DELAWARE | 77-0079387 | |||
(State of incorporation or organization) | (I.R.S. Employer Identification Number) |
Title of each class | Name of each exchangeon which registered | |||
Class A Common Stock, $.01 par value | New York Stock Exchange | |||
(including associated stock purchase rights) |
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Item 9A | 67 | |
Item 9B | 68 | |
Item 10. | 68 | |
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Item 15. | 69 |
Item 1. |
· | California production - Projects include expanding the thermal development of the Poso Creek field, the evaluation of the Company’s diatomite pilot at North Midway-Sunset and additional drilling of infill horizontal wells at South Midway-Sunset. |
· | Rockies & Mid-Continent production - In 2005, the Company will continue the development of the Brundage Canyon producing property on 80-acre spacing, test the potential of 40-acre infill drilling and appraise the northern and southern limits of the field. On the recently acquired Niobrara gas assets, the Company plans to drill approximately 60 wells as part of its ongoing development program and the initiation of the 40-acre infill program from the existing 80-acre development. |
· | Rockies & Mid-Continent prospects - The Company and its joint venture partner, will begin testing the oil potential of the Lake Canyon acreage with at least two shallow test wells at approximately 6,000 feet in the Green River trend. These initial drill sites will be approximately three miles west of the Company’s Brundage Canyon producing property and have the potential of providing the Company with development opportunities comparable to Brundage Canyon. Drilling of the first deep natural gas test well in Lake Canyon is scheduled for the fourth quarter of 2005. The Company intends to drill its obligation wells at Coyote Flats, (45 miles southwest of Brundage Canyon) which will target the Ferron sands and Emery coals. Additionally, the Company will participate with its partner to begin testing the Sharon Springs Shale gas, Niobrara biogenic natural gas, along with the deeper Pennsylvanian formation oil prospects in its recently acquired Tri-State acreage in Colorado, Nebraska and Kansas. |
· | In September 2004, the Company entered into a farm-out agreement pursuant to which Bill Barrett Corporation had the right to earn a 75% working interest in the deep Mesaverde formation and deeper horizons within the Brundage Canyon field by drilling a deep exploratory test. The Company's partner commenced the drilling of its initial deep exploratory well in Brundage Canyon in November 2004 and abandoned it in January 2005, pending the further evaluation of a 3-D seismic survey and assessment of optimal completion technology. No costs were incurred by the Company related to the drilling or abandonment of this well. |
2004 | 2003 | 2002 | ||||||||
Total revenues (in millions) | $ | 275 | $ | 181 | $ | 131 | ||||
Sales of oil and gas | 83 | % | 75 | % | 78 | % | ||||
Sales of electricity | 17 | % | 24 | % | 21 | % | ||||
Other | - | 1 | % | 1 | % |
Colorado Interstate Gas (CIG) index related prices. Additionally, produced gas from the Niobrara field in Colorado is also sold at monthly CIG index related price
For 2004, the first-of-month indices approximated $5.60 per MMBtu for SoCal Border, $5.15 per MMBtu for Rockies CIG and $5.05 for Rockies Questar. The closing price for the NYMEX prompt month natural gas contract averaged $6.18, $5.84 and $3.37 for years 2004, 2003 and 2002, respectively.
Average | Average | Average | Average | |||||||
Barrels | Swap | MMBtu | Swap | |||||||
Term | Per Day | Price | Term | Per Day | Price | |||||
Crude Oil Sales | Natural Gas Sales (CIG) | |||||||||
(NYMEX WTI) | ||||||||||
Full Year 2005 | 1,000 | $ 6.21 | ||||||||
1st Quarter 2005 | 8,000 | $ 41.38 | ||||||||
Natural Gas Purchases | ||||||||||
2nd Quarter 2005 | 8,000 | $ 40.58 | (SoCal Border) | |||||||
3rd Quarter 2005 | 7,500 | $ 40.84 | 1st Quarter 2005 | 9,000 | $ 5.60 | |||||
4th Quarter 2005 | 7,500 | $ 40.67 | 2nd Quarter 2005 | 8,000 | $ 5.19 | |||||
1st Quarter 2006 (1) | 1,250 | $ 45.32 | 3rd Quarter 2005 | 6,667 | $ 5.09 | |||||
2nd Quarter 2006 (1) | 1,250 | $ 44.49 | 4th Quarter 2005 | 6,000 | $ 5.05 | |||||
3rd Quarter 2006 (1) | 1,250 | $ 43.78 | 1st Quarter 2006 | 5,000 | $ 4.85 |
Payments to the Company's counterparties are triggered when the monthly average prices are above the swap price in the case of the Company's crude oil and natural gas sales hedges and below the swap price for the Company's natural gas purchase hedge positions. Conversely, payments from our counterparties are received when the monthly average prices are below the swap price for the Company's crude oil and natural gas sales hedges and above the swap price for the Company's natural gas purchase hedge positions. Management regularly monitors the crude oil and natural gas markets and the Company’s financial commitments to determine if, when, and at what level some form of crude oil and/or natural gas hedging or other price protection is appropriate.
cogeneration facilities. A proceeding is now underway at the CPUC to review and revise the methodology used to determine SRAC energy prices. This proceeding is currently scheduled to be completed by the end of 2005. There is no assurance that any new methodology will continue to provide a hedge against the Company’s fuel cost or that a revised pricing mechanism will be as beneficial as the current contract pricing.
The original SO contract for Placerita Unit 1 continues in effect through March 2009. The modified SRAC pricing terms reflect a fixed energy price of 5.37 cents/kilowatt per hour (KWh) until June 2006, at which time the energy price reverts to the SRAC pricing methodology. In 2002, the CPUC ordered the California utilities to offer SO contracts to certain cogeneration facilities with expired SO contracts, known as Qualifying Facilities or QFs, for a maximum term of one year. The Company met these requirements and entered into new SO contracts with Edison for its Placerita Unit 2 and with PG&E for its Cogen 38 and Cogen 18 facilities effective January 2003. These three new SO contracts resulted in improved electrical pricing in 2003 over 2002. All three SO contracts terminated on December 31, 2003, as originally ordered by the CPUC.
Location and Facility | Type of Contract | Purchaser | Contract Expiration | Approximate Megawatts Available for Sale | Approximate Megawatts Consumed in Operations | Approximate Barrels of Steam Per Day |
Placerita | ||||||
Placerita Unit 1 | SO2 | Edison | Mar-09 | 20 | - | 6,600 |
Placerita Unit 2 | SO1 | Edison | Dec-09 | 16 | 4 | 6,700 |
South Midway-Sunset | ||||||
Cogen 18 | SO1 | PG&E | Dec-09 | 12 | 4 | 6,600 |
Cogen 38 | SO1 | PG&E | Dec-09 | 37 | - | 18,000 |
· | the location of wells; |
· | the method of drilling and casing wells; |
· | the rates of production or "allowables;" |
· | the surface use and restoration of properties upon which wells are drilled; |
· | the plugging and abandoning of wells; and |
· | notice to surface owners and other third parties. |
Moreover, each state generally imposes a property, production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.
A portion of the Company's leases in the Uinta Basin are, and some of the Company's future leases in this and other areas may be, regulated by Native American tribes. In addition to regulation by various federal, state and local agencies and authorities, an entirely separate and distinct set of laws and regulations applies to lessees, operators and other parties within the boundaries of Native American reservations. Various federal agencies within the U.S. Department of the Interior, particularly the Minerals Management Service and the Bureau of Indian Affairs, together with each Native American tribe, promulgate and enforce regulations pertaining to oil and gas operations on Native American reservations. These regulations include lease provisions, royalty matters, drilling and production requirements, environmental standards, and numerous other matters.
