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| BRY > SEC Filings for BRY > Form 10-Q on 25-Jul-2008 | All Recent SEC Filings |
25-Jul-2008
Quarterly Report
General. The following discussion provides information on the results of operations for the three and six month periods ended June 30, 2008 and 2007 and our financial condition, liquidity and capital resources as of June 30, 2008. The financial statements and the notes thereto contain detailed information that should be referred to in conjunction with this discussion.
The profitability of our operations in any particular accounting period will be directly related to the realized prices of oil, gas and electricity sold, the type and volume of oil and gas produced and electricity generated and the results of development, exploitation, acquisition, exploration and hedging activities. The realized prices for natural gas and electricity will fluctuate from one period to another due to regional market conditions and other factors, while oil prices will be predominantly influenced by global supply and demand. The aggregate amount of oil and gas produced may fluctuate based on the success of development and exploitation of oil and gas reserves pursuant to current reservoir management. The cost of natural gas used in our steaming operations and electrical generation, production rates, labor, equipment costs, maintenance expenses, and production taxes are expected to be the principal influences on operating costs. Accordingly, our results of operations may fluctuate from period to period based on the foregoing principal factors, among others.
Overview. We seek to increase shareholder value through consistent growth in our
production and reserves, both through the drill bit and acquisitions. We strive
to operate our properties in an efficient manner to maximize the cash flow and
earnings of our assets. The strategies to accomplish these goals include:
· Developing our existing resource base
· Acquiring additional assets with significant growth potential
· Utilizing joint ventures with respected partners to enter new basins
· Accumulating significant acreage positions near our producing operations
· Investing our capital in a disciplined manner and maintaining a strong financial position
Notable Second Quarter Items.
· Achieved record production averaging 29,000 BOE/D, up 7% from the second
quarter of 2007 and up 3% from the first quarter of 2008
· Increased Piceance net average production to 20.8 MMcf/D in the month of June, up 24% from the first quarter of 2008
· Increased Diatomite net production to an average of 1,700 BOE/D, up 24% from the first quarter of 2008
· Production at Poso Creek averaged 3,200 Bbl/D, up 19% from the first quarter of 2008
· Achieved a production exit rate of 30,000 BOE/D
· Completed relocation of our corporate headquarters from Bakersfield, California to Denver, Colorado
· Announced that David D. Wolf would join the Company as Executive Vice President and Chief Financial Officer
Notable Items and Expectations for the Third Quarter of 2008.
· Closed on the acquisition of 4,500 acres in Limestone and Harrison Counties of
East Texas on July 15, 2008, adding an estimated 32 MMcf/D to production
· Increased our 2008 capital budget by $75 million to $370 million to fund the development of our East Texas acquisition
· Entered into an amended and restated secured credit facility with a $1 billion borrowing base
· Targeting a production average of approximately 35,000 BOE/D in the third quarter and a 2008 exit rate of between 39,000 and 40,000 BOE/D
Overview of the Second Quarter of 2008. We had net income of $49 million, or $1.08 per diluted share and net cash from operations was $107 million. We drilled 120 gross wells and capital expenditures, excluding property acquisitions, totaled $95 million. We achieved average production of 29,000 BOE/D in the second quarter of 2008, up 3% from an average of 28,066 BOE/D in the first quarter of 2008.
Results of Operations. The following companywide results are in millions (except per share data) for the three months ended:
2Q08
to
June 30, 2008 June 30, 2007 2Q07 March 31, 2008 2Q08 to 1Q08
(2Q08) (2Q07) Change (1Q08) Change
Sales of oil $ 146 $ 94 55% $ 131 11%
Sales of gas 39 19 105% 33 19%
Total sales of oil and gas $ 185 $ 113 64% $ 164 13%
Sales of electricity 17 14 21% 16 6%
Gain on sale of assets - 50 -% - -%
Other revenues 13 2 550% 5 160%
Total revenues and other income $ 215 $ 179 20% $ 185 16%
Net income $ 49 $ 52 (6%) $ 43 14%
Earnings per share (diluted) $ 1.08 $ 1.16 (7%) $ .95 14%
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Our revenues may vary significantly from period to period as a result of changes in commodity prices and/or production volumes. Crude oil sales in the three months ended June 30, 2008 were 11% higher than the three months ended March 31, 2008 resulting from price increases of 6% and sales volume increases of 5%. Gas sales in the three months ended June 30, 2008 were 19% higher than the three months ended March 31, 2008 resulting from production increases of 3% and a price increase of 16%. Net income decreased 6% from the second quarter of 2007 to the second quarter of 2008 in part due to the $50.4 million pretax gain on the sale of assets during the second quarter of 2007.
