAL OIL AND GAS DISCLOSURES
The following table sets forth revenue and direct cost information relating to
the Company's oil and gas exploration and production activities (in thousands).
UMC has no long-term supply or purchase agreements with governments or
authorities in which it acts as producer.
1996 1995 1994
---- ---- ----
UNITED STATES
Oil and gas revenues.................................................... $144,804 $ 91,541 $ 77,981
-------- -------- --------
Operating costs:
Production cost........................................................ 36,990 34,028 31,722
Exploration, including dry holes and leasehold impairments............. 21,112 10,852 8,870
Depreciation, depletion and amortization............................... 66,832 44,265 44,759
Impairment of oil and gas property..................................... - 8,317 94,793
Income tax provision (benefit)......................................... 7,551 (2,250) (38,822)
-------- -------- --------
132,485 95,212 141,322
-------- -------- --------
Results of operations.................................................. $ 12,319 $ (3,671) $(63,341)
======== ======== ========
COTE d'IVOIRE
Oil and gas revenues.................................................... $ 22,680 $ 4,729 $ -
-------- -------- --------
Operating costs:
Production cost........................................................ 5,370 3,388 -
Exploration, including dry holes and leasehold impairments............. 1,638 900 939
Depreciation, depletion and amortization............................... 5,689 1,469 -
Income tax provision (benefit)......................................... 3,794 (391) (357)
-------- -------- --------
16,491 5,366 582
-------- -------- --------
Results of operations.................................................. $ 6,189 $ (637) $ (582)
======== ======== ========
EQUATORIAL GUINEA AND OTHER FOREIGN
Oil and gas revenues.................................................... $ 21,430 $ - $ -
-------- -------- --------
Operating costs:
Production cost........................................................ 3,738 - -
Exploration, including dry holes and leasehold impairments............. 15,492 2,681 3,228
Depreciation, depletion and amortization............................... 2,976 - -
Income tax benefit..................................................... (295) (1,018) (1,226)
-------- -------- --------
21,911 1,663 2,002
-------- -------- --------
Results of operations.................................................. $ (481) $ (1,663) $ (2,002)
======== ======== ========
CANADA
Oil and gas revenues.................................................... $ 17,615 $ 17,080 $ 16,457
-------- -------- --------
Operating costs:
Production cost........................................................ 5,200 5,475 5,216
Exploration, including dry holes and leasehold impairments............. 2,083 1,249 3,150
Depreciation, depletion and amortization............................... 9,482 8,208 5,968
Income tax provision................................................... 323 816 807
-------- -------- --------
17,088 15,748 15,141
-------- -------- --------
Results of operations.................................................. $ 527 $ 1,332 $ 1,316
======== ======== ========
TOTAL
Oil and gas revenues.................................................... $206,529 $113,350 $ 94,438
-------- -------- --------
Operating costs:
Production cost........................................................ 51,298 42,891 36,938
Exploration, including dry holes and leasehold impairments............. 40,325 15,682 16,187
Depreciation, depletion and amortization............................... 84,979 53,942 50,727
Impairment of oil and gas property..................................... - 8,317 94,793
Income tax provision (benefit)......................................... 11,373 (2,843) (39,598)
-------- -------- --------
187,975 117,989 159,047
-------- -------- --------
Results of operations.................................................. $ 18,554 $ (4,639) $(64,609)
======== ======== ========
-48-
NOTE 19 SUPPLEMENTAL GUARANTOR INFORMATION
In connection with the sale by United Meridian Corporation of the Notes,
Petroleum, the Company's only direct subsidiary, has unconditionally guaranteed
the full and prompt performance of the Company's obligations under the Notes and
related indenture, including the payment of principal, premium (if any) and
interest. Other than intercompany arrangements and transactions, the
consolidated financial statements of Petroleum are equivalent in all material
respects to those of the Company and therefore the separate consolidated
financial statements of Petroleum are not material to investors and have not
been included herein. However, in an effort to provide meaningful financial
data relating to the guarantor (i.e., Petroleum on an unconsolidated basis) of
the Notes, the following condensed consolidating financial information has been
provided following the policies set forth below:
(1) Investments in subsidiaries are accounted for by the Company on the cost
basis. Earnings of subsidiaries are therefore not reflected in the related
investment accounts.