2005 | 2004 | 2003 | ||||||||
(Budgeted) (1) | ||||||||||
CALIFORNIA | ||||||||||
Midway-Sunset Field | ||||||||||
New wells | $ | 11,012 | $ | 11,376 | $ | 10,710 | ||||
Remedials/workovers | 420 | 1,415 | 1,718 | |||||||
Facilities - oil & gas | 6,850 | 4,045 | 3,136 | |||||||
Facilities - cogeneration | 3,435 | 1,055 | 231 | |||||||
General | 2,001 | 2,144 | 187 | |||||||
23,718 | 20,035 | 15,982 | ||||||||
Other California Fields | ||||||||||
New wells | 5,295 | 426 | 6,509 | |||||||
Remedials/workovers | 4,463 | 1,589 | 1,084 | |||||||
Facilities - oil & gas | 2,470 | 3,416 | 1,676 | |||||||
Facilities - cogeneration | 250 | 555 | 370 | |||||||
12,478 | 5,986 | 9,639 | ||||||||
Total California | 36,196 | 26,021 | 25,621 | |||||||
ROCKIES AND MID-CONTINENT | ||||||||||
Uinta Basin | ||||||||||
New wells | 47,914 | 39,467 | 14,298 | |||||||
Remedials/workovers | 2,050 | 4,597 | 234 | |||||||
Facilities | 4,332 | 1,979 | 146 | |||||||
54,296 | 46,043 | 14,678 | ||||||||
DJ Basin | ||||||||||
New wells/workovers | 5,660 | - | - | |||||||
Land and seismic | 3,573 | - | - | |||||||
9,233 | - | - | ||||||||
Other | 3,593 | 161 | 1,256 | |||||||
Total Rocky Mountain and | ||||||||||
Mid-Continent | 67,122 | 46,204 | 15,934 | |||||||
Other | 3,682 | - | - | |||||||
Totals | $ | 107,000 | $ | 72,225 | $ | 41,555 |
2004 | 2003 | 2002 | ||||||||
Net annual production:(1) | ||||||||||
Oil (Mbbls) | 7,044 | 5,827 | 5,123 | |||||||
Gas (Mmcf) | 2,839 | 1,277 | 769 | |||||||
Total equivalent barrels(2) | 7,517 | 6,040 | 5,251 | |||||||
Average sales price: | ||||||||||
Oil (per Bbl) before hedging | $ | 33.43 | $ | 24.41 | $ | 20.27 | ||||
Oil (per Bbl) after hedging | 29.89 | 22.37 | 19.54 | |||||||
Gas (per mcf) before hedging | 6.13 | 4.40 | 2.22 | |||||||
Gas (per mcf) after hedging | 6.12 | 4.43 | 2.22 | |||||||
Per BOE before hedging | 33.64 | 24.48 | 20.11 | |||||||
Per BOE after hedging | 30.32 | 22.52 | 19.39 | |||||||
Average operating cost – oil and gas production (per BOE) | 10.96 | 10.37 | 8.61 |
Developed Acres | Undeveloped Acres | Total | |||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | ||||||||||||||
California | 8,167 | 8,167 | 7,038 | 7,038 | 15,205 | 15,205 | |||||||||||||
Utah (1) | 9,520 | 9,360 | 82,363 | 58,352 | 91,883 | 67,712 | |||||||||||||
Wyoming | 3,800 | 750 | 4,266 | 2,250 | 8,066 | 3,000 | |||||||||||||
Illinois | - | - | 58,318 | 54,601 | 58,318 | 54,601 | |||||||||||||
Kansas | - | - | 168,960 | 163,046 | 168,960 | 163,046 | |||||||||||||
Other | 80 | 19 | - | - | 80 | 19 | |||||||||||||
21,567 | 18,296 | 320,945 | 285,287 | 342,512 | 303,583 |
2004 | 2003 | 2002 | |||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | ||||||||||||||
Exploratory wells drilled: | |||||||||||||||||||
Productive | 5 | 5 | - | - | - | - | |||||||||||||
Dry(1) | - | - | - | - | 11 | 11 | |||||||||||||
Development wells drilled: (2) | |||||||||||||||||||
Productive | 123 | 111 | 121 | 119 | 81 | 76 | |||||||||||||
Dry(1) | - | - | 1 | 1 | - | - | |||||||||||||
Total wells drilled: | |||||||||||||||||||
Productive | 128 | 116 | 121 | 119 | 81 | 76 | |||||||||||||
Dry(1) | - | - | 1 | 1 | 11 | 11 |
· | customary royalty interests; |
· | liens incident to operating agreements and for current taxes; |
· | obligations or duties under applicable laws; |
· | development obligations under oil and gas leases; and |
· | burdens such as net profits interests. |
The oil and gas business can be hazardous, involving unforeseen circumstances such as blowouts or environmental damage. Although it is not insured against all risks, the Company maintains a comprehensive insurance program to address the hazards inherent in operating its oil and gas business.
Item 2. |
Item 3. |
Item 4. | Submission of Matters to a Vote of Security Holders |
SHAWN M. CANADAY, 29, has been Treasurer since December 2004 and was Senior Financial Analyst from November 2003 until December 2004. Mr. Canaday has worked in the oil and gas industry since 1998 in various finance functions at ChevronTexaco and in public accounting. Mr. Canaday is also an Assistant Secretary for the Company.
Item 5. | Marketfor the Registrant’s Common Equity and Related Shareholder Matters and Issuer Purchases of Equity Securities |
2004 | 2003 | ||||||||||||||||||
Price Range | Dividends | Price Range | Dividends | ||||||||||||||||
High | Low | Per Share | High | Low | Per Share | ||||||||||||||
First Quarter | $ | 27.30 | $ | 18.25 | $ | 0.11 | $ | 17.01 | $ | 14.65 | $ | 0.10 | |||||||
Second Quarter | 31.07 | 25.09 | 0.11 | 18.38 | 14.40 | 0.15 | |||||||||||||
Third Quarter | 38.44 | 27.73 | 0.18 | 19.17 | 16.96 | 0.11 | |||||||||||||
Fourth Quarter | 50.58 | 35.16 | 0.12 | 20.95 | 17.90 | 0.11 |
Number of securities to be | ||||||
issued upon exercise of | Weighted average exercise | Number of securities | ||||
outstanding options, warrants | price of outstanding options, | remaining available for future | ||||
and rights (1)(3) | warrants and rights | issuance (2)(3) | ||||
Plan category | (a) | (b) | (c) | |||
Equity compensation plansapproved by security holders | 1,565,625 | $25.41 | - | |||
Equity compensation plans not approved by security holders | - | - | - | |||
Total | 1,565,625 | $25.41 | - |
(1) Does not include 56,204 shares earned and reserved for issuance from the Non-Employee Directors Deferred Compensation Plan for past compensation deferred.
(2) Does not include 192,999 shares available and reserved for future issuance from the Non-Employee Directors Deferred Compensation Plan in lieu of future option issuance from the Company's 1994 Non-Statutory Stock Option Plan which expired on December 2, 2004.
(3) Based on historical averages, the actual shares issued from the 1994 Non-Statutory Stock Option Plan have been at a ratio of approximately four options exercised for each share of Common Stock issued.
Item 6. | SelectedFinancial Data |
2004 | 2003 (1) | 2002(1) | 2001(1) | 2000(1) | ||||||||||||
Audited Financial Information | ||||||||||||||||
Statement of Income Data: | ||||||||||||||||
Sales of oil and gas | $ | 226,876 | $ | 135,848 | $ | 102,026 | $ | 100,146 | $ | 118,801 | ||||||
Sales of electricity | 47,644 | 44,200 | 27,691 | 35,133 | 51,420 | |||||||||||
Operating costs – oil and gas production | 82,419 | 62,554 | 45,217 | 38,114 | 48,594 | |||||||||||
Operating costs – electricity generation | 46,191 | 42,351 | 26,747 | 36,890 | 45,464 | |||||||||||
General and administrative expenses (G&A) | 20,354 | 12,868 | 9,215 | 8,718 | 6,782 | |||||||||||
Depreciation, depletion & amortization | ||||||||||||||||
(DD&A) - oil and gas production | 29,752 | 17,258 | 13,388 | 13,225 | 11,374 | |||||||||||
DD&A - electricity generation | 3,490 | 3,256 | 3,064 | 3,295 | 2,656 | |||||||||||
Net income | 69,187 | 32,363 | 29,210 | 20,985 | 37,766 | |||||||||||
Basic net income per share | 3.16 | 1.49 | 1.34 | 0.96 | 1.71 | |||||||||||
Diluted net income per share | 3.08 | 1.47 | 1.33 | 0.95 | 1.71 | |||||||||||
Weighted average number of shares outstanding (basic) | 21,894 | 21,772 | 21,741 | 21,973 | 22,029 | |||||||||||
Weighted average number of shares outstanding (diluted) | 22,470 | 22,031 | 21,902 | 22,162 | 22,145 | |||||||||||
Balance Sheet Data: | ||||||||||||||||
Working capital | $ | (3,840 | ) | $ | (3,540 | ) | $ | (2,892 | ) | $ | 6,314 | $ | (963 | ) | ||
Total assets | 412,104 | 340,377 | 259,325 | 238,779 | 238,572 | |||||||||||
Long-term debt | 28,000 | 50,000 | 15,000 | 25,000 | 25,000 | |||||||||||
Shareholders' equity | 263,086 | 197,338 | 172,774 | 153,590 | 145,220 | |||||||||||
Cash dividends per share | 0.52 | 0.47 | 0.40 | 0.40 | 0.40 | |||||||||||
Operating Data: | ||||||||||||||||
Cash flow from operations | 124,613 | 64,825 | 57,895 | 35,433 | 65,934 | |||||||||||
Capital expenditures (excluding acquisitions) | 72,225 | 41,555 | 30,632 | 14,895 | 25,253 | |||||||||||
Property/facility acquisitions | 2,845 | 48,579 | 5,880 | 2,273 | 3,182 | |||||||||||
Unaudited Operating Data | ||||||||||||||||
Oil and gas producing operations (per BOE): | ||||||||||||||||
Average sales price before hedging | $ | 33.64 | $ | 24.48 | $ | 20.11 | $ | 19.63 | $ | 23.01 | ||||||
Average sales price after hedging | 30.32 | 22.52 | 19.39 | 19.79 | 21.72 | |||||||||||
Average operating costs - oil and gas production | 10.96 | 10.37 | 8.61 | 7.64 | 9.29 | |||||||||||
G&A | 2.71 | 2.13 | 1.75 | 1.73 | 1.24 | |||||||||||
DD&A - oil and gas production | 3.96 | 2.86 | 2.55 | 3.28 | 2.57 | |||||||||||
Production(MBOE) | 7,517 | 6,040 | 5,251 | 5,044 | 5,467 | |||||||||||
Production(MWh) | 776 | 767 | 748 | 483 | 764 | |||||||||||
Proved Reserves Information: | ||||||||||||||||
Total BOE | 109,836 | 109,920 | 101,719 | 102,855 | 107,361 | |||||||||||
Standardized measure(2) | $ | 686,748 | $ | 528,220 | $ | 449,857 | $ | 278,453 | $ | 501,694 | ||||||
Present value (PV10) of estimated future netcash flow before income taxes | 876,502 | 683,124 | 599,826 | 358,653 | 719,882 | |||||||||||
Year-end average BOE price for PV10 purposes | 29.87 | 25.89 | 24.91 | 14.13 | 21.13 | |||||||||||
Other: | ||||||||||||||||
Return on average shareholders' equity | 31.06 | % | 17.50 | % | 17.90 | % | 14.00 | % | 28.80 | % | ||||||
Return on average total assets | 18.60 | % | 10.80 | % | 11.70 | % | 8.80 | % | 16.90 | % |
Item 7. | Management's Discussion and Analysis of Financial Condition and Results of Operations |
Overview
· | the profitability of the Company; |
· | the amount of cash flow available for capital expenditures; |
· | the Company's ability to borrow and raise additional capital; and |