In the first quarter of 2008, we determined there was an error in computing royalties payable in prior years, accumulating to $10.5 million as of December 31, 2007. We concluded the error was not material to any individual prior interim or annual period (or to the projected earnings for 2008) and, therefore, this error was corrected during the first quarter of 2008, with the effect of increasing our sales of oil and gas by $10.5 million and reducing our royalties payable.
[[Image Removed: WTI PRICING]]
[[Image Removed: HH PRICING]]
Operating data. The following table is for the three months ended:
March
June 30, 2008 % June 30, 2007 % 31, 2008 %
Heavy Oil Production
(Bbl/D) 16,888 58 16,129 59 16,375 58
Light Oil Production
(Bbl/D) 3,723 13 4,034 15 3,510 13
Total Oil Production
(Bbl/D) 20,611 71 20,163 74 19,885 71
Natural Gas Production
(Mcf/D) 50,339 29 42,193 26 49,086 29
Total (BOE/D) 29,000 100 27,195 100 28,066 100
Oil and gas, per BOE:
Average sales price
before hedging $ 91.89 $ 44.72 $ 71.67
Average sales price
after hedging 69.77 45.43 60.43
Oil, per Bbl:
Average WTI price $ 123.80 $ 65.02 $ 97.82
Price sensitive
royalties (5.92 ) (4.20 ) (4.47 )
Quality differential
and other (11.52 ) (9.24 ) (10.78 )
Crude oil hedges (29.37 ) (.52 ) (15.60 )
Correction to royalties
payable - - 5.85
Average oil sales price
after hedging $ 76.99 $ 51.06 $ 72.82
Natural gas price:
Average Henry Hub price
per MMBtu $ 10.93 $ 7.55 $ 8.05
Conversion to Mcf .55 .38 .40
Natural gas hedges (.69 ) .71 (.12 )
Location, quality
differentials and other (2.15 ) (3.53 ) (.90 )
Average gas sales price
after hedging $ 8.64 $ 5.11 $ 7.43
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Operating data. The following table is for the six months ended:
June 30, 2008 % June 30, 2007 %
Heavy Oil Production
(Bbl/D) 16,631 58 16,112 61
Light Oil Production
(Bbl/D) 3,617 13 3,643 14
Total Oil Production
(Bbl/D) 20,248 71 19,755 75
Natural Gas Production
(Mcf/D) 49,712 29 39,463 25
Total (BOE/D) 28,534 100 26,332 100
Oil and gas, per BOE:
Average sales price
before hedging $ 84.02 $ 44.25
Average sales price after
hedging 67.23 44.72
Oil, per Bbl:
Average WTI price $ 111.12 $ 61.68
Price sensitive royalties (5.21 ) (3.97 )
Quality differential and
other (11.15 ) (9.01 )
Crude oil hedges (22.66 ) (.24 )
Correction to royalties
payable 2.85 -
Average oil sales price
after hedging $ 74.95 $ 48.46
Natural gas price:
Average Henry Hub price
per MMBtu $ 9.49 $ 7.16
Conversion to Mcf .47 .36
Natural gas hedges (.41 ) .44
Location, quality
differentials and other (1.50 ) (2.12 )
Average gas sales price
after hedging $ 8.05 $ 5.84
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[[Image Removed: BOE PER DAY]]
Gas Basis Differential. The basis differential
between Henry Hub (HH) and Colorado Interstate
Gas (CIG) index narrowed due to the increased
take away capacity added by the start up of the
Rockies Express Pipeline (REX) in
January. However, the differential widened
again in the second quarter. In the first
quarter of 2008, the CIG basis differential per
MMBtu, based upon first-of-month values,
averaged $1.07 below HH and ranged from $.91 to
$1.19 below HH. For the second quarter, the
differential averaged $2.46 with the range
going from $1.78 at the start of the quarter to
$3.24 below HH at the end of the quarter. We
have contracted a total of 35,000 MMBtu/D on
the REX pipeline under two separate
transactions to provide firm transportion for
our Piceance basin gas production. After the
REX startup in 2008, all of the Piceance basin
gas was sold at mid-continent (ANR, NGPL or
PEPL) indexes which averaged approximately $.70
above the CIG index pricing before the cost of
transportation.
