Prima (NASDAQ:PENG)
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Prima Energy Corporation Reports Financial Results For 2003 Fourth Quarter and
Full Year, And Execution of Gas Gathering Agreement
DENVER, March 10 /PRNewswire-First Call/ -- Prima Energy Corporation ("Prima"
or "the Company"), a Denver based independent oil and gas company, today
reported its results for the quarter and year ended December 31, 2003. The
Company also announced that it has entered into a gas gathering agreement
covering a substantial portion of its acreage in the Powder River Basin
prospective for development of coal bed methane reserves. Results of Operations
for the Quarter and Year Ended December 31, 2003
Quarter Ended December 31, 2003
Prima's fourth quarter 2003 net income of $6,557,000 represented a 123% increase
over net income of $2,936,000 reported for the fourth quarter of 2002. On a
per-diluted-share basis, net income increased by 127% to $0.50 in the 2003
quarter compared to $0.22 in the final quarter of 2002. Cash flows from
operating activities before changes in operating assets and liabilities
increased by 95%, with $12,735,000 in the fourth quarter of 2003 comparing to
$6,540,000 in the fourth quarter of 2002. Cash flow from operations before
changes in operating assets and liabilities is a non-GAAP financialmeasure
derived from net cash provided by operating activities -- see "Reconciliation of
Non-GAAP Financial Measure" in a table below.
The improvements were attributable to revenue growth, primarily derived from oil
and gas sales. Prima's revenues totaled $19,875,000 in the 2003 quarter compared
to $10,233,000 in the final three months of 2002. Oil and gas sales reported for
the fourth quarter of 2003 totaled $17,017,000, compared to $8,325,000 for the
same quarter in 2002, representing an increase of 104%. The growth was due to a
41% year-over-year increase in production volumes and a 45% increase in average
realized oil and gas prices.
Prima's production mix in the fourth quarter of 2003 was 84% natural gas and 16%
oil, compared to 82% gas and 18% oil in the prior-year period. The Company's gas
production increased by 45% to 3,637,000 Mcf in the latest quarter, from
2,509,000 Mcf in the fourth quarter last year. Oil production totaled
approximately 116,000 barrels in the fourth quarter of 2003, compared to 94,000
barrels in the same quarter of 2002, for an increase of 23%. On an equivalent
unit basis, production expanded from 3,073,000 Mcfe in the final quarter of 2002
to 4,333,000 Mcfe in the recent quarter. This improvement was primarilydue to
Powder River Basin CBM operations, which generated net gas production of
1,971,000 Mcf in the fourth quarter of 2003 compared to 790,000 Mcf in the
fourth quarter of 2002. CBM production in both periods was primarily
attributable to the Porcupine-Tuit property, which began producing during the
third quarter of 2002. In addition, higher oil production in the recent quarter
was realized from increased drilling and refrac activity in the D-J Basin.
The average price received for natural gas production during the last quarter of
2003 was $3.65 per Mcf, compared to $2.24 per Mcf in the final quarter of 2002,
representing an increase of $1.41 or 63%. Average prices received for oil in
the same periods were $32.24 and $28.81 per barrel, respectively, for a
year-over-year increase of $3.43 or 12%. On an Mcf equivalent basis, the average
price received was $3.93 per Mcfe for the 2003 quarter compared to $2.71 per
Mcfe for the same quarter in 2002. Net hedging effects included in oil and gas
saleswere not significant in the final quarter of 2002, but increased revenues
in the recent quarter by $422,000, boosting average price realizations by $0.09
per Mcf of natural gas, $0.68 per barrel of oil and $0.10 per Mcfe. Prima also
recorded $334,000 of gains on non-hedge derivatives in the fourth quarter of
2003, compared to $137,000 of net losses on such positions in the final quarter
of 2002. Non-hedge derivatives consisted of NYMEX gas forward sales without
corresponding Rocky Mountain basis-differential swaps.
Depletion expense was $1.06 per Mcfe in the fourth quarter of 2003 and $0.96 in
the comparable period of 2002. The increase in the per-unit depletion rate
reflected higher average costs per Mcfe for 2003 reserve additions than our
historical average and increased estimates for future development costs for
period-end proved reserves. Lease operating expenses averaged $0.24 per Mcfe of
production in the 2003 quarter and $0.26 per Mcfe in the 2002 quarter.