· | the amount of oil and gas that the Company can economically produce. |
· | determining its proved oil and gas reserves; |
· | timing of its future drilling, development and abandonment activities; |
· | future costs to develop and abandon oil and gas properties; |
· | estimates and timing of certain tax items, deductions and credits, |
· | estimates related to certain, if any, environmental impacts of operations, and |
· | the valuation of derivative positions. |
2004 | 2003 | 2002 | ||||||||
Oil and Gas | ||||||||||
Oil Production (Bbl/D) | 19,246 | 15,966 | 14,036 | |||||||
Natural Gas Production (Mcf/D) | 7,752 | 3,499 | 2,106 | |||||||
Total (BOE/D) | 20,537 | 16,549 | 14,387 | |||||||
Per BOE: | ||||||||||
Average sales price before hedging | $ | 33.64 | $ | 24.48 | $ | 20.11 | ||||
Average sales price after hedging | 30.32 | 22.52 | 19.39 | |||||||
Electricity | ||||||||||
Electric power produced - MWh/D | 2,121 | 2,100 | 2,050 | |||||||
Electric power sold – MWh/D | 1,915 | 1,925 | 1,848 | |||||||
Average sales price/MWh before hedging | $ | 70.24 | $ | 62.91 | $ | 40.06 | ||||
Average sales price/MWh after hedging | $ | 70.24 | $ | 61.95 | $ | 39.64 | ||||
Fuel gas cost/MMBtu (excluding transportation) | $ | 5.46 | $ | 4.88 | $ | 3.13 |
2004, these properties contributed 4,400 BOE/day for all of 2004. With the continued development of its California and Brundage Canyon properties and the initial development of it newly acquired assets in the Rocky Mountain and Mid-Continent region, the Company anticipates that oil and gas production will average in excess of 23,000 BOE/day in 2005 or an approximate 12% increase in production over 2004.
Electricity Generation.The Company produced 2,121 MWh/D of electricity in 2004, compared to 2,100 MWh/D in 2003 and 2,050 MWh/D produced in 2002. During 2004, the Company received an average sales price, before hedging, for its electricity per MWh of $70.24 compared to $62.91 in 2003 and $40.06 in 2002. During 2004, electricity prices were, relative to the cost of natural gas to generate electricity, improved from 2003. In January 2004, three Standard Offer contracts were extended on similar terms to those in effect for 2003. This volume represented approximately 77% of the Company’s electricity sales output. Under the terms of the Standard Offer contracts, the price received for the electricity is based on the cost of natural gas at the California border. The Company consumes approximately 37,000 MMBtu of natural gas per day for use in generating steam and of this total, approximately 72% is consumed in the Company’s cogeneration operations. By maintaining a correlation between electricity and natural gas prices, the Company is able to better control its cost of producing steam. Depending on the outcome of a proceeding that is currently under way at the CPUC to review and revise the methodology to determine SRAC energy prices, this correlation between electricity and natural gas prices may change at some point in the future.
Amount per BOE | Amount (in thousands) | ||||||||||||||||||
% | % | ||||||||||||||||||
2004 | 2003 | Change | 2004 | 2003 | Change | ||||||||||||||
Operating costs | $ | 10.96 | $ | 10.36 | 6 | % | $ | 82,419 | $ | 62,554 | 32 | % | |||||||
DD&A | 3.96 | 2.86 | 38 | % | 29,752 | 17,258 | 72 | % | |||||||||||
G&A | 2.71 | 2.13 | 27 | % | 20,354 | 12,868 | 58 | % | |||||||||||
Interest expense | 0.27 | 0.23 | 17 | % | 2,067 | 1,414 | 46 | % | |||||||||||
Total | $ | 17.90 | $ | 15.58 | 15 | % | $ | 134,592 | $ | 94,094 | 43 | % |
The Company's total operating expenses for 2004, stated on a unit-of-production basis, increased 15% over 2003. The increase was primarily related to the following items:
| · | Operating costs for 2004, on a per barrel basis, increased 6% over 2003. The cost of the Company's steaming operations for its heavy oil properties represents a significant portion of the Company's operating costs and will vary depending on both the cost of natural gas used as fuel and the volume of steam injected during the year. Steam costs were higher in 2004 as the cost for natural gas per MMBtu increased to $5.46 from $4.88 in 2003, an increase of 12%. The Company also injected an average of 69,200 BSPD in 2004, up 9% from 63,300 BSPD in 2003. Assuming stable crude oil and natural gas prices, the Company plans to inject steam at levels in 2005 comparable to 2004 levels and anticipates operating costs in 2005, on a per BOE basis, to average between $13.25 and $14.25 in its California operations, between $8.50 and $9.50 in its Utah operations and between $11.75 and $12.75 for the total Company. |
| · | DD&A was $3.96 per BOE in 2004, up 38% from $2.86 per BOE in 2003. DD&A in 2004 was higher due to the shorter reserve life of the Brundage Canyon properties in Utah and the cumulative effect of increased development activities in recent years. The Company expects DD&A to trend higher over the next few years due to the shorter reserve life of the Rocky Mountain assets compared to the Company's California properties and continued development of its California and Rocky Mountain properties. The Company anticipates its oil and gas DD&A charges for 2005 will range from $4.25 to $4.75 per BOE. |
· | G&A expenses in 2004 were $2.71 per BOE, up 27% from $2.13 per BOE in 2003. Stock based compensation costs increased by $2.8 million in 2004, which are primarily non-cash charges resulting from mark-to-market adjustments under the variable method of accounting prior to the change of certain exercise provisions of the Company's stock option plan on July 29, 2004 and non-cash compensation expense under the fair value method of accounting. Compensation expenses increased by $2.3 million due to increased staffing resulting from the Company's growth, an increase in compensation levels and bonuses and costs related to a change in chief executive officers. Additionally, the Company incurred increased legal and accounting fees during 2004 of approximately $1 million, primarily due to compliance with Sarbanes-Oxley and other financial reporting related matters. For 2005, the Company anticipates that its G&A expenses will range from approximately $16 million to $19 million or $1.75 to $2.25 per BOE. |
· | Interest expense in 2004 was $.27 per BOE, up from $.23 per BOE in 2003. The Company’s borrowings at year-end 2004 were $28 million, down from $50 million in 2003. The Company borrowed $40 million in August 2003 to fund the acquisition of its Brundage Canyon property. The Company reduced its debt from 2003 levels during the latter half of 2004. Upon the close of its Niobrara gas acquisition in January of 2005 the Company’s outstanding borrowings rose to over $130 million. The Company anticipates that its interest cost for 2005 will be approximately $4 million to $5 million, or $.45 to $.60 per BOE. |
Amount per BOE | Amount (in thousands) | ||||||||||||||||||
% | % | ||||||||||||||||||
2003 | 2002 | Change | 2003 | 2002 | Change | ||||||||||||||
Operating costs | $ | 10.36 | $ | 8.61 | 20 | % | $ | 62,554 | $ | 45,217 | 38 | % | |||||||
DD&A | 2.86 | 2.55 | 12 | % | 17,258 | 13,388 | 29 | % | |||||||||||
G&A | 2.13 | 1.75 | 22 | % | 12,868 | 9,215 | 40 | % | |||||||||||
Interest expense | 0.23 | 0.20 | 15 | % | 1,414 | 1,042 | 36 | % | |||||||||||
Total | $ | 15.58 | $ | 13.11 | 19 | % | $ | 94,094 | $ | 68,862 | 37 | % |
· | Operating costs for 2003, on a per barrel basis, increased 20% over 2002. The cost of the Company's steaming operations for its heavy oil properties represents a significant portion of the Company's operating costs and will vary depending on both the cost of natural gas used as fuel in the steaming operations and the volume of steam injected during the year. Steam costs were higher in 2003 as the cost for natural gas per MMBtu increased to $4.88 from $3.13 in 2002. The Company also injected an average of 63,300 BSPD in 2003, up 5% from 60,060 BSPD in 2002. |
· | DD&A was $2.86 per BOE in 2003, up 12% from $2.55 per BOE in 2002. DD&A in 2003 was higher due to the shorter reserve life of the Brundage Canyon properties in Utah and the cumulative effect of increased development activities in recent years. |
· | G&A expenses in 2003 were $2.13 per BOE, up 22% from $1.75 per BOE in 2002. The majority of the increase was due to stock option compensation of $3.9 million in 2003 compared to $1.3 million in 2002, which are primarily non-cash charges resulting from mark-to-market adjustments under the variable method of accounting. Also contributing to the increase in 2003 was higher compensation expenses, the opening of a regional office in the Rocky Mountains, a higher level of acquisition activity and increased accounting and consulting charges incurred in 2003. |
· | Interest expense in 2003 was $.23 per BOE, up from $.20 per BOE in 2002. The Company’s borrowings at year-end 2003 were $50 million, up from $15 million in 2002 due to the acquisition of its Brundage Canyon properties in August 2003. |
Dry hole, Abandonment and Impairment.At December 31, 2004, the Company was in the process of drilling one exploratory well on its Midway-Sunset property and one exploratory well on its Coyote Flats prospect. These two wells were determined non-commercial in February 2005. Costs of $.5 million which were incurred as of December 31, 2004 were charged to expense and are reflected on the Company's income statement under "Dry-hole, abandonment and impairment." Remaining costs related to these wells are approximately $2.5 million which will be charged to expense during the first quarter of 2005.
