The discussion and analysis that follows should be read together with the accompanying financial statements and notes related thereto that are included elsewhere in this quarterly report on Form 10-Q. It includes forward-looking statements that may reflect our estimates, beliefs, plans and expected performance. The forward-looking statements are based upon events, risks and uncertainties that may be outside our control. Our actual results could differ significantly from those discussed in these forward-looking statements. Factors that could cause or contribute to these differences include, but are not limited to, market prices for natural gas and oil, regulatory changes, estimates of proved reserves, economic conditions, competitive conditions, development success rates, capital expenditures and other uncertainties, as well as those factors discussed below and elsewhere in this quarterly report on Form 10-Q and in our annual report on Form 10-K for the year ended December 31, 2007, including in "Risk Factors" and "Cautionary Statement Concerning Forward-Looking Statements," all of which are difficult to predict. As a result of these assumptions, risks and uncertainties, the forward-looking matters discussed may not occur.

Overview

We are an independent energy company engaged in the acquisition, exploration and development of domestic onshore natural gas reserves. We primarily focus our efforts on the development of coal bed methane (or CBM) properties located in the Powder River Basin in northeastern Wyoming and southern Montana. In addition, in April 2006, we acquired properties located in the Green River Basin in southern Wyoming. As of September 30, 2008, we owned natural gas and oil leasehold interests in approximately 494,000 gross (316,000 net) acres, approximately 93% of which were undeveloped. As of June 30, 2008, we had estimated net proved reserves of approximately 29.8 Bcf based on the CIG index price of $8.73 per Mcf.

We had a total capital expenditure budget of $30.1 million for 2008 and expected to drill 146 gross (110 net) wells during that period. However, due to low CIG index prices and limited capital resources, we have reduced our capital expenditure budget from $30.1 million to $26.6 million. We have curtailed substantially all new drilling for the remainder of 2008 and have shut in a number of wells that are not economic at current natural gas price levels, and if natural gas prices remain low, we may continue to operate with a reduced drilling plan through the first half of 2009. We incurred capital expenditures of approximately $26.1 million during the nine months ended September 30, 2008, primarily related to our drilling, completion and infrastructure costs on our Cabin Creek acreage, and drilled 115 gross (81 net) wells and completed 102 gross (70 net) wells during the nine months ended September 30, 2008. We operated 97% of those wells. During the fourth quarter of 2008, we expect to drill only 1 gross (0.9 net) well.

We were formed in June 2003 as a Delaware corporation through a contribution of proved producing properties and undeveloped leaseholds by subsidiaries of Carrizo Oil & Gas, Inc. and U.S. Energy Corporation and a cash contribution from funds affiliated with DLJ Merchant Banking.

In April 2006, we completed a private placement, exempt from registration under the Securities Act of 1933, of 12,835,230 shares of our common stock to qualified institutional buyers, non-U.S. persons and accredited investors. In May 2007, we completed our initial public offering of 3,750,000 shares of common stock. Shares of our common stock are traded on the NASDAQ Global Market under the symbol "PINN."

Critical Accounting Policies

The most subjective and complex judgments used in the preparation of our financial statements are:

† Reserve evaluation and determination;

† Estimates of the timing and cost of our future drilling activity;

† Estimates of the fair valuation of hedges in place;

† Estimates of timing and cost of asset retirement obligations;

† Estimates of the expense and timing of exercise of stock options;

† Accruals of operating costs, capital expenditures and revenue; and

† Estimates for litigation.

Oil and Gas Properties

We use the full cost method of accounting for oil and gas producing activities. Under this method, all costs associated with property acquisition, exploration and development, including costs of unsuccessful exploration, costs of surrendered and abandoned leaseholds, delay lease rentals and the fair value of estimated future costs of site restoration, dismantlement and abandonment activities, are capitalized within a cost center. Our oil and gas properties are all located within the United States, which constitutes a single cost center. We have not capitalized any overhead costs. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of gas properties and the gain significantly alters the relationship between capitalized costs and proved gas reserves of the cost center. Expenditures for maintenance and repairs are charged to lease operating expense in the period incurred.

Depreciation, depletion and amortization of oil and gas properties is computed on the unit-of-production method based on proved reserves. Amortizable costs include estimates of future development costs of proved undeveloped reserves and asset retirement obligations. We invest in unevaluated oil and gas properties for the purpose of exploration for proved reserves. The costs of such assets, including exploration costs on properties where a determination of whether proved oil and gas reserves will be established is still under evaluation, and any capitalized interest, are included in unproved oil and gas properties at the lower of cost or estimated fair market value and are not subject to amortization. On a quarterly basis, such costs are evaluated for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. We recorded an impairment of unevaluated properties of $1.6 million during each of the three and nine months ended September 30, 2008. Abandonment of unproved properties is accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized.

Substantially all remaining unproved property costs are expected to be developed and included in the amortization base ratably over the next three to five years. Salvage value is taken into account in determining depletion rates and is based on our estimate of the value of equipment and supplies at the time the well is abandoned. As of September 30, 2008 and December 31, 2007, the estimated salvage value was $7.3 million and $6.4 million, respectively.

