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| PETD > SEC Filings for PETD > Form 10-Q on 5-Nov-2009 | All Recent SEC Filings |
5-Nov-2009
Quarterly Report
This periodic report contains "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of
the Securities Exchange Act of 1934 ("Exchange Act") regarding our business,
financial condition, results of operations and prospects. All statements other
than statements of historical facts included in and incorporated by reference
into this report are forward-looking statements. Words such as expects,
anticipates, intends, plans, believes, seeks, estimates and similar expressions
or variations of such words are intended to identify forward-looking statements
herein, which include statements of estimated oil and natural gas production and
reserves, drilling plans, future cash flows, anticipated liquidity, anticipated
capital expenditures and our management's strategies, plans and
objectives. However, these are not the exclusive means of identifying
forward-looking statements herein. Although forward-looking statements contained
in this report reflect our good faith judgment, such statements can only be
based on facts and factors currently known to us. Consequently, forward-looking
statements are inherently subject to risks and uncertainties, including risks
and uncertainties incidental to the exploration for, and the acquisition,
development, production and marketing of, natural gas and oil, and actual
outcomes may differ materially from the results and outcomes discussed in the
forward-looking statements. Important factors that could cause actual results to
differ materially from the forward-looking statements include, but are not
limited to:
· changes in production volumes, worldwide demand, and commodity prices for oil and natural gas;
· the timing and extent of our success in discovering, acquiring, developing and producing natural gas and oil reserves;
· our ability to acquire leases, drilling rigs, supplies and services at reasonable prices;
· the availability and cost of capital to us;
· risks incident to the drilling and operation of natural gas and oil wells;
· future production and development costs;
· the availability of sufficient pipeline and other transportation facilities to carry our production and the impact of these facilities on price;
· the effect of existing and future laws, governmental regulations and the political and economic climate of the United States of America;
· the effect of natural gas and oil derivatives activities;
· conditions in the capital markets; and
· losses possible from pending or future litigation.
Further, we urge you to carefully review and consider the cautionary statements made in this report, our annual report on Form 10-K for the year ended December 31, 2008, filed with the Securities and Exchange Commission ("SEC") on February 27, 2009 ("2008 Form 10-K"), and our other filings with the SEC and public disclosures. We caution you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events.
Results of Operations
Summary of Operations
The following table sets forth selected information regarding our results of
operations, including production volumes, oil and gas sales, average sales price
received, average sales price including realized derivative gains and losses,
average lifting cost, other operating income and expenses for the 2009 and 2008
third quarter and nine-month periods.
Three Months Ended September 30, Nine Months Ended September 30,
2009 2008 Change 2009 2008 Change
Production (1)
Oil (Bbls) 312,547 322,133 -3.0 % 999,296 834,183 19.8 %
Natural gas (Mcf) 9,058,842 8,239,005 10.0 % 27,301,974 22,443,011 21.7 %
Natural gas equivalent (Mcfe) (2) 10,934,124 10,171,803 7.5 % 33,297,750 27,448,109 21.3 %
Oil and Gas Sales (in thousands)
Oil sales $ 19,045 $ 34,804 -45.3 % $ 50,917 $ 87,158 -41.6 %
Gas sales 24,961 64,448 -61.3 % 76,970 182,484 -57.8 %
Provision for underpayment of gas sales - 170 -100.0 % (2,581 ) (4,025 ) 35.9 %
Total oil and gas sales $ 44,006 $ 99,422 -55.7 % $ 125,306 $ 265,617 -52.8 %
Realized Gain (Loss) on Derivatives, net (in thousands)
Oil derivatives $ 3,506 $ (4,157 ) 184.3 % $ 15,618 $ (9,857 ) *
Natural gas derivatives 18,318 1,405 * 67,127 (10,660 ) *
Total realized gain (loss) on derivatives, net $ 21,824 $ (2,752 ) * $ 82,745 $ (20,517 ) *
Average Sales Price (excluding realized gains (losses) on derivatives)
Oil (per Bbl) $ 60.93 $ 108.04 -43.6 % $ 50.95 $ 104.48 -51.2 %
Natural gas (per Mcf) $ 2.76 $ 7.82 -64.7 % $ 2.82 $ 8.13 -65.3 %
Natural gas equivalent (per Mcfe) $ 4.02 $ 9.76 -58.8 % $ 3.84 $ 9.82 -60.9 %
Average Sales Price (including realized gains (losses) on derivatives)
Oil (per Bbl) $ 72.15 $ 95.14 -24.2 % $ 66.58 $ 92.67 -28.2 %
Natural gas (per Mcf) $ 4.78 $ 7.99 -40.2 % $ 5.28 $ 7.66 -31.1 %
Natural gas equivalent (per Mcfe) $ 6.02 $ 9.49 -36.6 % $ 6.33 $ 9.08 -30.3 %
Average Lifting Cost per Mcfe (3) $ 0.79 $ 0.94 -16.0 % $ 0.79 $ 1.07 -26.2 %
Natural gas marketing (in thousands) (4) $ 888 $ (1,000 ) 188.8 % $ 1,774 $ 1,028 72.6 %
Costs and Expenses (in thousands)
Exploration expense $ 6,586 $ 10,212 -35.5 % $ 15,362 $ 17,962 -14.5 %
General and administrative expense $ 9,627 $ 8,106 18.8 % $ 36,505 $ 27,160 34.4 %
Depreciation, depletion and amortization ("DD&A") $ 32,277 $ 28,645 12.7 % $ 100,465 $ 71,881 39.8 %
Interest Expense (in thousands) $ 9,221 $ 7,817 18.0 % $ 27,024 $ 19,143 41.2 %
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*Represents percentages in excess of 250% Amounts may not calculate due to rounding
(2) A ratio of energy content of natural gas and oil (six Mcf of natural gas equals one Bbl of oil) was used to obtain a conversion factor to convert oil production into equivalent Mcf of natural gas.