During 2003, the Company recorded a pre-tax write down of $4.2 million related to two CBM pilot projects. For the periods ended December 31, 2004 and December 31, 2002, the fair value of the Company's oil and gas properties exceeded their carrying cost and as a result, the Company did not write down any of its oil and gas properties.
Other.In 2002, the Company recorded income of $3.6 million, which represented the recovery of receivables from electricity sales that were written off in 2001 due to non-payment by utilities contractually obligated to purchase the Company's electricity.
Brundage Canyon, Utah assets. As of December 31, 2004, the Company had $172 million available under the facility. The Company drew on its credit facility to fund its acquisition of certain assets in the Niobrara field in January 2005. As of March 1, 2005, the Company's borrowing under its credit facility totaled $144 million. Exclusive of any further acquisitions in 2005, the Company plans to reduce debt levels from excess cash generated from operating activities.
The facility is a revolving credit facility for up to $200 million with ten banks. At December 31, 2004 and 2003, the Company had $28 million and $50 million, respectively, outstanding under the facility. In addition to the $28 million in borrowings under the Agreement, the Company has $.5 million of outstanding Letters of Credit and the remaining credit available under the facility is therefore, $172 million at December 31, 2004. The maximum amount available is subject to an annual borrowing base redetermination in accordance with the lenders' customary procedures and practices. The facility matures on July 10, 2006. Interest on amounts borrowed is charged at LIBOR plus a margin of 1.25% to 2.00%, or the higher of the lead bank’s prime rate or the federal funds rate plus 50 basis points plus a margin of 0.0% to 0.75%, with margins on the various rate options based on the ratio of credit outstanding to the borrowing base. The Company pays a commitment fee of 30 to 50 basis points on the unused portion, which is also based on the ratio of credit outstanding to the borrowing base. Given that the credit markets have improved over the last year and the Company believes that its borrowing capacity has expanded, the Company intends to negotiate a new credit facility in 2005.
The Company's contractual obligations as of December 31, 2004 are as follows (in thousands): | ||||||||||||||||
Less than | 1-3 | 3-5 | More than | |||||||||||||
Contractual Obligations | Total | 1 year | years | years | 5 years | |||||||||||
Long-term debt | $ | 28,000 | $ | - | $ | 28,000 | $ | - | $ | - | ||||||
Abandonment obligations | 8,214 | 304 | 871 | 1,064 | 5,975 | |||||||||||
Operating lease obligations | 1,423 | 621 | 676 | 126 | - | |||||||||||
Drilling obligation | 10,525 | 925 | 4,250 | 5,350 | - | |||||||||||
Firm natural gas | ||||||||||||||||
transportation contract | 23,438 | 2,814 | 5,628 | 5,628 | 9,368 | |||||||||||
Total | $ | 71,600 | $ | 4,664 | $ | 39,425 | $ | 12,168 | $ | 15,343 |
· | the domestic and foreign supply of oil and natural gas; |
· | the price and availability of alternative fuels; |
· | weather conditions; |
· | the level of consumer demand; |
· | the price of foreign imports; |
· | world-wide economic conditions; |
· | political conditions in oil and gas producing regions; |
· | the change in the value of the U.S. dollar as global oil prices are priced in U. S. dollars; and |
· | domestic and foreign governmental regulations. |
· | the quality and quantity of available data; |
· | the interpretation of that data; |
· | the accuracy of various mandated economic assumptions; and |
· | the judgment of the persons preparing the estimate. |
· | reserves; |
· | future oil and gas prices; |
· | operating costs; |
· | title to properties; and |
· | potential environmental and other liabilities. |
· | obtaining government and tribal required permits; |
· | unexpected drilling conditions; |
· | pressure or irregularities in formations; |
· | equipment failures or accidents; |
· | adverse weather conditions; |
· | compliance with governmental or landowner requirements; and |
· | shortages or delays in the availability of drilling rigs and the delivery of equipment. |
· | fires; |
· | explosions; |
· | blow-outs; |
· | uncontrollable flows of oil, gas, formation water or drilling fluids; |
· | natural disasters; |
· | pipe or cement failures; |
· | casing collapses; |
· | embedded oilfield drilling and service tools; |
· | abnormally pressured formations; |
· | major equipment failures, including cogeneration facilities; and |
· | environmental hazards such as oil spills, natural gas leaks, pipeline ruptures and discharges of toxic gases. |
· | injury or loss of life; |
· | severe damage or destruction of property, natural resources and equipment; |
· | pollution and other environmental damage; |
· | investigatory and clean-up responsibilities; |
· | regulatory investigation and penalties; |
· | suspension of operations; and |
· | repairs to resume operations. |
Item 7A. | Quantitativeand Qualitative Disclosures About Market Risk |
Impact of percent change in futures prices | ||||||||||||||||
12/31/04 | on earnings (in thousands) | |||||||||||||||
NYMEX Futures | -30% | -15% | + 15% | + 30% | ||||||||||||
Average WTI Price | $ | 42.66 | $ | 29.86 | $ | 36.26 | $ | 49.05 | $ | 55.45 | ||||||
Crude Oil gain/(loss) | (5,098 | ) | 31,102 | 13,002 | (23,199 | ) | (41,299 | ) | ||||||||
Average HH Price | 6.32 | 4.43 | 5.38 | 7.27 | 8.22 | |||||||||||
Natural Gas gain/(loss) | 2,625 | (3,216 | ) | (295 | ) | 5,545 | 8,466 |
Item 8. | FinancialStatements and Supplementary Data |
Page | |
Report of PricewaterhouseCoopers LLP, an Independent Registered Public Accounting Firm | 41 |
Balance Sheets at December 31, 2004 and 2003 | 42 |
Statements of Income for the Years Ended December 31, 2004, 2003 and 2002 | 43 |
Statements of Comprehensive Income for the Years Ended December 31, 2004, 2003 and 2002 | 43 |
Statements of Shareholders' Equity for the Years Ended December 31, 2004, 2003 and 2002 | 44 |
Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002 | 45 |
Notes to the Financial Statements | 46 |
Supplemental Information About Oil & Gas Producing Activities (unaudited) | 64 |
2004 | 2003 | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 16,690 | $ | 10,658 | |||
Short-term investments available for sale | 659 | 663 | |||||
Accounts receivable | 34,621 | 23,506 | |||||
Deferred income taxes | 3,558 | 6,410 | |||||
Fair value of derivatives | 3,243 | - | |||||
Prepaid expenses and other | 2,230 | 2,049 | |||||
Total current assets | 61,001 | 43,286 | |||||
Oil and gas properties (successful efforts basis),buildings and equipment, net | 338,706 | 295,151 | |||||
Deposits on potential property acquisitions | 10,221 | - | |||||
Other assets | 2,176 | 1,940 | |||||
$ | 412,104 | $ | 340,377 | ||||
LIABILITIES AND SHAREHOLDERS' EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 27,750 | $ | 20,867 | |||
Revenue and royalties payable | 23,945 | 11,623 | |||||
Accrued liabilities | 6,132 | 4,214 | |||||
Income taxes payable | 1,067 | 4,412 | |||||
Fair value of derivatives | 5,947 | 5,710 | |||||
Total current liabilities | 64,841 | 46,826 | |||||
Long-term liabilities: | |||||||
Deferred income taxes | 47,963 | 38,559 | |||||
