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| PETD > SEC Filings for PETD > Form 10-Q on 8-May-2009 | All Recent SEC Filings |
8-May-2009
Quarterly Report
This periodic report contains "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934 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, and our other filings with the Securities and Exchange Commission ("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
prices received, average sales price including realized derivative gains and
losses, average lifting cost, other operating income and expenses for the three
months ended March 31, 2009, or first quarter 2009, and the three months ended
March 31, 2008, or first quarter 2008.
Summary Operating Results
Three Months Ended March 31,
2009 2008 Change
Production (1)
Oil (Bbls) 343,884 255,452 34.6 %
Natural gas (Mcf) 9,090,261 6,946,822 30.9 %
Natural gas equivalent (Mcfe) (2) 11,153,565 8,479,534 31.5 %
Oil and Gas Sales (in thousands)
Oil sales $ 12,989 $ 20,727 -37.3 %
Gas sales 29,334 50,919 -42.4 %
Provision for underpayment of gas sales (2,581 ) - *
Total oil and gas sales $ 39,742 $ 71,646 -44.5 %
Realized Gain (Loss) on Derivatives, net (in
thousands)
Oil derivatives $ 7,294 $ (1,306 ) *
Natural gas derivatives 29,332 (1,105 ) *
Total realized gain (loss) on derivatives, net $ 36,626 $ (2,411 ) *
Average Sales Price (excluding realized
gains/losses on derivatives)
Oil (per Bbl) $ 37.77 $ 81.14 -53.5 %
Natural gas (per Mcf) $ 3.23 $ 7.33 -55.9 %
Natural gas equivalent (per Mcfe) $ 3.79 $ 8.45 -55.1 %
Average Sales Price (including realized
gains/losses on derivatives)
Oil (per Bbl) $ 58.98 $ 76.03 -22.4 %
Natural gas (per Mcf) $ 6.45 $ 7.17 -10.0 %
Natural gas equivalent (per Mcfe) $ 7.08 $ 8.16 -13.3 %
Average Lifting Cost per Mcfe (3) $ 0.93 $ 1.13 -17.7 %
Other Operating Income (4) (in thousands)
Natural gas marketing activities $ 511 $ 1,204 -57.6 %
Oil and gas well drilling $ 48 $ 3,005 -98.4 %
Costs and Expenses (in thousands)
Exploration expense $ 5,643 $ 4,283 31.8 %
General and administrative expense $ 12,094 $ 9,823 23.1 %
Depreciation, depletion and amortization $ 34,344 $ 21,131 62.5 %
Interest Expense (in thousands) $ 8,383 $ 4,932 70.0 %
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* Percentage change not meaningful or equal to or greater than 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) Includes revenues and operating expenses.
During first quarter 2009, we experienced the continuation of dramatic declines in oil and natural gas commodity prices from late July of last year. Last year was marked with a series of unprecedented events: oil and natural gas prices soared to near record highs through July; then, in the midst of U.S. credit turmoil and a worldwide economic slump, in December, oil prices fell to their lowest in four years and natural gas prices dropped by almost half. While we certainly felt the impact of these events, we believe that we were successful in managing our operations in such a manner that we were able to minimize the negative impacts. As production increased to 11.2 Bcfe for first quarter 2009 compared to 8.5 Bcfe for first quarter 2008, an increase of 31.5%, our average sales price declined $4.66 per Mcfe. However, our derivative position eased the impact of the fall in oil and natural gas prices. Our realized derivative gains for first quarter 2009 of $36.6 million added an average of $3.29 per Mcfe produced during first quarter 2009, somewhat easing the dramatic drop in prices. At March 31, 2009, we estimate the net fair value of our open derivative positions, excluding the derivative positions attributed to our affiliated partnerships, to be $104.5 million. See the Liquidity and Capital Resources discussion below for the steps we are taking in this uncertain economic environment.
Depressed commodity prices for first quarter 2009 as compared to the higher prices in first quarter 2008 were the primary contributors to the $66 million change in oil and gas price risk management. Of the $66 million change, $57.5 million was related to the change in unrealized gains and losses on derivative instruments. Unrealized gains and losses are non-cash items and these non-cash charges to our 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 do not qualify for hedge accounting treatment under FAS No. 133 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 NYMEX and CIG prices for the next 24 months (forward curve) from the selected dates.