(3) Lifting costs represent oil and gas operating expenses which exclude production taxes.
(4) Represents sales from natural gas marketing less costs of natural gas marketing.
Even with natural gas prices rebounding somewhat from earlier in 2009, through
September 2009, we continued to experience the depressed natural gas prices from
the dramatic declines in late July 2008 through the end of 2008. As our
production increased to 33.3 Bcfe for the 2009 nine-month period compared to
27.4 Bcfe for the same 2008 period, an increase of 21.3%, our average sales
price declined 60.9% or $5.98 per Mcfe. While the significant changes in
commodity prices have impacted our results of operations, we believe that we
were successful in managing our operations to reduce the negative impacts
through our derivative positions. Our realized derivative gains for the 2009
nine-month period of $82.7 million added an average of $2.49 per Mcfe produced
during the 2009 nine-month period. At September 30, 2009, we estimate the net
fair value of our open derivative positions, excluding the derivative positions
attributed to our affiliated partnerships, to be a net asset of $21.9 million.
Depressed commodity prices for the 2009 nine-month period, as compared to the higher prices in the same 2008 period, were the primary contributors to the $38.7 million decrease in revenues from oil and gas price risk management. Of this change, $142 million was related to an increase in unrealized derivative losses, partially offset by an increase in realized derivative gains of $103.3 million. Unrealized gains and losses are non-cash items and these non-cash charges to our condensed consolidated statement of operations will continue to fluctuate with the fluctuation in commodity prices until the positions mature or are closed, at which time they will become realized or cash items. While the required accounting treatment for derivatives that are not designated as hedges may result in significant swings in operating results over the life of the derivatives, the combination of the settled derivative contracts and the revenue received from the oil and gas sales at delivery are expected to result in a more predictable cash flow stream than would the sales contracts without the associated derivatives.
The table below, which demonstrates the volatility in the markets' projected commodity prices, sets forth the average New York Mercantile Exchange ("NYMEX") and Colorado Interstate Gas ("CIG") prices for the next 24 months (forward curve) from the selected dates.
June 30, September 30, March 31, September 30, October 31,
Commodity Index 2008 2008 2009 2009 2009
Natural gas: NYMEX $ 12.52 $ 8.21 $ 5.44 $ 6.25 $ 6.00
CIG 8.86 5.46 4.15 5.64 5.49
Oil: NYMEX 140.15 103.63 59.35 74.64 81.26
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Oil and Gas Sales
The following tables set forth oil and natural gas production and average sales
price by area.