Long-term debt | 28,000 | 50,000 | |||||
Abandonment obligation | 8,214 | 7,311 | |||||
Fair value of derivatives | - | 343 | |||||
84,177 | 96,213 | ||||||
Commitments and contingencies (Notes 10 and 11) | |||||||
Shareholders' equity: | |||||||
Preferred stock, $.01 par value, 2,000,000 shares authorized;no shares outstanding | - | - | |||||
Capital stock, $.01 par value: | |||||||
Class A Common Stock, 50,000,000 shares authorized;21,060,420 shares issued and outstanding (20,904,372 in 2003) | 210 | 209 | |||||
Class B Stock, 1,500,000 shares authorized;898,892 shares issued and outstanding (liquidation preference of $899) | 9 | 9 | |||||
Capital in excess of par value | 60,676 | 56,475 | |||||
Deferred stock-based compensation | - | (1,108 | ) | ||||
Accumulated other comprehensive loss | (987 | ) | (3,632 | ) | |||
Retained earnings | 203,178 | 145,385 | |||||
Total shareholders' equity | 263,086 | 197,338 | |||||
$ | 412,104 | $ | 340,377 |
2004 | 2003 | 2002 | ||||||||
Revenues: | ||||||||||
Sales of oil and gas | $ | 226,876 | $ | 135,848 | $ | 102,026 | ||||
Sales of electricity | 47,644 | 44,200 | 27,691 | |||||||
Interest and dividend income | 261 | 236 | 536 | |||||||
Other income | 165 | 580 | 1,116 | |||||||
274,946 | 180,864 | 131,369 | ||||||||
Expenses: | ||||||||||
Operating costs – oil and gas production | 82,419 | 62,554 | 45,217 | |||||||
Operating costs – electricity generation | 46,191 | 42,351 | 26,747 | |||||||
Depreciation, depletion & amortization - oil and gas | 29,752 | 17,258 | 13,388 | |||||||
Depreciation, depletion & amortization - electricity generation | 3,490 | 3,256 | 3,064 | |||||||
General and administrative | 20,354 | 12,868 | 9,215 | |||||||
Interest | 2,067 | 1,414 | 1,042 | |||||||
Loss on disposal of assets | 410 | - | - | |||||||
Dry hole, abandonment and impairment | 745 | 4,195 | - | |||||||
Recovery of electricity receivable | - | - | (3,631 | ) | ||||||
185,428 | 143,896 | 95,042 | ||||||||
Income before income taxes | 89,518 | 36,968 | 36,327 | |||||||
Provision for income taxes | 20,331 | 4,605 | 7,117 | |||||||
Net income | $ | 69,187 | $ | 32,363 | $ | 29,210 | ||||
Basic net income per share | $ | 3.16 | $ | 1.49 | $ | 1.34 | ||||
Diluted net income per share | $ | 3.08 | $ | 1.47 | $ | 1.33 | ||||
Weighted average number of shares of capital stock outstanding (used to calculate basic net income per share) | 21,894 | 21,772 | 21,741 | |||||||
Effect of dilutive securities: | ||||||||||
Stock options | 523 | 215 | 115 | |||||||
Other | 53 | 44 | 46 | |||||||
Weighted average number of shares of capital stock used to calculate diluted net income per share | 22,470 | 22,031 | 21,902 | |||||||
Statements of Comprehensive Income | ||||||||||
Years Ended December 31, 2004, 2003 and 2002 | ||||||||||
(In Thousands) | ||||||||||
Net income | $ | 69,187 | $ | 32,363 | $ | 29,210 | ||||
Unrealized gains (losses) on derivatives, net of incometaxes of ($521), ($709), and ($1,712) | (781 | ) | (3,632 | ) | (2,569 | ) | ||||
Reclassification of unrealized losses included in net incomenet of income taxes of $2,284, $1,712 and $0 | 3,426 | 2,569 | - | |||||||
Comprehensive income | $ | 71,832 | $ | 31,300 | $ | 26,641 |
Class A | Class B | Par Value | Compensation | Earnings | Comprehensive Income (Loss) | Equity | ||||||||||||||||
Balances at January 1, 2002 | $ | 208 | $ | 9 | $ | 50,730 | $ | (101 | ) | $ | 102,745 | $ | - | $ | 153,591 | |||||||
Accrued compensation costs | 1 | - | 1,149 | - | - | - | 1,150 | |||||||||||||||
Deferred director fees – stockcompensation | - | - | 190 | - | - | - | 190 | |||||||||||||||
Unearned stock-basedcompensation | - | - | 245 | (245 | ) | - | - | - | ||||||||||||||
Retirement of warrants | - | - | (100 | ) | - | - | - | (100 | ) | |||||||||||||
Cash dividends declared -$.40 per share | - | - | - | - | (8,698 | ) | - | (8,698 | ) | |||||||||||||
Unrealized losses on derivatives | - | - | - | - | - | (2,569 | ) | (2,569 | ) | |||||||||||||
Net income | - | - | - | - | 29,210 | - | 29,210 | |||||||||||||||
Balances at December 31, 2002 | 209 | 9 | 52,214 | (346 | ) | 123,257 | (2,569 | ) | 172,774 | |||||||||||||
Accrued compensation costs | - | - | 3,319 | - | - | - | 3,319 | |||||||||||||||
Deferred director fees – stockcompensation | - | - | 169 | - | - | - | 169 | |||||||||||||||
Unearned stock-basedcompensation | - | - | 773 | (773 | ) | - | - | - | ||||||||||||||
Amortization of deferred stockoption compensation | - | - | - | 11 | - | - | 11 | |||||||||||||||
Cash dividends declared -$.47 per share | - | - | - | - | (10,235 | ) | - | (10,235 | ) | |||||||||||||
Unrealized losses on derivatives | - | - | - | - | - | (1,063 | ) | (1,063 | ) | |||||||||||||
Net income | - | - | - | - | 32,363 | - | 32,363 | |||||||||||||||
Balances at December 31, 2003 | 209 | 9 | 56,475 | (1,108 | ) | 145,385 | (3,632 | ) | 197,338 | |||||||||||||
Adoption of SFAS 123 | - | - | (243 | ) | 1,108 | - | - | 865 | ||||||||||||||
Stock-based compensationcosts | 1 | - | 3,451 | - | - | - | 3,452 | |||||||||||||||
Deferred director fees – stockcompensation | - | - | 993 | - | - | - | 993 | |||||||||||||||
Cash dividends declared -$.52 per share | - | - | - | - | (11,394 | ) | - | (11,394 | ) | |||||||||||||
Unrealized gain onderivatives | - | - | - | - | - | 2,645 | 2,645 | |||||||||||||||
Net income | - | - | - | - | 69,187 | - | 69,187 | |||||||||||||||
Balances at December 31, 2004 | $ | 210 | $ | 9 | $ | 60,676 | $ | - | $ | 203,178 | $ | (987 | ) | $ | 263,086 |
2004 | 2003 | 2002 | ||||||||
Cash flows from operating activities: | ||||||||||
Net income | $ | 69,187 | $ | 32,363 | $ | 29,210 | ||||
Depreciation, depletion and amortization | 33,242 | 20,514 | 16,452 | |||||||
Dry hole, abandonment and impairment | (569 | ) | 3,756 | - | ||||||
Stock-based compensation expense | 5,309 | 2,872 | 1,093 | |||||||
Deferred income taxes | 10,815 | 1,496 | 3,883 | |||||||
Loss on disposal of assets | 410 | - | - | |||||||
Other, net | 384 | 400 | (184 | ) | ||||||
Decrease (increase) in current assets other than cash, cash equivalents and short-term investments | (11,310 | ) | (9,034 | ) | 1,469 | |||||
Increase (decrease) in current liabilities | 17,145 | 12,458 | 5,972 | |||||||
Net cash provided by operating activities | 124,613 | 64,825 | 57,895 | |||||||
Cash flows from investing activities: | ||||||||||
Capital expenditures, excluding property acquisitions | (72,225 | ) | (41,555 | ) | (30,632 | ) | ||||
Property acquisitions | (2,845 | ) | (48,579 | ) | (5,880 | ) | ||||
Deposits on potential acquisitions | (10,221 | ) | - | - | ||||||
Proceeds from sale of assets | 101 | 1,890 | - | |||||||
Purchase of short-term investments | - | (3 | ) | (660 | ) | |||||
Maturities of short-term investments | 3 | - | 594 | |||||||
Other, net | - | 524 | 52 | |||||||
Net cash used in investing activities | (85,187 | ) | (87,723 | ) | (36,526 | ) | ||||
Cash flows from financing activities: | ||||||||||
Proceeds from issuance of long-term debt | - | 40,000 | 5,000 | |||||||
Payment of long-term debt | (22,000 | ) | (5,000 | ) | (15,000 | ) | ||||
Dividends paid | (11,394 | ) | (10,235 | ) | (8,698 | ) | ||||
Other, net | - | (1,075 | ) | (43 | ) | |||||
Net cash provided by (used in) financing activities | (33,394 | ) | 23,690 | (18,741 | ) | |||||