December 31, June 30, December 31, March 31,
Commodity Index 2007 2008 2008 2009
Natural gas: NYMEX $ 8.12 $ 12.52 $ 6.62 $ 5.44
CIG 6.78 8.86 4.49 4.15
Oil: NYMEX 90.79 140.15 57.49 59.35
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Oil and Gas Sales Activity
The following tables set forth oil and natural gas production and sales activity
by area.
Three Months Ended March 31,
2009 2008 Change
Production
Oil (Bbls)
Rocky Mountain Region 341,357 253,533 34.6 %
Appalachian Basin 1,704 1,096 55.5 %
Michigan Basin 823 823 0.0 %
Total 343,884 255,452 34.6 %
Natural gas (Mcf)
Rocky Mountain Region 7,828,763 5,599,765 39.8 %
Appalachian Basin 975,681 967,620 0.8 %
Michigan Basin 285,817 379,437 -24.7 %
Total 9,090,261 6,946,822 30.9 %
Natural gas equivalent (Mcfe)
Rocky Mountain Region 9,876,905 7,120,963 38.7 %
Appalachian Basin 985,905 974,196 1.2 %
Michigan Basin 290,755 384,375 -24.4 %
Total 11,153,565 8,479,534 31.5 %
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Three Months Ended March 31,
2009 2008 Change
Average Sales Price (excluding realized derivative gains/losses)
Oil (per Bbl)
Rocky Mountain Region $ 37.78 $ 81.08 -53.4 %
Appalachian Basin 37.06 88.71 -58.2 %
Michigan Basin 36.90 96.03 -61.6 %
Weighted average price 37.77 81.14 -53.5 %
Natural gas (per Mcf)
Rocky Mountain Region $ 2.95 $ 7.13 -58.6 %
Appalachian Basin 5.04 8.41 -40.1 %
Michigan Basin 4.24 7.63 -44.4 %
Weighted average price 3.23 7.33 -55.9 %
Natural gas equivalent (per Mcfe)
Rocky Mountain Region $ 3.65 $ 8.49 -57.0 %
Appalachian Basin 5.04 8.45 -40.4 %
Michigan Basin 4.26 7.74 -45.0 %
Weighted average price 3.79 8.45 -55.1 %
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While our production increased to 11.2 Bcfe for first quarter 2009 from 8.5 Bcfe for first quarter 2008, our oil and gas sales revenue decreased $31.9 million quarter-to-quarter, primarily due to the dramatic decline in commodity prices, partially offset by increased volumes. Approximately $39.5 million of the decrease in revenue was due to pricing, offset in part by increased production, which contributed $10.1 million. The decrease in oil and gas sales revenue was offset by realized derivative gains for first quarter 2009 of $36.6 million, see Oil and Gas Price Risk Management, Net discussion below.
Oil and Natural Gas Pricing. Financial results 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 have been 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 facilities to increase pipeline capacity, rendering the timing and availability of these facilities beyond our control. Oil pricing is also driven strongly by supply and demand relationships.
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.
Although 86.1% of our natural gas production for first quarter 2009 is produced in the Rocky Mountain Region, much of our Rocky Mountain natural gas pricing is based upon other indices in addition to CIG. The table below identifies the pricing basis of our oil and natural gas sales based on production for first quarter 2009. The pricing basis 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 March 31, 2009
Percent of
Area Pricing Basis Commodity Production
Piceance/Wattenberg Colorado Interstate Gas (CIG) Gas 37%
Colorado/North Dakota NYMEX Oil 18%
Piceance San Juan Basin/Southern California Gas 16%
NECO Mid Continent (Panhandle Eastern) Gas 12%
Appalachian NYMEX Gas 9%
Wattenberg Colorado Liquids Gas 4%
Michigan Mich-Con/NYMEX 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 March 31,
2009 2008
(in thousands)
Lifting cost, excluding production
taxes $ 10,321 $ 9,610
Production taxes 1,913 5,015
Costs for well operations segment 1,643 1,362
Overhead and other production
expenses 2,339 2,145
Total oil and gas production and
well operations cost $ 16,216 $ 18,132
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Lifting Costs. Lifting costs per Mcfe, excluding production taxes which fluctuate with oil and natural gas prices, decreased 17.7% to $0.93 per Mcfe for first quarter 2009 from $1.13 per Mcfe for first quarter 2008. The decrease is primarily due to a 31.5% increase in production, which allows us to spread the fixed portion of our production costs over an increased volume, thereby lowering the per unit cost. Additionally, lower oil and natural gas prices have also put pressure on oil and gas service providers to reduce their rates, for which we have started seeing the benefits. We expect a downward trend to continue until commodity prices rebound.