Production taxes were $0.41 and $0.23 per Mcfe in the 2003 and 2002 quarters,
respectively, primarily reflecting higher product prices in 2003.
Oilfield services provided on Prima-managed properties are eliminated in
consolidation, and represented approximately 25% and 28% of the Company's total
oilfield services activities in the fourth quarters of 2003 and 2002,
respectively. Billings to third parties in the final quarter of 2003 totaled
$2,242,000 compared to $1,923,000 in the fourth quarter of 2002, for an increase
of $319,000, or 17%. Costs of oilfield services provided to third parties
totaled $1,593,000 in the 2003 quarter compared to $1,296,000 in the 2002
period, for an increase of $297,000, or 23%. These increases were primarily
attributable to greater demand for oilfield services in the D-J Basin in 2003.
Income taxes totaled 33% of pre-tax income in the recent quarter, compared to
14% in the prior year's quarter, due to permanent differences that did not
increase proportionately with pre-tax income and the cessation of Section 29 tax
credits at the end of 2002.
Year Ended December 31, 2003
For the year ended December 31, 2003, we reported net income of $23,795,000, or
$1.82 per diluted share, on revenues of $70,154,000. These amounts compare to
net income of $5,230,000, or $0.40 per diluted share, on revenues of
$31,790,000, for the year ended December 31, 2002. Total expenses, other than
income taxes, were $35,247,000 in 2003 compared to $25,735,000 in 2002. Revenues
increased $38,364,000 or 121%, expenses increased $9,512,000 or 37%, and net
income increased $18,565,000 or 355% in 2003. Cash flows from operating
activities before changes in operating assets and liabilities increased by 124%
year-over-year, from $21,063,000 in 2002 to $47,158,000 in 2003. The primary
drivers in these results were increased oil and gas sales and changes in amounts
reported on derivatives not qualifying for hedge accounting treatment.
Oil and gas sales reported for 2003 totaled $58,622,000 compared to $25,785,000
for 2002, for an increase of 127%. The large improvement was due to a 46%
year-over-year growth in production volumes and a 56% increase in the average
price realized per equivalent unit of production.
Prima's production was 84% natural gas and 16% oil in 2003, compared to 79% gas
and 21% oil in the prior year. Natural gas production totaled 13,015,000 Mcf in
2003 compared to 8,343,000 Mcf in 2002, for an increase of 4,672,000 Mcf, or
56%. Oil production totaled 401,000 barrels and 373,000 barrels in 2003and
2002, respectively, for an increase of 28,000 barrels, or 8%. On an equivalent
unit basis, production grew from 10,580,000 Mcfe in 2002 to 15,421,000 Mcfe in
2003. This increase was primarily due to Powder River Basin CBM operations,
which generated net gas production of 6,474,000 Mcf in 2003 compared to
1,576,000 Mcf in 2002. The Company's CBM production to date has been largely
attributable to the Stones Throw property, which was sold March 5, 2002, and the
Porcupine-Tuit property, which beganproducing from 27 wells during the third
quarter of 2002. Production from Porcupine-Tuit increased in the second half of
2002 and in 2003 as de-watering occurred, new wells were drilled and brought
on-line, and additional compression capacity was installed by the gathering
company. At the end of 2003, Prima had 85 wells on-line at Porcupine-Tuit
producing at a combined net daily rate of approximately 19,500 Mcf.
The average price received on natural gas sales in 2003 was $3.53 per Mcf,
compared to $1.97 per Mcf in 2002, for an increase of $1.56 per Mcf, or 79%. The
average price received per barrel of oil was $31.71 in 2003 compared to $25.14
in 2002, representing an increase of $6.57 per barrel or 26%. On an Mcf
equivalent basis, the average price received was $3.80 per Mcfe in 2003 compared
to $2.44 per Mcfe in the prior year. The portion of our total oil and gas
revenues derived from natural gas was 78% in 2003 compared to 64% in 2002.