Net increase in cash and cash equivalents | 6,032 | 792 | 2,628 | |||||||
Cash and cash equivalents at beginning of year | 10,658 | 9,866 | 7,238 | |||||||
Cash and cash equivalents at end of year | $ | 16,690 | $ | 10,658 | $ | 9,866 | ||||
Supplemental disclosures of cash flow information: | ||||||||||
Interest paid | $ | 1,243 | $ | 2,125 | $ | 1,321 | ||||
Income taxes paid | $ | 11,652 | $ | 2,510 | $ | 5,420 | ||||
Supplemental non-cash activity: | ||||||||||
Increase (decrease) in fair value of derivatives: | ||||||||||
Current (net of income taxes of $1,202, ($635), and ($1,649)) | $ | 1,804 | $ | (952 | ) | $ | (2,474 | ) | ||
Non-current (net of income taxes of $561, ($74), and ($63)) | 841 | (111 | ) | (95 | ) | |||||
Net increase(decrease) to accumulated other comprehensive income | $ | 2,645 | $ | (1,063 | ) | $ | (2,569 | ) |
1. | General |
2. | Summary of Significant Accounting Policies |
2. | Summary of Significant Accounting Policies (cont'd) |
2. | Summary of Significant Accounting Policies (cont'd) |
2. | Summary of Significant Accounting Policies (cont'd) |
2003 | 2002 | ||||||
Net income, as reported | $ | 32,363 | $ | 29,210 | |||
Plus compensation cost (net of tax), as reported | 2,335 | 806 | |||||
Less compensation cost (net of tax), pro forma | (1,323 | ) | (701 | ) | |||
Net income, pro forma | $ | 33,375 | $ | 29,315 | |||
Basic net income per share: | |||||||
As reported | $ | 1.49 | $ | 1.34 | |||
Pro forma | 1.53 | 1.35 | |||||
Diluted net income per share: | |||||||
As reported | $ | 1.47 | $ | 1.33 | |||
Pro forma | 1.52 | 1.34 |
2003 | 2002 | ||||||
Yield | 2.87 | % | 2.55 | % | |||
Expected option life – years | 7.0 | 7.5 | |||||
Volatility | 27.87 | % | 33.45 | % | |||
Risk-free interest rate | 3.86 | % | 4.09 | % |
2. | Summary of Significant Accounting Policies (cont'd) |
2003 | 2002 | ||||||
Operating costs - oil and gas | |||||||
As previously reported | $ | 60,705 | $ | 44,604 | |||
As revised | 62,554 | 45,217 | |||||
Difference | $ | 1,849 | $ | 613 | |||
Operating costs - electricity generation | |||||||
As previously reported | $ | 44,200 | $ | 27,360 | |||
As revised | 42,351 | 26,747 | |||||
Difference | $ | (1,849 | ) | $ | (613 | ) | |
DD&A - oil and gas | |||||||
As previously reported | $ | 20,514 | $ | 16,452 | |||
As revised | 17,258 | 13,388 | |||||
Difference | $ | (3,256 | ) | $ | (3,064 | ) | |
DD&A - electricity generation | |||||||
As previously reported | $ | - | $ | - | |||
As revised | 3,256 | 3,064 | |||||
Difference | $ | 3,256 | $ | 3,064 | |||
3. | Fair Value of Financial Instruments |
4. | Concentration of Credit Risks |
4. | Concentration of Credit Risks |
Sales | ||||||||||||||||
Accounts Receivable | For the Year Ended December 31, | |||||||||||||||
Customer | December 31, 2004 | December 31, 2003 | 2004 | 2003 | 2002 | |||||||||||
Oil & Gas Sales: | ||||||||||||||||
A | $ | 18,391 | $ | 12,887 | $ | 202,966 | $ | 142,422 | $ | 94,870 | ||||||
B | 5,465 | 2,256 | 58,807 | 5,566 | - | |||||||||||
C | 670 | 625 | 9,138 | 6,524 | - | |||||||||||
D | - | - | - | 680 | 5,463 | |||||||||||
E | - | - | - | - | 10,188 | |||||||||||
$ | 24,526 | $ | 15,768 | $ | 270,911 | $ | 155,192 | $ | 110,521 | |||||||
Electricity Sales: | ||||||||||||||||
F | $ | 3,402 | $ | 2,156 | $ | 21,755 | $ | 20,334 | $ | 15,199 | ||||||
G | 2,764 | 2,970 | 26,524 | 24,616 | - | |||||||||||
H | - | - | - | 265 | 12,317 | |||||||||||
$ | 6,166 | $ | 5,126 | $ | 48,279 | $ | 45,215 | $ | 27,516 |
5. | Oil and Gas Properties, Buildings and Equipment |
2004 | 2003 | ||||||
Oil and gas: | |||||||
Proved properties: | |||||||
Producing properties, including intangible drilling costs | $ | 260,566 | $ | 237,677 | |||
Lease and well equipment(1) | 238,778 | 191,092 | |||||
499,344 | 428,769 | ||||||
Unproved properties | |||||||
Properties, including intangible drilling costs | 5,569 | 3,710 | |||||
Lease and well equipment | 2,498 | 582 | |||||
8,067 | 4,292 | ||||||
507,411 | 433,061 | ||||||
Less accumulated depreciation, depletion and amortization | 170,606 | 139,514 | |||||
336,805 | 293,547 | ||||||
Commercial and other: | |||||||
Land | 297 | 174 | |||||
Buildings and improvements | 3,703 | 3,703 | |||||
Machinery and equipment | 4,835 | 4,266 | |||||
8,835 | 8,143 | ||||||
Less accumulated depreciation | 6,934 | 6,539 | |||||
1,901 | 1,604 | ||||||
$ | 338,706 | $ | 295,151 | ||||
(1)Includes cogeneration facility costs. |
2004 | 2003 | 2002 | ||||||||
Property acquisitions | ||||||||||
Proved properties | $ | 440 | $ | 49,326 | $ | 186 | ||||
Unproved properties | 2,405 | 853 | 5,694 | |||||||
Development(1) | 66,664 | 42,391 | 29,133 | |||||||
Exploration | 5,506 | 788 | 1,684 | |||||||
$ | 75,015 | $ | 93,358 | $ | 36,697 |
5. | Oil and Gas Properties, Buildings and Equipment (Cont'd) |
Results of operations from oil and gas producing | 2004 | 2003 | 2002 | |||||||
and exploration activities (in thousands): | ||||||||||
Sales to unaffiliated parties | $ | 226,876 | $ | 135,848 | $ | 102,026 | ||||
Production costs | (82,419 | ) | (62,554 | ) | (45,217 | ) | ||||
Depreciation, depletion and amortization | (29,752 | ) | (17,258 | ) | (13,388 | ) | ||||
Dry hole, abandonment and impairment | (745 | ) | (4,195 | ) | - | |||||
113,960 | 51,841 | 43,421 | ||||||||
Income tax expenses | (32,875 | ) | (8,426 | ) | (8,341 | ) | ||||
Results of operations from producing and exploration activities | $ | 81,085 | $ | 43,415 | $ | 35,080 |
2004 | 2003 | 2002 | ||||||||
Beginning balance at January 1 | $ | 511 | $ | 1,684 | $ | - | ||||
Additions to capitalized exploratory well costs pending the determination of proved reserves | 3,420 | 1,081 | 1,684 | |||||||
Reclassifications to wells, facilities and equipment based on the determination of proved reserves | - | - | - | |||||||
Capitalized exploratory well costs charged to expense | 479 | 2,254 | - | |||||||
Ending balance at December 31 | $ | 3,452 | $ | 511 | $ | 1,684 |
The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of wells for which exploratory well costs have been capitalized for a period of greater than one year since the completion of drilling (in thousands):
2004 | 2003 | 2002 | ||||||||
Capitalized exploratory well costs that have beencapitalized for a period of one year or less | $ | 2,941 | $ | 511 | $ | 1,684 | ||||
Capitalized exploratory well costs that have beencapitalized for a period greater than one year | 511 | - | - | |||||||
Balance at December 31 | $ | 3,452 | $ | 511 | $ | 1,684 | ||||
Number of projects that have exploratory well costs thathave been capitalized for a period of greater than one year | 1 | - | - |
5. | Oil and Gas Properties, Buildings and Equipment (Cont'd) |
6. | Debt Obligations |
2004 | 2003 | ||||||
Long-term debt for the years ended December 31 (in thousands): | |||||||
Revolving bank facility | $ | 28,000 | $ | 50,000 |
7. | Shareholders' Equity |
Number of Shares | |||||||
Class A | Class B | ||||||
December 31, 2001 | 20,833,094 | 898,892 | |||||
Option exercises | 19,717 | - | |||||
Shares cancelled | (98 | ) | - | ||||
Shares repurchased and retired | (18 | ) | - | ||||
December 31, 2002 | 20,852,695 | 898,892 | |||||
Option exercises | 51,683 | - | |||||
Shares repurchased and retired | (6 | ) | - | ||||
December 31, 2003 | 20,904,372 | 898,892 | |||||
Option exercises | 155,269 | - | |||||