Three Months Ended September 30, Nine Months Ended September 30,
Percentage Percentage
2009 2008 Change 2009 2008 Change
Production
Oil (Bbls)
Rocky Mountain Region 308,512 318,722 -3.2 % 989,780 826,303 19.8 %
Appalachian Basin 3,338 2,467 35.3 % 7,241 5,105 41.8 %
Michigan Basin 697 944 -26.2 % 2,275 2,775 -18.0 %
Total 312,547 322,133 -3.0 % 999,296 834,183 19.8 %
Natural gas (Mcf)
Rocky Mountain Region 7,700,028 6,916,539 11.3 % 23,288,344 18,389,853 26.6 %
Appalachian Basin 968,494 931,150 4.0 % 2,971,374 2,895,499 2.6 %
Michigan Basin 390,320 391,316 -0.3 % 1,042,256 1,157,659 -10.0 %
Total 9,058,842 8,239,005 10.0 % 27,301,974 22,443,011 21.7 %
Natural gas equivalent (Mcfe)
Rocky Mountain Region 9,551,100 8,828,871 8.2 % 29,227,024 23,347,671 25.2 %
Appalachian Basin 988,522 945,952 4.5 % 3,014,820 2,926,129 3.0 %
Michigan Basin 394,502 396,980 -0.6 % 1,055,906 1,174,309 -10.1 %
Total 10,934,124 10,171,803 7.5 % 33,297,750 27,448,109 21.3 %
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Three Months Ended September 30, Nine Months Ended September 30,
2009 2008 Percentage Change 2009 2008 Percentage Change
Average Sales Price (excluding derivative gains/losses)
Oil (per Bbl)
Rocky Mountain Region $ 60.96 $ 108.00 -43.6 % $ 50.96 $ 104.45 -51.2 %
Appalachian Basin 55.96 108.68 -48.5 % 50.14 105.93 -52.7 %
Michigan Basin 63.83 118.92 -46.3 % 50.76 112.38 -54.8 %
Weighted average price 60.93 108.04 -43.6 % 50.95 104.48 -51.2 %
Natural gas (per Mcf)
Rocky Mountain Region 2.70 7.37 -63.4 % 2.65 7.78 -65.9 %
Appalachian Basin 3.18 10.40 -69.4 % 3.96 9.99 -60.4 %
Michigan Basin 2.88 9.67 -70.2 % 3.39 9.24 -63.3 %
Weighted average price 2.76 7.82 -64.7 % 2.82 8.13 -65.3 %
Natural gas equivalent (per Mcfe)
Rocky Mountain Region 4.14 9.68 -57.2 % 3.84 9.82 -60.9 %
Appalachian Basin 3.24 10.43 -68.9 % 4.00 10.02 -60.1 %
Michigan Basin 2.95 9.84 -70.0 % 3.45 9.38 -63.2 %
Weighted average price 4.02 9.76 -58.8 % 3.84 9.82 -60.9 %
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Despite increases in production for both the 2009 third quarter and nine-month periods, oil and gas sales revenue for these periods, excluding the provision for underpayment of gas sales, decreased $55.2 million and $141.8 million, respectively, compared to the same 2008 periods. Approximately $164.2 million of the decrease in oil and gas sales revenue for the 2009 nine-month period was due to pricing, offset in part by increased production, which contributed $22.4 million. The decrease in oil and gas sales revenue was partially offset by increased realized derivative gains for the 2009 third quarter and nine-month periods of $24.6 million and $103.3 million, respectively. See Oil and Gas Price Risk Management, Net discussion below.
Oil and Natural Gas Pricing. Our results of operations depend upon many factors, particularly the price of oil and natural gas and our ability to market our production effectively. Oil and natural gas prices are among the most volatile of all commodity prices. These price variations have a material impact on our financial results. Oil and natural gas prices also vary by region and locality, depending upon the distance to markets, and the supply and demand relationships in that region or locality. This can be especially true in the Rocky Mountain Region. The combination of increased drilling activity and the lack of local markets have resulted in a local market oversupply situation from time to time. Like most producers in the region, we rely on major interstate pipeline companies to construct these pipelines to increase capacity, rendering the timing and availability of these facilities beyond our control.
The price we receive for a large portion of the natural gas produced in the Rocky Mountain Region is based on a market basket of prices, which generally includes gas sold at CIG prices as well as gas sold at Mid-Continent or other nearby region prices. The CIG Index, and other indices for production delivered to other Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is NYMEX based. This negative differential has narrowed in recent months and has even more recently become a positive differential, which contradicts historical variances. For example, CIG was $1.79 lower than NYMEX in January 2009, narrowed to close at only $0.37 lower in October 2009 and has more recently closed at $0.02 higher than NYMEX for November 2009.
The table below identifies the market for our oil and natural gas sales based on production for the 2009 third quarter. The market is the index that most closely relates to the price under which our oil and natural gas is sold.
Energy Market Exposure
For the Three Months Ended September 30, 2009
Area Market Commodity Percent of Production
Piceance/Wattenberg CIG Gas 37%
Colorado/North Dakota NYMEX Oil 18%
San Juan
Basin/Southern
Piceance California Gas 15%
Mid Continent
NECO (Panhandle Eastern) Gas 13%
Appalachian NYMEX Gas 9%
Michigan Mich-Con/NYMEX Gas 4%
Wattenberg Colorado Liquids Gas 3%
Other Other Gas/Oil 1%
100%
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Oil and Gas Production and Well Operations Costs. Oil and gas production and well operations cost includes our lifting cost, production taxes, the cost to operate wells and pipelines for our affiliated partnerships and other third parties (whose income is included in well operations and pipeline income) and certain production and engineering staff related overhead costs.