Under full cost method of accounting rules, capitalized costs less accumulated depletion and related deferred income taxes may not exceed a "ceiling" value which is the sum of (1) the present value discounted at 10% of estimated future net revenue using current prices and costs, including the effects of derivative instruments designated as cash flow hedges but excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, less any related income tax effects, plus (2) the cost of properties not being amortized, if any, plus (3) the lower of costs or estimated fair value of unproved properties, less (4) the income tax effects related to differences in the book to tax basis of oil and gas properties. This is referred to as the "full cost ceiling limitation." If capitalized costs exceed the limit, the excess must be charged to expense. The expense may not be reversed in future periods. At the end of each quarter, we calculate the full cost ceiling limitation. At September 30, 2008, the capitalized cost of our oil and gas properties exceeded the full cost ceiling limitation by approximately $21.4 million based upon a natural gas price of $3.62 per Mcf (based on the Colorado Interstate Gas Rocky Mountain Index) in effect at that date. Based on the subsequent price increase to approximately $4.95 per Mcf at the measurement date of November 11, 2008, the full cost ceiling limitation exceeded the capitalized cost of our oil and gas properties by approximately $2.6 million. Therefore, the Company did not record an impairment for the three and nine months ended September 30, 2008. An impairment of approximately $18.2 million was recorded for the nine months ended September 30, 2007. The impairment of our oil and gas properties resulted from low commodity prices throughout 2007, specifically at the end of the first, second and third quarters of 2007. A decline in gas prices or an increase in operating costs subsequent to the measurement date or reductions in economically recoverable reserve quantities could result in the recognition of additional impairments of our oil and gas properties in future periods.

Gas Sales

We use the sales method for recording natural gas sales. Sales of gas applicable to our interest in producing natural gas and oil leases are recorded as revenues when the gas is metered and title transferred pursuant to the gas sales contracts covering our interest in gas reserves. During such times as our sales of gas exceed our pro rata ownership in a well, such sales are recorded as revenues unless total sales from the well have exceeded our share of estimated total gas reserves underlying the property at which time such excess is recorded as a gas imbalance liability. At September 30, 2008 and December 31, 2007, there was no such liability recorded. Although there was no such liability recorded for prior periods, gas reserves are an estimate and are updated on an annual and interim basis. Gas pricing, expenses and production may impact future gas reserves remaining which, in turn, could impact the recording of liabilities in the future. Gas sales accruals at September 30, 2008 and December 31, 2007 were based on the actual volume statements from our purchasers and distribution process. If accruals were to change by 10% at September 30, 2008 and at December 31, 2007, the impact would have been $100,000 and $306,000, respectively.

Asset Retirement Obligations

We follow the provisions of Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for the Asset Retirement Obligations." SFAS No. 143 generally applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 requires us to recognize an estimated liability for costs associated with the abandonment of our oil and gas properties.

A liability for the fair value of an asset retirement obligation with a corresponding increase to the carrying value of the related long-lived asset is recorded at the time a well is completed or acquired. The increased carrying value is depleted using the units-of-production method, and the discounted liability is increased through accretion over the remaining life of the respective oil and gas properties.

The estimated liability is based on historical gas industry experience in abandoning wells, including estimated economic lives, external estimates as to the cost to abandon the wells in the future and federal and state regulatory requirements. Our liability is discounted using our best estimate of our credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in estimated abandonment costs, changes in well economic lives or if federal or state regulators enact new requirements regarding the abandonment of wells. For example, a 10% change in our estimated retirement costs would have a $331,000 effect on our asset retirement obligation liability at September 30, 2008.

The following is a summary of our asset retirement obligation activity for the three and nine months ended September 30, 2008 and 2007 (in thousands):

                                        Three              Nine               Three              Nine
                                    Months Ended       Months Ended       Months Ended       Months Ended
                                    September 30,      September 30,      September 30,      September 30,
                                                  2008                                  2007
                                              (unaudited)                           (unaudited)
Beginning balance asset
retirement obligations             $         3,154    $         2,767    $         2,533    $         2,321
Additional obligations added
during the period                              142                410                 69                182
Obligations settled during the
period                                         (48 )              (48 )                -                  -
Accretion expense                               66                185                 53                152
Ending balance of asset
retirement obligations             $         3,314    $         3,314    $         2,655    $         2,655

Inventory

We acquired inventory of oil and gas equipment, primarily tubulars, in 2007 and 2008 to take advantage of quantity pricing and to secure a readily available supply. Inventory is valued at the lower of average cost or market. Inventory is used in the development of gas properties and to the extent it is estimated that it will be billed to other working interest owners during the next year, it is included in current assets. Otherwise, it is recorded in non-current assets. The price of steel is a primary factor in valuing our inventory. Under the valuation method of lower of average cost or market, a 10% reduction in the price of steel would cause a $67,000 reduction in our inventory valuation as of September 30, 2008. The market price of steel is evaluated each quarter using prices quoted by authorized vendors in the area.