Shares issued under Director deferred compensation plan | 797 | - | |||||
Shares repurchased and retired | (18 | ) | - | ||||
December 31, 2004 | 21,060,420 | 898,892 |
7. | Shareholders' Equity (Cont’d) |
8. | Asset Retirement Obligations |
2004 | 2003 | ||||||
Beginning balance at January 1 | $ | 7,311 | $ | 4,596 | |||
Liabilities incurred | 769 | 2,623 | |||||
Liabilities settled | (570 | ) | (439 | ) | |||
Accretion expense | 704 | 531 | |||||
Ending balance at December 31 | $ | 8,214 | $ | 7,311 |
9. | Income Taxes |
2004 | 2003 | 2002 | ||||||||
Current: | ||||||||||
Federal | $ | 7,073 | $ | 2,490 | $ | 2,340 | ||||
State | 2,443 | 619 | 894 | |||||||
9,516 | 3,109 | 3,234 | ||||||||
Deferred: | ||||||||||
Federal | 11,959 | 2,027 | 4,286 | |||||||
State | (1,144 | ) | (531 | ) | (403 | ) | ||||
10,815 | 1,496 | 3,883 | ||||||||
Total | $ | 20,331 | $ | 4,605 | $ | 7,117 |
2004 | 2003 | ||||||
Deferred tax asset: | |||||||
Federal benefit of state taxes | $ | 1,308 | $ | 318 | |||
Credit carryforwards | 26,478 | 23,440 | |||||
Stock option costs | 1,700 | 2,185 | |||||
Derivatives | 658 | 2,421 | |||||
Other, net | 1,610 | 1,488 | |||||
31,754 | 29,852 | ||||||
Deferred tax liability: | |||||||
Depreciation and depletion | (76,311 | ) | (61,425 | ) | |||
Other, net | 152 | (253 | ) | ||||
(76,159 | ) | (61,678 | ) | ||||
Net deferred tax liability | $ | (44,405 | ) | $ | (31,826 | ) |
9. | Income Taxes (Cont'd) |
2004 | 2003 | 2002 | ||||||||
Tax computed at statutory federal rate | 35 | % | 35 | % | 35 | % | ||||
State income taxes, net of federal benefit | 1 | 1 | 1 | |||||||
Tax credits | (9 | ) | (24 | ) | (15 | ) | ||||
Recognition of tax basis of properties | (5 | ) | - | - | ||||||
Other | 1 | - | (1 | ) | ||||||
Effective tax rate | 23 | % | 12 | % | 20 | % |
10. | Commitments |
Year ending December 31, | ||||
2005 | $ | 621 | ||
2006 | 538 | |||
2007 | 138 | |||
2008 | 108 | |||
2009 | 18 | |||
Total | $ | 1,423 |
10. | Commitments (Cont'd) |
Year ending December 31, | |||||
2005 | $ | 2,814 | |||
2006 | 2,814 | ||||
2007 | 2,814 | ||||
2008 | 2,814 | ||||
2009 | 2,814 | ||||
Thereafter | 9,368 | ||||
Total | $ | 23,438 |
11. | Contingencies |
12. | Stock Option Plan |
12. | Stock Option Plan (Cont'd) |
2004 | ||
Expected volatility | 25% | |
Weighted-average volatility | 25% | |
Expected dividends | 1.27% - 2.45% | |
Expected term (in years) | 4 - 7 | |
Risk-free rate | 3.4% - 4.4% |
2004 | 2003 | 2002 | ||||||||
Options | Options | Options | ||||||||
Balance outstanding, January 1 | 1,701,925 | 1,604,575 | 1,474,962 | |||||||
Granted | 567,750 | 411,500 | 241,200 | |||||||
Exercised | (581,550 | ) | (294,150 | ) | (95,837 | ) | ||||
Canceled/expired | (122,500 | ) | (20,000 | ) | (15,750 | ) | ||||
Balance outstanding, December 31 | 1,565,625 | 1,701,925 | 1,604,575 | |||||||
Balance exercisable at December 31 | 688,275 | 1,037,275 | 1,153,000 | |||||||
Available for future grant | - | 615,600 | 1,007,100 | |||||||
Weighted average remaining contractuallife (years) | 8 | 7 | 7 | |||||||
Weighted average fair value peroption granted during the year basedon the Black-Scholes pricing model | $ | 10.10 | $ | 5.11 | $ | 5.25 |
12. | Stock Option Plan (Cont'd) |
Weighted | ||||||||||
Weighted | Average | Weighted | ||||||||
Range of | Average | Remaining | Average | |||||||
Exercise | Options | Exercise | Contractual | Options | Exercise | |||||
Prices | Outstanding | Price | Life | Exercisable | Price | |||||
$10.63 - $22.50 | 997,875 | $ 16.76 | 6.9 | 648,275 | $ 16.01 | |||||
$22.51 - $34.00 | 103,500 | 28.79 | 9.5 | - | - | |||||
$34.01 - $45.50 | 464,250 | 43.23 | 9.9 | 40,000 | 43.54 | |||||
$10.63 - $45.50 | 1,565,625 | $ 25.41 | 8.0 | 688,275 | $ 17.61 |
2004 | 2003 | 2002 | ||||||||
Outstanding at January 1 | $ | 16.50 | $ | 15.17 | $ | 14.80 | ||||
Granted during the year | 40.60 | 19.31 | 16.14 | |||||||
Exercised during the year | 15.73 | 13.15 | 11.87 | |||||||
Cancelled/expired during the year | 18.02 | 16.55 | 15.92 | |||||||
Outstanding at December 31 | 25.41 | 16.50 | 15.17 | |||||||
Exercisable at December 31 | 17.61 | 15.62 | 14.81 |
13. | 401(k) Plan |
14. | Director Deferred Compensation Plan |
15. | Hedging |
With respect to the Company's hedging activities, the Company utilizes more than one Conterparty on its hedges and monitors each counterparty's credit rating.
16. | Quarterly Financial Data (unaudited) |
Basic Net | Diluted Net | |||||||||||||||
Operating | Gross | Net | Income | Income | ||||||||||||
2004 | Revenues | Profit | Income | Per Share | Per Share | |||||||||||
First Quarter | $ | 57,139 | $ | 19,976 | $ | 10,364 | $ | 0.48 | $ | 0.47 | ||||||
Second Quarter | 64,046 | 25,057 | 15,278 | 0.70 | 0.68 | |||||||||||
Third Quarter | 72,904 | 31,130 | 18,229 | 0.83 | 0.82 | |||||||||||
Fourth Quarter(1) | 80,431 | 36,505 | 25,316 | 1.15 | 1.13 | |||||||||||
$ | 274,520 | $ | 112,668 | $ | 69,187 | $ | 3.16 | $ | 3.08 | |||||||
2003 | ||||||||||||||||
First Quarter | $ | 46,766 | $ | 16,790 | $ | 10,275 | $ | 0.47 | $ | 0.47 | ||||||
Second Quarter | 39,372 | 9,187 | 4,905 | 0.23 | 0.22 | |||||||||||
Third Quarter | 44,108 | 11,842 | 7,827 | 0.36 | 0.35 | |||||||||||
Fourth Quarter | 49,802 | 17,110 | 9,356 | 0.43 | 0.42 | |||||||||||
$ | 180,048 | $ | 54,929 | $ | 32,363 | $ | 1.49 | $ | 1.47 |
17. | Subsequent Events (unaudited) |
2004 | 2003 | 2002 | ||||||||||||||||||||||||||
Oil | Gas | Oil | Gas | Oil | Gas | |||||||||||||||||||||||
Mbbls | Mmcf | BOE | Mbbls | Mmcf | BOE | Mbbls | Mmcf | BOE | ||||||||||||||||||||
Proved developed and | ||||||||||||||||||||||||||||
Undeveloped reserves: | ||||||||||||||||||||||||||||
Beginning of year | 106,640 | 19,680 | 109,920 | 100,744 | 5,850 | 101,719 | 101,701 | 6,926 | 102,855 | |||||||||||||||||||
Revision of previous estimates | 2,974 | 8,246 | 4,348 | (82 | ) | 293 | (33 | ) | (30 | ) | (307 | ) | (81 | ) | ||||||||||||||
Improved recovery | 2,021 | - | 2,021 | 1,271 | - | 1,271 | 752 | - | 752 | |||||||||||||||||||
Extensions and discoveries | 2,736 | 714 | 2,855 | 1,853 | 2,005 | 2,187 | 3,444 | - | 3,444 | |||||||||||||||||||
Property sales | (127 | ) | (77 | ) | (140 | ) | - | - | - | - | - | - | ||||||||||||||||
Production | (7,043 | ) | (2,839 | ) | (7,516 | ) | (5,827 | ) | (1,277 | ) | (6,040 | ) | (5,123 | ) | (769 | ) | (5,251 | ) | ||||||||||
Purchase of reserves in place | 132 | - | 132 | 8,681 | 12,809 | 10,816 | - | - | - | |||||||||||||||||||
Royalties converted to working interest (1) | (1,784 | ) | - | (1,784 | ) | - | - | - | - | - | - | |||||||||||||||||
End of year | 105,549 | 25,724 | 109,836 | 106,640 | 19,680 | 109,920 | 100,744 | 5,850 | 101,719 | |||||||||||||||||||
Proved developed reserves: | ||||||||||||||||||||||||||||
Beginning of year | 78,145 | 12,207 | 80,180 | 72,889 | 3,252 | 73,431 | 79,317 | 3,518 | 79,903 | |||||||||||||||||||
End of year | 78,207 | 20,048 | 81,549 | 78,145 | 12,207 | 80,180 | 72,889 | 3,252 | 73,431 |
(1) In December 2004 certain royalty owners exercised their right to convert their royalty interest into a working interest on the Company's Formax property in the Midway-Sunset field. This resulted in a reduction to the Company of 1.8 million barrels of reserves and represents approximately 450 BOE/day at year end production levels. The Company has no other similar conversion rights by any other current royalty owners.