Gas from the Uinta basin sold for approximately $.03 below CIG pricing before deducting the cost of pipeline transport. A portion of the Uinta gas is priced on the Questar index while the remainder is based upon the CIG or NWPL index.
DJ Basin gas is priced using one of two indices. Approximately two-thirds of our volume from our DJ natural gas properties is tied to the Panhandle Eastern Pipeline (PEPL) index for pricing and the remaining volume to CIG pricing. For that portion of the production with firm transportation on either the Cheyenne Plains Pipeline or the KMIGT pipeline, pricing is based upon the PEPL index which averaged approximately $1.84 below the HH index during the second quarter, before the cost of transportation. The remainder of the DJ Basin gas is sold slightly above the CIG index price.
Gas Marketing. In December 2007, we entered into a second long-term (ten year) firm transportation contract for our Colorado natural gas production. This contract is for 25,000 MMBtu/D on the REX pipeline for gas production in the Piceance basin. We pay a demand charge for this capacity and our own production did not fill that capacity. In order to maximize our firm transportation capacity, we bought our partners' share of the gas produced in the Piceance at the market rate for that area. We then used our excess transportation to move this gas to where it was eventually sold. The net of our gas marketing revenue and our gas marketing expense in the Statements of Income is $.7 million in the six month period ended June 30, 2008. We expect our production will reach our firm transportation contract volume during 2009.
Oil Contracts. Utah - In February 2007, we entered into a multi-staged crude oil sales contract with a refiner for our Uinta basin light crude oil. Under the agreement, the refiner began purchasing 3,200 Bbl/D in July 2007. The refiner has increased its total capacity to 5,000 Bbl/D as provided in our contract. As operator we deliver all produced volumes under our sales contracts, although our working interest partners or royalty owners may take their respective volumes in kind and market their own volumes. Gross oil production averaged approximately 4,000 BOE/D in the quarter ended June 30, 2008. The differential under the contract, which includes transportation and gravity adjustments, is linked to WTI and would range from $20 to $30 per barrel at WTI prices between $80 and $120. This contract provides us an outlet to sell all of our current oil production in the Uinta basin.
Hedging. See Note 4 to the unaudited condensed financial statements and Item 3. Quantitative and Qualitative Disclosures about Market Risk.
Electricity. We consume natural gas as fuel to operate our three cogeneration facilities which are intended to provide an efficient and secure long-term supply of steam necessary for the cost-effective production of heavy oil in California. We sell our electricity to utilities under standard offer contracts based on "avoided cost" or SRAC pricing approved by the California Public Utilities Commission (CPUC) and under which our revenues are currently linked to the cost of natural gas. Natural gas index prices are the primary determinant of our electricity sales price based on the current pricing formula under these contracts. The correlation between electricity sales and natural gas prices allows us to manage our cost of producing steam more effectively.
In 2007, our electricity operations improved partially from the lower cost of our firm transportation natural gas compared to California prices which are used to determine our electricity payment. We purchase and transport 12,000 MMBtu/D on the Kern River Pipeline under our firm transportation contract and use this gas to produce conventional and cogeneration steam in the Midway-Sunset field. The differential between Rocky Mountain gas prices and Southern California Border prices increased during 2007 allowing us to purchase a portion of our gas at a discount to the Southern California Border price. As our electricity revenue is linked to Southern California Border prices, the fuel we purchased at lower Rocky Mountain prices was the primary contributor to the increase in our electricity margin in 2007. We purchased approximately 38,000 MMBtu/D as fuel for use in our cogeneration facilities in the year ended December 31, 2007. Rockies natural gas differentials have stabilized near their historical levels and we do not expect to have significant positive electricity margins in 2008. We expect to have small gains or losses on electricity on a quarterly basis which depends on seasonality as we receive improved pricing during the summer months. On September 20, 2007, the CPUC issued a decision (SRAC Decision) that changes the way SRAC energy prices will be determined for existing and new Standard Offer (SO) contracts and revises the capacity prices paid under current SO1 contracts. Based on our preliminary analysis, we do not believe that the proposed pricing changes will materially affect us in 2008.