(2) Certain reclassifications were made to conform all of the financial
information to the financial presentation on a consolidated basis. The
principal eliminating entries eliminate investments in subsidiaries and
intercompany balances.
-49-
SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENT OF INCOME
For the years ended December 31, 1996, 1995 and 1994
(In thousands)
Unconsolidated
---------------------------------------------
Guarantor Non-Guarantor Consolidated
UMC Subsidiary Subsidiaries UMC
---------- --------------- ---------------- --------------
1996
- ----
Revenues................................................... $ - $ 149,917 $ 86,487 $ 236,404
------- --------- -------- ---------
Costs and expenses:
Production costs.......................................... - 36,932 14,366 51,298
General and administrative................................ 180 10,554 1,993 12,727
Exploration, including dry holes and impairments.......... - 21,107 19,218 40,325
Depreciation, depletion and amortization.................. - 66,744 18,235 84,979
------- --------- -------- ---------
Income (loss) from operations.............................. (180) 14,580 32,675 47,075
Interest income (expense), net............................ 18,052 (32,067) (8,796) (22,811)
Other credits, net........................................ - (1,034) 190 (844)
------- --------- -------- ---------
Net income (loss) before income taxes...................... 17,872 (18,521) 24,069 23,420
Income tax benefit (provision)............................. (6,208) 6,707 (6,515) (6,016)
------- --------- -------- ---------
Net income (loss).......................................... $11,664 $ (11,814) $ 17,554 $ 17,404
======= ========= ======== =========
1995
- ----
Revenues................................................... $ - $ 107,108 $ 39,933 $ 147,041
------- --------- -------- ---------
Costs and expenses:
Production costs.......................................... - 34,028 8,863 42,891
General and administrative................................ 415 6,966 3,044 10,425
Exploration, including dry holes and impairments.......... - 10,852 4,830 15,682
Depreciation, depletion and amortization.................. - 44,264 9,678 53,942
Impairment of proved oil and gas properties............... - 8,317 - 8,317
------- --------- -------- ---------
Income (loss) from operations.............................. (415) 2,681 13,518 15,784
Interest income (expense), net............................ 12,629 (25,789) (4,785) (17,945)
Other credits, net........................................ - (28) 403 375
------- --------- -------- ---------
Net income (loss) before income taxes...................... 12,214 (23,136) 9,136 (1,786)
Income tax benefit (provision)............................. (4,275) 7,681 479 3,885
------- --------- -------- ---------
Net income (loss).......................................... $ 7,939 $ (15,455) $ 9,615 $ 2,099
======= ========= ======== =========
1994
- ----
Revenues................................................... $ - $ 79,757 $ 18,060 $ 97,817
------- --------- -------- ---------
Costs and expenses:
Production costs.......................................... - 31,285 5,653 36,938
General and administrative................................ 801 6,750 4,953 12,504
Exploration, including dry holes and impairments.......... - 9,254 6,933 16,187
Depreciation, depletion and amortization.................. - 43,442 7,285 50,727
Impairment of proved oil and gas properties............... - 94,706 87 94,793
------- --------- -------- ---------
Loss from operations....................................... (801) (105,680) (6,851) (113,332)
Interest income (expense), net............................ 12,374 (18,530) (2,884) (9,040)
Other credits, net........................................ - 136 (277) (141)
------- --------- -------- ---------
Net income (loss) before income taxes...................... 11,573 (124,074) (10,012) (122,513)
Income tax benefit (provision)............................. (6,921) 48,112 333 41,524
------- --------- -------- ---------
Net income (loss).......................................... $ 4,652 $ (75,962) $ (9,679) $ (80,989)
======= ========= ======== =========
-50-
SUPPLEMENTAL CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 1996 and 1995
(In thousands)
Unconsolidated
------------------------------------------------
Guarantor Non-Guarantor Eliminating Consolidated
UMC Subsidiary Subsidiaries Entries UMC
1996 ---------- ------------ ---------------- ---------------- --------------