Three Months Ended September 30, Nine Months Ended September 30,
2009 2008 2009 2008
(in thousands)
Lifting cost $ 8,669 $ 9,523 $ 26,192 $ 29,276
Production taxes 2,645 7,112 7,380 18,695
Costs of well operations and pipeline
income 1,855 1,232 5,195 3,973
Overhead and other production expenses 2,049 4,715 6,856 10,171
Total oil and gas production and well
operations cost $ 15,218 $ 22,582 $ 45,623 $ 62,115
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Lifting Costs. Lifting costs per Mcfe decreased 16% and 26.2% to $0.79 per Mcfe for the 2009 third quarter and nine-month periods from $.94 per Mcfe and $1.07 per Mcfe for the same 2008 periods. The decrease per Mcfe is primarily due to lower third party costs from service providers as a result of pressure by purchasers to reduce costs as oil and gas prices deteriorated, our own cost reduction initiatives, and increased production, which allows us to spread the fixed portion of our production costs over the increased volume.
Production Taxes. Production taxes decreased $4.5 million or 62.8% to $2.6 million and $11.3 million or 60.5% to $7.4 million for the 2009 third quarter and nine-month periods, respectively. This decrease is primarily related to the 55.7% and 52.8% decrease in oil and gas sales for the 2009 third quarter and nine-month periods, respectively.
Cost of well operations and pipeline income. The increases in cost of well operations and pipeline income for the 2009 third quarter and nine-month periods over the same 2008 periods were the result of costs related to several pipeline maintenance projects.
Overhead and other production expenses. Overhead and other production expenses decreased in the 2009 third quarter and nine-month periods compared to the same 2008 periods due to the lower cost of field services, including vehicle, lower rates from third parties and less work and services being performed in this low commodity price environment.
Oil and Gas Price Risk Management, Net
Three Months Ended Nine Months Ended
September 30, September 30,
2009 2008 2009 2008
(in thousands)
Oil and gas price risk management gain
(loss), net:
Realized gains (losses):
Oil $ 3,506 $ (4,157 ) $ 15,618 $ (9,857 )
Natural gas 18,318 1,405 67,127 (10,660 )
Total realized gains (losses), net 21,824 (2,752 ) 82,745 (20,517 )
Unrealized gains (losses):
Reclassification of realized (gains)
losses included in prior periods
unrealized (21,139 ) 24,646 (62,548 ) 436
Unrealized gains (losses) for the period (14,498 ) 147,508 (33,611 ) 45,375
Total unrealized gains (losses), net (35,637 ) 172,154 (96,159 ) 45,811
Total oil and gas price risk management
gain (loss), net $ (13,813 ) $ 169,402 $ (13,414 ) $ 25,294
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Realized gains recognized in the 2009 third quarter and nine-month periods are a result of lower oil and gas commodity prices at settlement compared to the respective strike price. During the 2009 third quarter, we recorded derivative unrealized losses on our CIG basis swaps of $7.1 million as the forward basis differential between NYMEX and CIG has continued to narrow along with unrealized losses of $6.5 million on our natural gas positions as the forward strip price has continued to rebound compared to the previous forward curve. Similarly, during the 2009 nine-month period, we recorded derivative unrealized losses of $28.9 million on our CIG basis swaps and $8.5 million on our oil swaps, offset in part by unrealized gains of $3.8 million on our natural gas positions as natural gas prices continued to decline compared to the previous forward curves.
Oil and gas price risk management, net includes realized gains and losses and unrealized changes in the fair value of derivative instruments related to our oil and natural gas production. Oil and gas price risk management, net does not include derivative transactions related to natural gas marketing, which are included in sales from and cost of natural gas marketing. See Note 3, Fair Value Measurements, and Note 4, Derivative Financial Instruments, to the accompanying condensed consolidated financial statements for additional details of our derivative financial instruments.
Oil and Gas Sales Derivative Instruments. We use various derivative instruments to manage fluctuations in oil and natural gas prices. We have in place a series of collars, fixed-price swaps and basis swaps on a portion of our oil and natural gas production. Under our collar arrangements, if the applicable index rises above the ceiling price, we pay the counterparty; however, if the index drops below the floor price, the counterparty pays us. Under our swap arrangements, if the applicable index rises above the swap price, we pay the counterparty; however, if the index drops below the swap price, the counterparty pays us. Because we sell all our physical oil and natural gas at similar prices to the indexes inherent in our derivative instruments, we ultimately realize a price related to our collars of no less than the floor and no more than the ceiling and, for our swaps, we ultimately realize the fixed price related to our swaps.
The following table identifies our derivative positions (excluding the derivative positions allocated to our affiliated partnerships) related to oil and gas sales in effect as of September 30, 2009, on our production by area. Our production volumes for the 2009 third quarter were 312,547 Bbls of oil and 9.1 Bcf of natural gas.
Collars Fixed-Price Swaps Basis Protection Swaps
. . .
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