The following table is for the three months ended:
March
June 30, 2008 June 30, 2007 31, 2008
Electricity
Revenues (in millions) $ 17.0 $ 13.9 $ 15.9
Operating costs (in millions) $ 15.5 $ 11.1 $ 16.4
Electric power produced - MWh/D 1,919 2,060 2,152
Electric power sold - MWh/D 1,724 1,819 1,959
Average sales price/MWh $ 108.21 $ 84.13 $ 90.48
Fuel gas cost/MMBtu (including
transportation) $ 10.01 $ 6.46 $ 7.94
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Oil and Gas Operating, Production Taxes, G&A and Interest Expenses. The following table presents information about our operating expenses for each of the three month periods ended:
Amount per BOE Amount (in thousands)
June 30,
June 30, 2008 June 30, 2007 March 31, 2008 June 30, 2008 2007 March 31, 2008
Operating costs -
oil and gas
production $ 20.91 $ 14.44 $ 16.30 $ 55,185 $ 35,725 $ 41,629
Production taxes 2.83 1.67 2.34 7,481 4,139 5,967
DD&A - oil and gas
production 11.02 9.45 10.60 29,073 23,397 27,076
G&A 4.23 3.90 4.46 11,160 9,651 11,383
Interest expense 1.50 2.01 1.46 3,951 4,976 3,738
Total $ 40.49 $ 31.47 $ 35.16 $ 106,850 $ 77,888 $ 89,793
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Our total operating costs, production taxes, DD&A, G&A and interest expenses for the three months ended June 30, 2008, stated on a unit-of-production basis, increased 29% over the three months ended June 30, 2007 and increased 15% as compared to the three months ended March 31, 2008. The changes were primarily related to the following items:
· Operating costs: The majority of the increase in our operating costs was due to higher steam costs resulting from higher fuel costs. The following table presents steam information:
March
June 30, 2008 June 30, 2007 2Q08 to 2Q07 31, 2008 2Q08 to 1Q08
(2Q08) (2Q07) Change (1Q08) Change
Average volume of steam 97,853 84,032 16% 91,326 7%
injected (Bbl/D)
Fuel gas cost/MMBtu (including $ 10.01 $ 6.46 55% $ 7.94 26%
transportation)
Approximate net fuel gas
volume consumed in steam 27,382 22,559 21% 21,634 27%
generation (MMBtu/D)
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Our total cost to purchase fuel for our steam operations increased by $2.07 per MMBtu or 26% in the three months ended June 2008 compared to the three months ended March 2008 as the SoCal border natural gas price increased over this time period. We consumed an additional 5,750 MMBtu/D in the second quarter of 2008 when compared to the first quarter of 2008 primarily related to increased conventional steam generation consumption and seasonal changes in the price received for our electricity which is used to allocate our cogeneration fuel gas volumes between electricity costs and steam costs. The increase in natural gas prices and our overall consumption accounted for approximately $10 million of the $13.6 million increase in operating costs between the first and second quarters of 2008. We plan to increase our fuel gas consumption by 4,000 MMBtu/D in the fourth quarter of 2008 as we add additional steam generation capacity at Poso Creek and the Diatomite.
During 2008, we generally expect a small change in our net income due to a change in natural gas prices as an increase in our steam costs is offset by revenue from our gas production and payments under our hedges. However, our gas long position can be impacted by volatility in the differential between the SoCal border price where we purchase the majority of our natural gas for steam generation and the Rockies prices at which we sell our produced volumes. Our realized price from the sale of natural gas increased $1.21/Mcf from the first quarter of 2008 as compared to the second quarter of 2008 while the cost of fuel purchased to generate steam and electricity increased $2.07/MMBtu over the same period.