During 2003, we recognized $2,734,000 of total gains relating to oil and gas
derivatives, comprised of $414,000 of hedging gains included in reported oil and
gas sales and $2,320,000 of separately reported gains on derivative instruments
that did not qualify for hedge accounting (these consisted primarily offorward
sales of NYMEX gas without corresponding swaps for Rocky Mountain basis
differentials). The net gains recognized on derivative instruments that did not
qualify for hedge accounting included related mark-to-market adjustments to fair
value during the year.
By comparison, our revenues for 2002 included $3,376,000 of aggregate losses
from oil and gas derivatives, including hedging losses of $458,000 and
$2,918,000 of reported losses on derivative instruments not qualifying for hedge
accounting.The $2,918,000 of losses on non-qualifying hedges included
$4,464,000 of net unrealized losses that primarily represented reversals of
unrealized mark-to-market gains recorded in the prior year, as the value of gas
futures positions held at December 31, 2001 declined when gas prices escalated
in 2002 before the contracts were settled.
Our depletion expense for oil and gas properties in 2003 was $14,956,000 or
$0.97 per Mcfe, compared to $9,710,000, or $0.92 per Mcfe, in 2002. Lease
operating expenses totaled $3,619,000 for the year ended December 31, 2003
compared to $3,076,000 for the year ended December 31, 2002, representing an
increase of $543,000 or 18%. The increase was primarily associated with the
additional CBM production in 2003 and LOE decreased on a per-unit-of-production
basis, from $0.29 in 2002 to $0.23 in 2003. Ad valorem and production taxes were
$2,116,000 and $5,783,000 in 2002 and 2003, respectively, for an increase of
$3,667,000. Such taxes fluctuate with oil and gas salesrevenues and changing
mill levy rates, and averaged 9.9% of total oil and gas sales (excluding hedging
effects) in 2003 compared to 8.2% in 2002, reflecting a greater portion of oil
and gas sales attributable to properties in Wyoming, which has higher production
tax rates than Colorado.
Oilfield service revenues from third parties totaled $8,577,000 in 2003 compared
to $8,326,000 in the prior year, for an increase of $251,000 or 3%. Costs of
oilfield services provided to third parties were $6,510,000 in 2003 compared to
$6,490,000 in 2002, for an increase of $20,000 or less than 1%. Approximately
24% of fees billed by the service companies in 2003 were for Prima-owned
property interests, compared to 19% in 2002. A 10% year-over-year increase in
billings before intercompany eliminations, attributable to stronger demand for
services, was partially offset by the increased portion of work performed on
Prima-operated properties.
General and administrative expenses, net of third party reimbursementsand
amounts capitalized, were $3,321,000 in 2003 compared to $3,255,000 in 2002. Net
G&A costs increased by $66,000 or 2%. Higher total costs were largely offset by
reimbursements of management and operator fees from third parties, which
increased from $405,000 in 2002 to $601,000 in 2003. Capitalized G&A was
$2,124,000 in both years.
Our effective tax rate increased to 33% in 2003 from approximately 14% in 2002,
due primarily to the $28,852,000, or 476%, increase in pre-tax income without a
proportionate change in permanent differences. The statutory provision under
which Section 29 tax credits were generated by production from certain wells
expired at the end of 2002.
Gas Gathering Agreement
Prima also announced that it recently completed anagreement with an independent
company that will expand its existing gathering system and install new
compression facilities to enable the Company to tie in and market coal bed
methane production from acreage covering most of its Kingsbury, Cedar Draw,
North Shell Draw, Wild Turkey and Fortification Creek project areas, as well as
certain additional nearby lands. These areas account for a substantial portion
of Prima's estimated potential reserves in this CBM play and the planned
facilities are integral to the Company's current year plans to drill an
estimated 150 CBM wells and hook up most of these and approximately 130
previously-drilled CBM wells. The Company also has more than 1,000 additional
prospective CBM well sites on these lands. Under theterms of the agreement,
Prima will pay gathering and compression fees based on throughput volumes. We
anticipate that we will begin to tie wells into such facilities by the third
quarter of this year.
Conference Call
Prima Energy Corporation (NASDAQ:PENG) has scheduled a conference call for
Thursday, March 11, 2004 at 11:00 a.m. Mountain Standard Time (1:00 p.m. Eastern
Standard Time), in order to review the Company's fourth quarter 2003 financial
results and provide an update on operations.