- ----
ASSETS
Current assets.............................. $ 3 $ 93,023 $ 63,135 $ - $ 156,161
Intercompany investments.................... 668,025 (346,861) (182,827) (138,337) -
Property and equipment, net................. - 282,236 241,953 - 524,189
Other assets................................ 5,947 36,714 (4,718) - 37,943
---------- ----------- -------------- --------------- -------------
Total assets............................. $ 673,975 $ 65,112 $ 117,543 $ (138,337) $ 718,293
========== =========== ============== =============== =============
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities......................... $ 3,327 42,577 $ 52,488 $ - $ 98,392
Long-term debt.............................. 150,000 (5,700) 12,532 - 156,832
Deferred credits and other liabilities...... - 9,421 21,412 - 30,833
Stockholders' equity........................ 520,648 18,814 31,111 (138,337) 432,236
---------- ----------- -------------- --------------- -------------
Total liabilities & stockholders'
equity.................................. $ 673,975 $ 65,112 $ 117,543 $ (138,337) $ 718,293
========== =========== ============== =============== =============
1995
- ----
ASSETS
Current assets.............................. $ 31 $ 44,599 $ 31,383 $ - $ 76,013
Intercompany investments.................... 453,574 (239,072) (76,165) (138,337) -
Property and equipment, net................. - 305,930 162,743 - 468,673
Other assets................................ 6,103 28,970 (1,309) - 33,764
---------- ----------- -------------- --------------- -------------
Total assets............................. $ 459,708 $ 140,427 $ 116,652 $ (138,337) $ 578,450
========== =========== ============== =============== =============
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities......................... $ 3,443 57,920 $ 29,447 $ - $ 90,810
Long-term debt.............................. 150,000 39,225 55,574 - 244,799
Deferred credits and other liabilities...... - 12,655 17,874 - 30,529
Stockholders' equity........................ 306,265 30,627 13,757 (138,337) 212,312
---------- ----------- -------------- --------------- -------------
Total liabilities & stockholders'
equity.................................. $ 459,708 $ 140,427 $ 116,652 $ (138,337) $ 578,450
========== =========== ============== =============== =============
-51-
SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the years ended December 31, 1996, 1995 and 1994
(In thousands)
Unconsolidated
----------------------------------------
Guarantor Non-Guarantor Consolidated
UMC Subsidiary Subsidiaries UMC
---------- ---------- ------------- ------------
1996
- ----
Cash flows from operating activities:
Net income (loss)......................................... $ 11,664 $ (11,814) $ 17,554 $ 17,404
Adjustments to reconcile net income
(loss) to cash from operating activities................. 6,746 76,914 19,981 103,641
Changes in assets and liabilities......................... 40 (25,641) (12,010) (37,611)
-------- --------- -------- ---------
Net cash provided by operating activities................ 18,450 39,459 25,525 83,434
Cash flows used in investing activities.................... - (61,392) (74,357) (135,749)
Cash flows provided by (used in) financing activities...... (18,478) 57,061 55,088 93,671
-------- --------- -------- ---------
Net increase (decrease) in cash and cash equivalents....... (28) 35,128 6,256 41,356
Cash and cash equivalents at beginning of period........... 31 6,631 6,924 13,586
-------- --------- -------- ---------
Cash and cash equivalents at end of period................. $ 3 $ 41,759 $ 13,180 $ 54,942
======== ========= ======== =========
1995
- ----
Cash flows from operating activities:
Net income (loss)......................................... $ 7,939 $ (15,455) $ 9,615 $ 2,099
Adjustments to reconcile net income
(loss) to cash from operating activities................. 494 45,239 (2,020) 43,713
Changes in assets and liabilities......................... 5,755 13,146 (18,707) 194
-------- --------- -------- ---------
Net cash provided by (used in) operating activities...... 14,188 42,930 (11,112) 46,006
Cash flows used in investing activities.................... - (18,488) (64,220) (82,708)
Cash flows provided by (used in) financing activities...... (14,169) (21,539) 74,171 38,463
-------- --------- -------- ---------
Net increase (decrease) in cash and cash equivalents....... 19 2,903 (1,161) 1,761
Cash and cash equivalents at beginning of period........... 12 3,728 8,085 11,825