· Production taxes: Our production taxes have increased compared to the second quarter of 2007 and the first quarter of 2008 as commodity prices and thus the values of our oil and natural gas has increased. Severance taxes paid in Utah and Colorado, are directly related to the field sales price of the commodity. In California, our production is burdened with ad valorem taxes on our total proved reserves. We expect production taxes to track oil and gas prices generally.
· Depreciation, depletion and amortization: DD&A increased per BOE by 17% and 4% in the second quarter of 2008 as compared to the second quarter of 2007 and as compared to the first quarter of 2008, respectively, due to an increase in the contribution of our development properties with higher drilling and leasehold acquisition costs, which is in line with our expectations.
· General and administrative: Approximately 70% of our G&A is related to compensation. The primary reason for the increase in G&A during the second quarter of 2008 as compared to the second quarter of 2007 was primarily due to an increase in the number of employees from 243 as of June 30, 2007 to 274 as of June 30, 2008.
· Interest expense: Our total outstanding borrowings were approximately $511 million at June 30, 2008 compared to $475 million and $455 million at June 30, 2007 and March 31, 2008, respectively. For the three months ended June 30, 2008, $4 million of interest cost has been capitalized and we expect to capitalize approximately $20 million of interest cost during the full year of 2008.
Estimated 2008 and Actual Six Months Ended June 30, 2008 and 2007 Oil and Gas Operating, G&A and Interest Expenses. We estimate our average 2008 production volume will range between 32,500 BOE/D and 33,500 BOE/D. Based on actual first six months and the remainder of 2008 at NYMEX WTI crude oil price of $100 per barrel and NYMEX HH natural gas price of $10.00 per MMBtu, we expect our expenses to be within the following ranges:
Anticipated
range
in 2008 Six months ended Six months ended
per BOE June 30, 2008 June 30, 2007
Operating costs-oil and gas 18.50 to
production (1) $ 20.50 $ 18.64 $ 14.55
2.20 to
Production taxes 2.70 2.59 1.67
DD&A - oil and gas 10.00 to
production 11.00 10.81 8.84
4.00 to
G&A 4.50 4.34 4.19
1.50 to
Interest expense 2.00 1.48 1.94
36.20 to
Total $ 40.70 $ 37.86 $ 31.19
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(1) We expect operating costs to increase in 2008 as compared to 2007 due to higher projected natural gas costs.
Our total operating costs, production taxes, DD&A, G&A and interest expenses for the six months ended June 30, 2008, stated on a unit-of-production basis, increased 21% over the six months ended June 30, 2007. The changes were primarily related to the following items:
· Operating costs: The majority of the increase in our operating costs was due to higher steam costs resulting from higher fuel costs. The following table presents steam information:
Six months Six months
ended ended
June June
30, 2008 30, 2007 Change
Average volume of steam 94,589 85,076 11%
injected (Bbl/D)
Fuel gas cost/MMBtu $ 8.98 $ 6.58 37%
(including transportation)
Approximate net fuel gas
volume consumed in 24,536 21,022 17%
steam generation
(MMBtu/D)
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Our total cost to purchase fuel for our steam operations increased by $2.40 per MMBtu or 37% in the six months ended June 2008 compared to the six months ended June 2007 as the SoCal border natural gas price increased over this time period. We consumed an additional 3,510 MMBtus per day in the first six months of 2008 when compared to the first six months of 2007 primarily related to increased conventional steam generation consumption and seasonal changes in the price received for our electricity which is used to allocate our cogeneration fuel gas volumes.
· Production taxes: Production taxes per BOE in the six months ended June 30, 2008 were 55% higher than the comparable period in 2007 as commodity prices and thus the values of our oil and natural gas has increased. Severance taxes paid in Utah and Colorado, are directly related to the field sales price of the commodity. In California, our production is burdened with ad valorem taxes on our total proved reserves. We expect production taxes to track oil and gas prices generally.
· Depreciation, depletion and amortization: DD&A per BOE were 22% higher in the six months ended June 30, 2008 compared to the same period in the prior year due to an increase in the contribution of our development properties with higher drilling and leasehold acquisition costs, which is in line with our expectations.
· General and administrative: G&A per BOE increased by 4% in the six months ended June 30, 2007 compared to the same period in the prior year due to additional staffing and higher overall compensation costs associated with our growth activities.
. . .
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