Interested parties may access the conference call by dialing (800) 362- 0571 and
providing conference I.D. "PRIMA". Replays will be available from 1:00 p.m.
MST, March 11 through 10:00 p.m. MST March 18, 2004, by dialing (800) 934-7615
(no reservation number necessary). In addition, the conference call will be
webcast live over the Internet and can be accessed by following the link from
Prima Energy's website at http://www.primaenergy.com/. A replay from the
Internet site will be available shortly after the call is completed, and will be
available for 90 days.
This press release contains "forward-looking statements" which are made pursuant
to the "safe harbor" provisions of the Private Securities Litigation Reform Act
of 1995. These include, without limitation, statements relating to future
drilling and development plans, production and other such matters. The words
"anticipate," "estimate," or "plan" and similar expressions identify
forward-looking statements. Such statements are based on certain assumptions
and analyses made by the Company in light of its experience and its perception
of historical trends, current conditions, expected future developments and other
factors it believes are appropriate in the circumstances. Prima does not
undertake to update, revise or correct any of the forward-looking information.
Factors that could cause actual results to differ materially from the Company's
expectations expressed in the forward-looking statements include, but are not
limited to, the following: industry conditions; volatility of oil and natural
gas prices; operational risks; potential liabilities, delays and associated
costs imposed by government regulation (including environmental regulation); the
substantial capital expenditures required to fund its operations; risks related
to exploration and developmental drilling; and uncertainties about oil and
natural gas reserve estimates. For a more complete explanation of these various
factors, see "Cautionary Statement for the Purposes of the 'Safe Harbor'
Provisions of the Private Securities Litigation Reform Act of 1995" included in
the Company's latest Annual Report on Form 10-K filed with the Securities And
Exchange Commission.
NASDAQ Symbol: PENG
Contacts: Richard H. Lewis, President and Chief Executive Officer
Neil L. Stenbuck, Executive Vice President and
Chief Financial Officer
Telephone Number: (303) 297-2100
Website: http://www.primaenergy.com/
Financial data follows. In addition, a copy of the Company's Form 10-K for the
year ended December 31, 2003 will be available on the Company's website after it
has been filed.
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended Year Ended
December 31, December 31,
2003 2002 2003 2002
REVENUES
Oil and gas sales $17,017,000 $8,325,000 $58,622,000 $25,785,000
Gains (losses)
on derivatives
instruments, net 334,000 (137,000) 2,320,000 (2,918,000)
Oilfield services 2,242,000 1,923,000 8,577,000 8,326,000
Interest, dividend
and other income 282,000 122,000 635,000 597,000
19,875,000 10,233,000 70,154,000 31,790,000
EXPENSES
Depreciation,
depletion and
amortization:
Depletion of
oil and gas
properties 4,598,000 2,953,000 14,956,000 9,710,000
Depreciation of
property and
equipment 260,000 192,000 1,058,000 1,088,000
Lease operating
expense 1,019,000 801,000 3,619,000 3,076,000
Ad valorem and
production taxes 1,773,000 703,000 5,783,000 2,116,000
Cost of oilfield
services 1,593,000 1,296,000 6,510,000 6,490,000
General and
administrative 850,000 867,000 3,321,000 3,255,000
10,093,000 6,812,000 35,247,000 25,735,000
Income Before
Income Taxes
and Cumulative
Effect of Change
in Accounting
Principle 9,782,000 3,421,000 34,907,000 6,055,000
Provision for
income taxes 3,225,000 485,000 11,515,000 825,000
Net Income Before
Cumulative Effect
of Change in
Accounting
Principle 6,557,000 2,936,000 23,392,000 5,230,000
Cumulative effect
of change in
accounting principle -- -- 403,000 --
NET INCOME $6,557,000 $2,936,000 $23,795,000 $5,230,000
Basic Net Income
per Share Before