-------- --------- -------- ---------
Cash and cash equivalents at end of period................. $ 31 $ 6,631 $ 6,924 $ 13,586
======== ========= ======== =========
1994
- ----
Cash flows from operating activities:
Net income (loss)......................................... $ 4,652 $ (75,962) $ (9,679) $ (80,989)
Adjustments to reconcile net income
(loss) to cash from operating activities................. 880 104,769 14,365 120,014
Changes in assets and liabilities......................... (805) (12,161) 17,505 4,539
-------- --------- -------- ---------
Net cash provided by operating activities................ 4,727 16,646 22,191 43,564
Cash flows provided by (used in) investing activities...... 340 (148,771) (31,729) (180,160)
Cash flows provided by (used in) financing activities...... (5,072) 135,762 17,236 147,926
-------- --------- -------- ---------
Net increase (decrease) in cash and cash equivalents....... (5) 3,637 7,698 11,330
Cash and cash equivalents at beginning of period........... 17 91 387 495
-------- --------- -------- ---------
Cash and cash equivalents at end of period................. $ 12 $ 3,728 $ 8,085 $ 11,825
======== ========= ======== =========
-52-
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
For the information called for by Items 10, 11, 12 and 13, reference is made
to the Company's definitive proxy statement for its 1997 Annual Meeting of
Stockholders, which will be filed with the Securities and Exchange Commission
within 120 days after December 31, 1996, and portions of which are incorporated
herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(A) 1. FINANCIAL STATEMENTS
The following financial statements and the Report of Independent Public
Accountants are filed as a part of this report on the pages indicated:
Report of Independent Public Accountants -- page 23
Consolidated Statement of Income -- For the years ended
December 31, 1996, 1995 and 1994 -- page 24
Consolidated Balance Sheet -- December 31, 1996 and 1995 -- page 25
Consolidated Statement of Changes in Stockholders' Equity -- For the
years ended December 31, 1996, 1995 and 1994 -- page 27
Consolidated Statement of Cash Flows -- For the years ended
December 31, 1996, 1995 and 1994 -- page 28
Selected Quarterly Financial Data for the years ended December 31, 1996
and 1995 -- page 15
Selected Financial Data for the five years ended December 31, 1996 --
page 14
(A) 2. FINANCIAL STATEMENT SCHEDULES
Financial statement schedules have been omitted because they are not
applicable or the information required therein is included elsewhere in the
financial statements or notes thereto.
-53-
INDEX TO EXHIBITS
EXHIBIT
NUMBER EXHIBIT
- ------- ----------------------------------------------------------------------
3.1 Certificate of Incorporation of the Company, as amended, incorporated
by reference to Exhibit 3.1 to UMC's 1995 Form 10-K filed with the
Securities and Exchange Commission on March 7, 1996.
3.2 By-laws of the Company, as amended, incorporated by reference to
Exhibit 3.2 to UMC's 1995 Form 10-K filed with the Securities and
Exchange Commission on March 7, 1996.
4.1 Amended and Restated Credit Agreement dated as of July 18, 1994, among
Petroleum, UMC and Norfolk Holdings Inc. as the Guarantors, The Chase
Manhattan Bank, N.A., Morgan Guaranty Trust Company of New York and
the lenders signatory thereto, incorporated by reference to Exhibit
(b)(1) of Schedule 14D-1 and Schedule 13D of UMC, (No. 5-44990) filed
with the Securities and Exchange Commission on August 11, 1994.
4.2 First Joint Amendment to Amended and Restated Credit Agreement and to
Amended and Restated Credit Agreement (Canada) effective as of
September 2, 1994, incorporated by reference to Exhibit 4.2 to
Amendment No. 1 to UMC's Form S-4 (No. 33-83458) filed with the
Securities and Exchange Commission on October 7, 1994.
4.3 Guaranty Agreement dated as of July 18, 1994, by UMC in favor of The
Chase Manhattan Bank, N.A., Morgan Guaranty Trust Company of New York
and the lenders listed therein, incorporated by reference to Exhibit
4.4 to UMC's Form S-4 (No. 33-83458) filed with the Securities and
Exchange Commission on August 31, 1994.
4.4 Guaranty Agreement dated as of July 18, 1994, by Norfolk Holdings Inc.
as the Guarantor, in favor of The Chase Manhattan Bank, N.A., Morgan
Guaranty Trust Company of New York and the lenders listed therein,
incorporated by reference to Exhibit 4.5 to UMC's Form S-4 (No. 33-
83458) filed with the Securities and Exchange Commission on August 31,
1994.