Production Taxes. Production taxes decreased $3.1 million or 61.9% to $1.9 million. This decrease is primarily related to the 40.9% decrease in oil and gas sales along with a decrease of $1.1 million in our estimated 2008 taxes.
Oil and Gas Price Risk Management, Net
Three Months Ended March 31,
2009 2008
(in thousands)
Oil and gas price risk management, net:
Realized gain (loss)
Oil $ 7,294 $ (1,306 )
Natural gas 29,332 (1,105 )
Total realized gain, net 36,626 (2,411 )
Reclassification of realized (gains) losses
included in prior periods unrealized (30,193 ) 351
Unrealized gains (losses) for the period 17,250 (40,250 )
$ 23,683 $ (42,310 )
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The net unrealized gain for first quarter 2009 of $17.3 million was primarily due to a $33 million net unrealized gain from our commodity derivatives offset in part by a decrease in fair value of our CIG basis protection swaps of $15.7 million. The net unrealized gain from commodity derivatives resulted from the continued decline in commodity prices during the first quarter. The unrealized loss from our CIG basis protection swaps resulted from a more significant decline in NYMEX pricing compared to CIG pricing. The realized gains from commodity derivatives resulted from the current realized prices being below our swaps and floor contract prices.
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 activities, which are included in sales from and cost of natural gas marketing activities. 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 Derivative Activities. 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 the collar arrangements, if the applicable index rises above the ceiling price or swap, we pay the counterparty; however, if the index drops below the floor or swap, the counterparty pays us.
The following table identifies our derivative positions (excluding the
derivative positions allocated to our affiliated partnerships) related to oil
and gas sales activities in effect as of March 31, 2009, on our production by
area. Our production volumes for first quarter 2009 were 343,884 Bbls of oil and
9.1 Bcf of natural gas. No new positions have been entered into subsequent to
March 31, 2009, through the date of this filing.
Floors Ceilings Swaps (Fixed Prices) Basis Protection Contracts Fair Value
Weighted Weighted Weighted Weighted At
Commodity/ Quantity Average Quantity Average Quantity Average Quantity Average March 31,
Index/ (Gas-MMbtu Contract (Gas-MMbtu Contract (Gas-MMbtu Contract (Gas-MMbtu Contract 2009
Operating Area Oil-Bbls) Price Oil-Bbls) Price Oil-Bbls) Price Oil-Bbls) Price (in thousands)
Natural Gas
Rocky Mountain Region
CIG
2Q 2009 3,641,103 $ 5.75 3,641,103 $ 8.90 - $ - - $ - $ 11,931
3Q 2009 3,641,103 5.75 3,641,103 8.90 - - - - 10,461
4Q 2009 2,656,180 6.70 2,656,180 10.26 1,008,939 9.20 - - 14,292
2010 2,845,497 6.84 2,845,497 10.93 1,513,408 9.20 6,957,835 1.88 9,664
2011 1,022,667 4.75 1,022,667 9.45 - - 7,651,364 1.88 (4,769 )
2012 - - - - - - 7,687,672 1.88 (5,623 )
2013 - - - - - - 6,888,618 1.88 (4,358 )
PEPL
2Q 2009 720,000 6.14 720,000 10.81 - - - - 2,426
3Q 2009 720,000 6.14 720,000 10.81 - - - - 1,957
4Q 2009 580,000 7.81 580,000 12.68 240,000 10.91 - - 3,909
2010 1,470,000 6.52 1,470,000 10.79 1,060,000 7.99 - - 5,858
2011 390,000 5.76 390,000 9.56 - - - - 218
NYMEX
2010 417,447 5.75 417,447 8.30 6,016,290 5.60 - - (1,123 )
2011 551,618 5.75 551,618 8.30 - - - - (84 )
Appalachian and Michigan Basins
NYMEX
2Q 2009 903,434 7.13 903,434 12.85 429,430 9.09 - - 5,309
3Q 2009 903,434 7.13 903,434 12.85 429,430 9.09 - - 4,842
4Q 2009 866,452 9.00 866,452 15.66 429,138 9.09 - - 5,343
2010 1,543,551 8.22 1,543,551 14.19 1,879,614 8.78 - - 9,503
2011 264,504 6.62 264,504 11.64 797,515 9.60 - - 2,411
2012 - - - - 154,379 9.89 - - 378
Total Natural Gas 72,545
Oil
Rocky Mountain Region
NYMEX
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