Cumulative Effect
of Change in
Accounting
Principle $0.51 $0.23 $1.82 $0.41
Cumulative effect
of change in
accounting
principle -- -- 0.03 --
BASIC NET INCOME
PER SHARE $0.51 $0.23 $1.85 $0.41
Diluted Net Income
per Share Before
Cumulative
Effect of Change in
Accounting Principle $0.50 $0.22 $1.79 $0.40
Cumulative effect
of change in
accounting principle -- -- 0.03 --
DILUTED NET INCOME
PER SHARE $0.50 $0.22 $1.82 $0.40
Weighted Average
Common Shares
Outstanding 12,925,172 12,777,716 12,824,123 12,770,716
Weighted Average
Common Shares
Outstanding
Assuming
Dilution 13,207,781 13,233,947 13,062,345 13,221,376
PRODUCTION:
Natural gas (Mcf) 3,637,000 2,509,000 13,015,000 8,343,000
Oil (barrels) 116,000 94,000 401,000 373,000
Net equivalent
units (Mcfe) 4,333,000 3,073,000 15,421,000 10,580,000
AVERAGE PRICES:
Natural gas
(per Mcf) $3.65 $2.24 $3.53 $1.97
Oil (per barrel) $32.24 $28.81 $31.71 $25.14
Net equivalent
units (per Mcfe) $3.93 $2.71 $3.80 $2.44
PRIMA ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
2003 2002
OPERATING ACTIVITIES
Net income $23,795,000 $5,230,000
Adjustments to reconcile
net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 16,014,000 11,001,000
Deferred income taxes 6,416,000 (977,000)
Cumulative effect of change in
accounting principle (403,000) --
Unrealized losses (gains) on
derivatives instruments (685,000) 4,464,000
Tax benefits from stock option plans 1,913,000 1,250,000
Other 108,000 95,000
Net changes in operating assets
and liabilities (1,009,000) 461,000
Net cash provided by
operating activities 46,149,000 21,524,000
INVESTING ACTIVITIES
Additions to oil and gas properties (26,856,000) (22,252,000)
Proceeds from sales of oil
and gas properties 1,765,000 14,577,000
Purchases of other property, net (1,213,000) (768,000)
Proceeds from sales of
available for sale securities, net 625,000 658,000
Net cash used in investing activities (25,679,000) (7,785,000)
NET FINANCING ACTIVITIES (815,000) (813,000)
INCREASE IN CASH AND CASH EQUIVALENTS 19,655,000 12,926,000
CASH AND CASH EQUIVALENTS,
beginning of year 36,263,000 23,337,000
CASH AND CASH EQUIVALENTS,
end of year $ 55,918,000 $ 36,263,000
PRIMA ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
December 31, December 31,
2003 2002
ASSETS
Current assets $69,901,000 $47,257,000
Oil and gas properties, net 101,414,000 88,538,000
Property and equipment, net 4,718,000 4,839,000
Other assets 1,184,000 1,293,000
$177,217,000 $141,927,000
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities $13,753,000 $11,303,000
Ad valorem taxes, non-current 3,634,000 2,077,000
Asset retirement obligations 1,903,000 --
Deferred income taxes 27,251,000 21,281,000
Stockholders' equity 130,676,000 107,266,000
$177,217,000 $141,927,000
RECONCILIATION OF NON-GAAP FINANCIAL MEASURE
Cash flow from operations before changes in operating assets and
liabilities is presented because of its acceptance as an indicator of the
ability of an oil and gas exploration and production company to internally
fund exploration and development activities. This measure should not be
considered as an alternative to net cash provided by operating activities
as defined by generally accepted accounting principles. A reconciliation
of cash flow from operations before changes in operating assets and
liabilities to net cash provided by operating activities is shown below:
Three Months Ended Year Ended
December 31, December 31,
20032002 2003 2002
Net cash provided
by operating
activities $13,779,000 $8,078,000 $46,149,000 $21,524,000
Net changes in
operating assets
and liabilities (1,044,000) (1,538,000) 1,009,000 (461,000)
Cash flow from
operations before
changes in
operating assets
and liabilities $12,735,000 $6,540,000 $47,158,000 $21,063,000
DATASOURCE: Prima Energy Corporation
CONTACT: Richard H. Lewis, President and Chief Executive Officer, or
Neil L. Stenbuck, Executive Vice President and Chief Financial Officer, both
of Prima Energy Corporation, +1-303-297-2100
Web site: http://www.primaenergy.com/