4.5 Amended and Restated Credit Agreement dated as of July 18, 1994 among
UMC Resources Canada Ltd., The Chase Manhattan Bank of Canada and the
lenders signatory thereto, incorporated by reference to Exhibit 4.6 to
UMC's Form S-4 (No. 33-83458) filed with the Securities and Exchange
Commission on August 31, 1994.
4.6 Guaranty Agreement dated as of July 18, 1994, by UMC as the Guarantor,
in favor of The Chase Manhattan Bank of Canada and the lenders listed
therein, incorporated by reference to Exhibit 4.7 to UMC's Form S-4
(No. 33-83458) filed with the Securities and Exchange Commission on
August 31, 1994.
4.7 Guaranty Agreement dated as of July 18, 1994 by Petroleum in favor of
The Chase Manhattan Bank of Canada and the lenders listed therein,
incorporated by reference to Exhibit 4.8 to UMC's Form S-4 (No. 33-
83458) filed with the Securities and Exchange Commission on August 31,
1994.
4.8 Employment Agreement dated as of August 9, 1994, among Donald D. Wolf,
UMC and Petroleum, incorporated by reference to Exhibit (c)(4) to
UMC's Schedule 14D-1 (No. 5-44990) filed with the Securities and
Exchange Commission on August 11, 1994.
4.9 Amendment No. 1 to Registration Rights Agreement dated as of August 9,
1994 among GARI, UMC, General Atlantic Corporation, John Hancock
Mutual Life Insurance Company and Fidelity Oil Holdings, Inc.,
incorporated by reference to Exhibit (c)(8) to UMC's Schedule 14D-1
(No. 5-44990) filed with the Securities and Exchange Commission on
August 11, 1994.
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EXHIBIT
NUMBER EXHIBIT
- ------- ----------------------------------------------------------------------
4.10 Second Joint Amendment to Amended and Restated Credit Agreement and to
Amended and Restated Credit Agreement (Canada) effective as of
November 15, 1994, incorporated by reference to Exhibit 4.11 to UMC's
1994 Form 10-K filed with the Securities and Exchange Commission on
March 10, 1995.
4.11 Third Joint Amendment to Amended and Restated Credit Agreement and to
Amended and Restated Credit Agreement (Canada) effective as of
December 31, 1994, incorporated by reference to Exhibit 4.12 to UMC's
1994 Form 10-K filed with the Securities and Exchange Commission on
March 10, 1995.
4.12 Credit Agreement dated as of December 31, 1994 among UMC, The Chase
Manhattan Bank, N.A., Morgan Guaranty Trust Company of New York and
Lenders Signatory thereto incorporated by reference to Exhibit 4.13 to
UMC's 1994 Form 10-K filed with the Securities and Exchange Commission
on March 10, 1995.
4.13 Specimen of certificate representing Series A Voting Common Stock,
$.01 par value, of the Company, incorporated herein by reference to
Exhibit 4.13 to the Company's Form 10-Q for the period ended June 30,
1994 filed with the Securities and Exchange Commission on August 10,
1994.
4.14 Stock Purchase Agreement of Series F Convertible Preferred Stock (par
value $0.01 per share) between UMC and John Hancock Mutual Life
Insurance Company, The Travelers Insurance Company, The Travelers Life
and Annuity Company, The Phoenix Insurance Company and the Travelers
Indemnity Company dated June 30, 1994, incorporated by reference to
Exhibit 4.16 to UMC's Form 10-Q for the quarterly period ended June
30, 1995, filed with the Securities and Exchange Commission on August
10, 1995.
4.15 Stock Purchase Agreement of Series F Convertible Preferred Stock (par
value $0.01 per share) between UMC and John Hancock Mutual Life
Insurance Company dated July 24, 1995, incorporated by reference to
Exhibit 4.17 to UMC's Form 10-Q for the quarterly period ended June
30, 1995, filed with the Securities and Exchange Commission on August
10, 1995.
4.16 First Amendment to Credit Agreement among UMC, The Chase Manhattan
Bank, N.A., Morgan Guaranty Trust Company of New York and Lenders
Signatory thereto dated as of June 30, 1995, incorporated by reference
to Exhibit 4.18 to UMC's Form 10-Q for the quarterly period ended June
30, 1995, filed with the Securities and Exchange Commission on August
10, 1995.