2004 | 2003 | 2002 | ||||||||
Future cash inflows | $ | 3,281,155 | $ | 2,845,767 | $ | 2,533,410 | ||||
Future production costs | (1,405,432 | ) | (1,246,340 | ) | (1,179,100 | ) | ||||
Future development costs | (216,859 | ) | (198,279 | ) | (134,766 | ) | ||||
Future income tax expenses | (355,764 | ) | (324,097 | ) | (305,485 | ) | ||||
Future net cash flows | 1,303,100 | 1,077,051 | 914,059 | |||||||
10% annual discount for estimated timing of cash flows | (616,352 | ) | (548,831 | ) | (464,202 | ) | ||||
Standardized measure of discounted future net cash flows | $ | 686,748 | $ | 528,220 | $ | 449,857 | ||||
Average sales prices at December 31: | ||||||||||
Oil ($/Bbl) | $ | 29.49 | $ | 25.77 | $ | 24.92 | ||||
Gas ($/Mcf) | $ | 6.61 | $ | 4.94 | $ | 3.94 | ||||
BOE Price | $ | 29.87 | $ | 25.89 | $ | 24.91 |
2004 | 2003 | 2002 | ||||||||
Standardized measure - beginning of year | $ | 528,220 | $ | 449,857 | $ | 278,453 | ||||
Sales of oil and gas produced, net of production costs | (144,457 | ) | (75,143 | ) | (57,422 | ) | ||||
Revisions to estimates of proved reserves: | ||||||||||
Net changes in sales prices and production costs | 190,861 | 45,292 | 276,417 | |||||||
Revisions of previous quantity estimates | 40,419 | (229 | ) | (550 | ) | |||||
Improved recovery | 18,787 | 9,400 | 5,063 | |||||||
Extensions and discoveries | 26,541 | 16,171 | 23,189 | |||||||
Change in estimated future development costs | (56,314 | ) | (75,841 | ) | (74,566 | ) | ||||
Purchases of reserves in place | 962 | 47,700 | - | |||||||
Sales of reserves in place | (1,043 | ) | ||||||||
Development costs incurred during the period | 65,971 | 41,461 | 30,632 | |||||||
Accretion of discount | 68,312 | 59,983 | 35,865 | |||||||
Income taxes | (16,890 | ) | (8,896 | ) | (62,531 | ) | ||||
Other | (21,430 | ) | 18,465 | (4,693 | ) | |||||
Royalties converted to working interest (1) | (13,191 | ) | - | - | ||||||
Net increase | 158,528 | 78,363 | 171,404 | |||||||
Standardized measure - end of year | $ | 686,748 | $ | 528,220 | $ | 449,857 |
(1) In December 2004 certain royalty owners exercised their right to convert their royalty interest into a working interest on the Company's Formax property in the Midway-Sunset field. This resulted in a reduction to the Company of 1.8 million barrels of reserves and represents approximately 450 BOE/day at year end production levels. The Company has no other similar conversion rights by any other current royalty owners.
Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
Item 9A. | Controlsand Procedures |
· | pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the Company's assets; |
· | provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of the Company's Management and Directors; and |
· | provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements. |
Item 9B. | Other Information |
Item 10. | Directorsand Executive Officers of the Registrant |
Item 11. | ExecutiveCompensation |
Item 12. | Security Ownership of Certain Beneficial Owners and Management |
Item 13. | Certain Relationships and Related Transactions |
Item 14. | PrincipalAccounting Fees and Services |
Item 15 | Exhibits, Financial Statement Schedules |
Exhibit No. | Description of Exhibit |
3.1* | Registrant's Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Registrant's Registration Statement on Form S-1 filed on June 7, 1989, File No. 33-29165) |
3.2* | Registrant's Restated Bylaws (filed as Exhibit 3.2 to the Registrant's Registration Statement on Form S-1 on June 7, 1989, File No. 33-29165) |
3.3* | Registrant's Certificate of Designation, Preferences and Rights of Series B Junior Participating Preferred Stock (filed as Exhibit A to the Registrant's Registration Statement on Form 8-A12B on December 7, 1999, File No. 778438-99-000016) |
3.4* | Registrant's First Amendment to Restated Bylaws dated August 31, 1999 (filed as Exhibit 3.4 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-9735) |
3.5 | Bylaws, as amended, dated February 24, 2005 |
4.1* | Rights Agreement between Registrant and ChaseMellon Shareholder Services, L.L.C. dated as of December 8, 1999 (filed by the Registrant on Form 8-A12B on December 7, 1999, File No. 778438-99-000016) |
10.1* | Description of Cash Bonus Plan of Berry Petroleum Company (filed as Exhibit 10.1 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2001, File No. 1-9735). |
10.2* | Form of Salary Continuation Agreement dated as of December 5, 1997, by and between Registrant and Ralph J. Goehring (filed as Exhibit 10.3 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1997, File No. 1-9735) |
10.3* | Form of Salary Continuation Agreements dated as of March 20, 1987, as amended August 28, 1987, by and between Registrant and selected employees of the Company (filed as Exhibit 10.12 to the Registration Statement on Form S-1 filed on June 7, 1989, File No. 33-29165) |
10.4* | Instrument for Settlement of Claims and Mutual Release by and among Registrant, Victory Oil Company, the Crail Fund and Victory Holding Company effective October 31, 1986 (filed as Exhibit 10.13 to Amendment No. 1 to the Registrant's Registration Statement on Form S-4 filed on May 22, 1987, File No. 33-13240) |
10.5* | Credit Agreement, dated as of July 10, 2003, by and between the Registrant and Wells Fargo Bank, N.A. and other financial institutions (filed as Exhibit 10.7 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2003, File No. 1-9735) |
10.6* | Amended and Restated 1994 Stock Option Plan (filed as Exhibit 4.1 to the Registrant’s Registration Statement on Form S-8 filed on August 20, 2002, File No. 333-98379) |
10.7** | Crude oil purchase contract, dated as of August 1, 2002, by and between the Registrant and Equiva Trading Company (filed as Exhibit 10.9 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-9735). |
Exhibit No. | Description of Exhibit |
10.8 | Amended and Restated Non-Employee Director Deferred Stock and Compensation Plan |
10.9* | Purchase and sale agreement between the Registrant and Williams Production Company (filed as Exhibit 10.11 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2003, File No. 1-9735) |
10.10* | Employment Contract dated as of June 16, 2004 by and between the Registrant and Robert F. Heinemann (filed as Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File No. 1-9735) |
10.11* | Salary Continuation Agreement dated as of June 16, 2004 by and between the Registrant and Robert F. Heinemann (filed as Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File No. 1-9735) |
10.12* | Purchase and sale agreement between the Registrant and J-W Operating Company (filed as Exhibit 99.2 to the Registrant's Current Report on Form 8-K/A filed on February 15, 2005, File No. 1-9735) |
23.1 | Consent of PricewaterhouseCoopers LLP, Independent Registered Accounting Firm |
23.2 | Consent of DeGolyer and MacNaughton |
31.1 | Certification of Chief Executive Officer pursuant to SEC Rule 13(a)-14(a) |
31.2 | Certification of Chief Financial Officer pursuant to SEC Rule 13(a)-14(a) |
32.1 | Certification of Chief Executive Officer pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code |
32.2 | Certification of Chief Financial Officer pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code |
99.1 | Form of Indemnity Agreement of Registrant |
99.2* | Form of "B" Group Trust (filed as Exhibit 28.3 to Amendment No. 1 to Registrant's Registration Statement on Form S-4 filed on May 22, 1987, File No. 33-13240) |
* Incorporated by reference | |
** Pursuant to 17CFR240.24b-2, confidential information has been omitted and has been filed separately with the Securities and Exchange Commission, pursuant to a Confidential Treatment Request filed with the Commission. |
/s/ Robert F. Heinemann | /s/ Ralph J. Goehring | /s/ Donald A. Dale |
ROBERT F. HEINEMANN | RALPH J. GOEHRING | DONALD A. DALE |
President Chief Executive Officer | Executive Vice President and | Controller |
and Director | Chief Financial Officer | (Principal Accounting Officer) |
(Principal Financial Officer) |
Name | Office | Date |
/s/ Martin H. Young, Jr. | Chairman of the Board, Director | March 30, 2005 |
Martin H. Young, Jr. | ||
/s/ Robert F. Heinemann | President, Chief Executive Officer | March 30, 2005 |
Robert F. Heinemann | and Director | |
/s/ William F. Berry | Director | March 30, 2005 |
William F. Berry | ||
/s/ Ralph B. Busch, III | Director | March 30, 2005 |
Ralph B. Busch, III | ||
/s/ William E. Bush, Jr. | Director | March 30, 2005 |
William E. Bush, Jr. | ||
/s/ Stephen L. Cropper | Director | March 30, 2005 |
Stephen L. Cropper | ||
/s/ J. Herbert Gaul, Jr. | Director | March 30, 2005 |
J. Herbert Gaul, Jr. | ||
/s/ John A. Hagg | Director | March 30, 2005 |
John A. Hagg | ||
/s/ Thomas J. Jamieson | Director | March 30, 2005 |
Thomas J. Jamieson | ||