4.17 Loan Agreement between UMIC Cote d'Ivoire Corporation and
International Finance Corporation dated as of July 14, 1995,
incorporated by reference to Exhibit 4.19 to UMC's Form 10-Q for the
quarterly period ended June 30, 1995, filed with the Securities and
Exchange Commission on August 10, 1995.
4.18 Share Retention, Guarantee and Clawback Agreement among UMC, UMC
Petroleum Corporation, UMIC Cote d'Ivoire Corporation and
International Finance Corporation dated as of July 14, 1995,
incorporated by reference to Exhibit 4.20 to UMC's Form 10-Q for the
quarterly period ended June 30, 1995, filed with the Securities and
Exchange Commission on August 10, 1995.
4.19 Fourth Joint Amendment to Amended and Restated Credit Agreement and to
Amended and Restated Credit Agreement (Canada) effective as of October
30, 1995, incorporated by reference to Exhibit 4.21 to UMC's Form 10-Q
for the quarterly period ended September 30, 1995, filed with the
Securities and Exchange Commission on November 13, 1995.
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EXHIBIT
NUMBER EXHIBIT
- ------- ----------------------------------------------------------------------
4.20 Indenture between the Company, Petroleum and Bank of Montreal Trust
Company, dated October 30, 1995, incorporated by reference to Exhibit
4.20 to UMC's 1995 Form 10-K filed with the Securities and Exchange
Commission on March 7, 1996.
4.21 Rights Agreement by and between United Meridian Corporation and
Chemical Mellon Shareholder Services, L.L.C., as Rights Agent, dated
as of February 13, 1996, incorporated by reference as Exhibit 1 to
Form 8-K, filed with the Securities and Exchange Commission on
February 14, 1996.
10.1 UMC Key Employee Cash Compensation Program, as amended, incorporated
herein by reference to Exhibit 10.1 to the Company's Form S-1 (No. 33-
63532) filed with the Securities and Exchange Commission on May 28,
1993.
10.2 The UMC Petroleum Savings Plan as amended and restated incorporated
herein by reference to Exhibit 4.10 to the Company's Form S-8 (No. 33-
73574) filed with the Securities and Exchange Commission on December
29, 1993.
10.3 First Amendment to the UMC Petroleum Savings Plan, as Amended and
Restated as of January 1, 1993, dated April 18, 1994, incorporated by
reference to Exhibit 10.3 to UMC's 1994 Form 10-K filed with the
Securities and Exchange Commission on March 10, 1995.
10.4 UMC 1987 Nonqualified Stock Option Plan, as amended, incorporated
herein by reference to Exhibit 10.3 to the Company's Form S-1 (No. 33-
63532) filed with the Securities and Exchange Commission on May 28,
1993.
10.5 Third Amendment to UMC 1987 Nonqualified Stock Option Plan dated
November 16, 1993 incorporated herein by reference to Exhibit 10.4 to
the Company's 1993 Form 10-K filed with the Securities and Exchange
Commission on March 7, 1994.
10.6 Fourth Amendment to UMC 1987 Nonqualified Stock Option Plan dated
April 6, 1994, incorporated by reference to Exhibit 10.6 to UMC's 1994
Form 10-K filed with the Securities and Exchange Commission on March
10, 1995.
10.7 UMC 1994 Employee Nonqualified Stock Option Plan incorporated by
reference to Exhibit 4.14 to the Company's Form S-8 (No. 33-79160)
filed with the Securities and Exchange Commission on May 19, 1994.
10.8 First Amendment to the UMC 1994 Employee Nonqualified Stock Option
Plan dated November 16, 1994, incorporated by reference to Exhibit
4.11.1 to the Company's Form S-8 (No. 33-86480) filed with the
Securities and Exchange Commission on November 18, 1994.
10.9 Second Amendment to the UMC 1994 Employee Nonqualified Stock Option
Plan dated May 22, 1996, incorporated by reference to Exhibit 4.3.2 to
the Company's Form S-8 (No. 333-05401) filed with the Securities and
Exchange Commission on June 6, 1996.
10.10* Form of the Third Amendment to the UMC 1994 Employee Nonqualified
Stock Option Plan dated November 13, 1996.
10.11 UMC 1994 Outside Directors' Nonqualified Stock Option Plan
incorporated herein by reference to Exhibit 4.15 to the Company's Form
S-8 (No. 33-79160) filed with the Securities and Exchange Commission
on May 19, 1994.
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EXHIBIT
NUMBER EXHIBIT
- ------- ----------------------------------------------------------------------
10.12 First Amendment to the UMC 1994 Outside Directors' Nonqualified Stock
Option Plan dated May 22, 1996, incorporated by reference to Exhibit
4.4.1 to the Company's Form S-8 (No. 333-05401) filed with the
Securities and Exchange Commission on June 6, 1996.
10.13* Form of the Second Amendment to the UMC 1994 Outside Directors'
Nonqualified Stock Option Plan dated November 13, 1996.
10.14 UMC Petroleum Corporation Supplemental Benefit Plan effective January
1, 1994, approved by the Board of Directors on March 29, 1994,
incorporated by reference to Exhibit 10.10 to UMC's 1994 Form 10-K
filed with the Securities and Exchange Commission on March 10, 1995.
10.15 Form of Indemnification Agreement, with Schedule of Signatories,
incorporated herein by reference to Exhibit 10.4 to the Company's Form
S-1 (No. 33-63532) filed with the Securities and Exchange Commission
on May 28, 1993.
10.16 Petroleum Production Sharing Contract on Block CI-11 dated June 27,
1992 among the Republic of Cote d'Ivoire, UMIC Cote d'Ivoire
Corporation and Societe Nationale d'Operations Petrolieres de la Cote
d'Ivoire (including English translation), incorporated herein by
reference to Exhibit 10.5 to Amendment No. 3 to the Company's Form S-1
(No. 33-63532) filed with the Securities and Exchange Commission on
July 20, 1993.
10.17 Production Sharing Contract dated August 18, 1992 between the Republic
of Equatorial Guinea and United Meridian International Corporation
(Area A - Offshore NE Bioco), incorporated herein by reference to
Exhibit 10.6 to Amendment No. 1 to the Company's Form S-1 (No. 33-
63532) filed with the Securities and Exchange Commission on June 18,
1993.
10.18 Production Sharing Contract dated June 29, 1992 between the Republic
of Equatorial Guinea and United Meridian International Corporation
(Area B - Offshore NW Bioco), incorporated herein by reference to
Exhibit 10.7 to Amendment No. 1 to the Company's Form S-1 (No. 33-
63532) filed with the Securities and Exchange Commission on June 18,
1993.
10.19 Production Sharing Contract dated June 29, 1994 between the Republic
of Equatorial Guinea and United Meridian International Corporation
(Area C - Offshore Bioco) incorporated by reference to Exhibit 10.15
to UMC's 1994 Form 10-K filed with the Securities and Exchange
Commission on March 10, 1995.
10.20 Production Sharing Contract on Block CI-01 dated December 5, 1994
among The Republic of Cote d'Ivoire, UMIC Cote d'Ivoire Corporation
and Societe Nationale d'Operations Petrolieres de la Cote d'Ivoire
(English translation) incorporated by reference to Exhibit 10.16 to
UMC's 1994 Form 10-K filed with the Securities and Exchange Commission
on March 10, 1995.
10.21 Production Sharing Contract on Block CI-02 dated December 5, 1994
among The Republic of Cote d'Ivoire UMIC Cote d'Ivoire Corporation and
Societe Nationale d'Operations Petrolieres de la Cote d'Ivoire
(English translation) incorporated by reference to Exhibit 10.17 to
UMC's 1994 Form 10-K filed with the Securities and Exchange Commission
on March 10, 1995.
10.22 Production Sharing of Block CI-12 dated April 27, 1995 among The
Republic of Cote d'Ivoire, UMIC Cote d'Ivoire Corporation and others
(English translation), incorporated by reference to Exhibit 10.18 to
UMC's 1995 Form 10-K filed with the Securities and Exchange Commission
on March 7, 1996.
-57-
EXHIBIT
NUMBER EXHIBIT
- ------- ----------------------------------------------------------------------
10.23 Contract for Sale and Purchase of Natural Gas for Block CI-11 among
Caisse Autonome D'Amortissement, UMIC Cote d'Ivoire Corporation and
others dated September 30, 1994 (French and English translation)
incorporated by reference to Exhibit 10.7 to the Company's Form 10-Q
for the period ended September 30, 1994 filed with the Securities and
Exchange Commission on November 14, 1994.
10.24 Production Sharing Contract dated April 5, 1995 between The Republic
of Equatorial Guinea and UMIC Equatorial Guinea Corporation (Area D -
Offshore Bioco) incorporated by reference to Exhibit 10.20 to the
Company's Form 10-Q for the period ended June 30, 1995 filed with the
Securities and Exchange Commission on August 10, 1995.
10.25 Contract for Purchase and Sale of Lion Crude Oil between UMIC Cote
d'Ivoire Corporation, International Finance Corporation, G.N.R. (Cote
d'Ivoire) Ltd. and Pluspetrol S.A. and Total International Limited,
dated December 1, 1995, incorporated by reference to Exhibit 10.22 to
UMC's 1995 Form 10-K filed with the Securities and Exchange Commission
on March 7, 1995.
10.26 Amendment to United Meridian Corporation 1994 Non-Qualified Stock
Option Agreement for Former Employees of General Atlantic Resources,
Inc. dated as of April 16, 1996 among UMC and Donald D. Wolf,
incorporated by reference to Exhibit 10.22 to the Company's Form 10-Q
for the period ended June 30, 1996 filed with the Securities and
Exchange Commission on August 8, 1996.
10.27 Amendment to Employment Agreement dated as of April 16, 1996 among
Petroleum and Donald D. Wolf incorporated by reference to Exhibit
10.23 to the Company's Form 10-Q for the period ended June 30, 1996
filed with the Securities and Exchange Commission on August 8, 1996.
10.28 Employment Agreement, dated October 9, 1996, between UMC, UMC
Petroleum Corporation and James L. Dunlap, incorporated by reference
to Exhibit 10.1 to UMC's Form S-3, Amendment No. 2 (No. 333-12823),
filed with the Securities and Exchange Commission on October 30, 1996.
10.29 Form of Indemnification Agreement with a schedule of director
signatories, incorporated by reference to Exhibit 10.2 to UMC's Form
S-3, Amendment No. 2 (No. 333-12823) filed with the Securities and
Exchange Commission on October 30, 1996.
11.1* Calculation of Net Income per Common Share.
21.1* Subsidiaries of United Meridian Corporation.
23.1* Consent of Arthur Andersen LLP.
27.1* Financial Data Schedule.
- --------------
* Filed herewith.
(B) REPORTS ON FORM 8-K
None.
-58-
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
REGISTRANT UNITED MERIDIAN CORPORATION
March 7, 1997 /s/ JOHN B. BROCK
--------------------
John B. Brock
Chairman of the Board of Directors
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on March 7, 1997 on
behalf of the registrant and in the capacities indicated.
Name Capacities
/s/ JOHN B. BROCK
- -------------------------- Chairman, Chief Executive Officer and Director
John B. Brock (Principal Executive Officer)
/s/ JAMES L. DUNLAP
- -------------------------- President, Chief Operating Officer and Director
James L. Dunlap
/s/ J. DENNIS BONNEY
- -------------------------- Director
J. Dennis Bonney
/s/ CHARLES R. CARSON
- ------------------------- Director
Charles R. Carson
/s/ ROBERT H. DEDMAN
- ------------------------- Director
Robert H. Dedman
/s/ STEVEN A. DENNING
- -------------------------- Director
Steven A. Denning
/s/ ROBERT L. HOWARD
- ------------------------- Director
Robert L. Howard
-59-
Name Capacities
/s/ ROBERT V. LINDSAY
- -------------------------- Director
Robert V. Lindsay
/s/ ELVIS L. MASON
- -------------------------- Director
Elvis L. Mason
/s/ JAMES L. MURDY
- -------------------------- Director
James L. Murdy
/s/ DAVID K. NEWBIGGING
- -------------------------- Director
David K. Newbigging
/s/ MATTHEW R. SIMMONS
- -------------------------- Director
Matthew R. Simmons
/s/ DONALD D. WOLF
- -------------------------- Director
Donald D. Wolf
/s/ WALTER B. WRISTON
- -------------------------- Director
Walter B. Wriston
/s/ JONATHAN M. CLARKSON
- -------------------------- Executive Vice President and Chief Financial
Jonathan M. Clarkson Officer
/s/ CHRISTOPHER E. CRAGG
- -------------------------- Vice President, Controller and Chief Accounting
Christopher E. Cragg Officer
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