Property and Equipment

Property and equipment is comprised primarily of a building, computer hardware and software, vehicles and equipment, and is recorded at cost. Renewals and betterments that substantially extend the useful lives of the assets are capitalized. Maintenance and repairs are expensed when incurred. Depreciation and amortization are provided using the straight-line method over the estimated useful lives of the assets, ranging as follows: buildings-30 years, computer hardware and software-3 to 5 years, machinery, equipment and vehicles-5 years, and office furniture and equipment-3 to 5 years.

General and Administrative Expenses

General and administrative expenses are reported net of amounts allocated and billed to working interest owners of gas properties operated by us. The administrative expenses billed to working interest owners may change in accordance with the terms of the joint operating agreements. Administrative expenses are charged to working interest owners based on productive well counts. A 10% change in well counts for the three and nine months ended September 30, 2008 would have increased or decreased our expenses billed to working interest owners by approximately $54,000 and $145,000, respectively. As we operate and drill additional wells in the future, additional administrative expenses will be charged to the working interest owners when the wells become productive. General and administrative expenses for the nine months ended September 30, 2008 also include $2.1 million of merger related costs attributable to the failed merger with Quest Resource Corporation.

Income Taxes

We use the asset and liability method of accounting for income taxes, in accordance with SFAS No. 109, "Accounting for Income Taxes." Deferred tax assets and liabilities are recognized for the expected future tax consequences of temporary differences between the financial statement and tax bases of assets and liabilities. If appropriate, deferred tax assets are reduced by a valuation allowance which reflects expectations of the extent to which such assets will be realized. As of September 30, 2008 and December 31, 2007, we had recorded a full valuation allowance for our net deferred tax asset.

On January 1, 2007, we adopted the Financial Accounting Standards Board Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109" (FIN 48). FIN 48 prescribes a measurement process for recording in the financial statements uncertain tax positions taken or expected to be taken in a tax return. Additionally, FIN 48 provides guidance regarding uncertain tax positions relating to derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. At September 30, 2008, we had no material uncertain tax positions or penalties or interest recorded.

Derivatives

We use derivative instruments to manage our exposure to fluctuating natural gas prices through the use of natural gas swap and option contracts. We account for derivative instruments or hedging activities under the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 requires us to record derivative instruments at their fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income (loss) and are recognized in the statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges, if any, are recognized in earnings. Changes in the fair value of derivatives that do not qualify for hedge treatment are recognized in earnings. Please see Note 5 of the notes to the unaudited financial statements appearing elsewhere in this quarterly report for additional discussion of derivatives.

We periodically hedge a portion of our oil and gas production through swap and collar agreements. The purpose of the hedges is to provide a measure of stability to our cash flows in an environment of volatile oil and gas prices and to manage the exposure to commodity price risk. Our management decided not to use hedge accounting for these agreements. Therefore, in accordance with the provisions of SFAS No. 133, the changes in fair market value are recognized in earnings.

Stock-Based Compensation

Effective January 1, 2006, we adopted SFAS No. 123(R), "Share-Based Payments," which requires companies to recognize compensation expense for share-based payments based on the estimated fair value of the awards. SFAS No. 123(R) also requires that the benefits of tax deductions in excess of compensation cost recognized for stock awards and options ("excess tax benefits") be presented as financing cash inflows in the Statement of Cash Flows.

Accounts Receivable

Our revenue producing activities are conducted primarily in Wyoming. We grant credit to qualified customers, which potentially subjects us to credit risk resulting from, among other factors, adverse changes in the industry in which we operate and the financial condition of our customers. We continuously monitor collections and payments from our customers and, if necessary, record an allowance for doubtful accounts based upon historical experience and any specific customer collection issues identified. We recorded an allowance of $100,000 at each of September 30, 2008 and December 31, 2007.

Transportation Costs

We account for transportation costs under Emerging Issues Task Force Issues 00-10, "Accounting for Shipping and Handling Fees and Costs," whereby amounts paid for transportation are classified as operating expenses.

Legal Estimates

From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. We account for these costs under SFAS No. 5, "Accounting for Contingencies," which states that a loss contingency be recorded if it is probable that a liability has been incurred and it is reasonably estimatable. At each of September 30, 2008 and December 31, 2007, we recorded no liability for legal proceedings.

Per Share Information

Basic earnings (loss) per share is computed by dividing net income (loss) from continuing operations attributable to common stock by the weighted average number of shares of common stock outstanding during each period. Diluted earnings per share is computed by adjusting the average number of shares of common stock outstanding for the dilutive effect, if any, of common stock equivalents such as stock options and warrants. For the three months ended September 30, 2008, diluted net income per share was $0.30, while basic net income per share was $0.31. Certain options to purchase shares of our common stock were excluded from the dilution calculations because the shares were anti-dilutive. During the nine months ended September 30, 2008, 717,500 options were excluded because they were anti-dilutive. During the nine months ended September 30, 2007, 907,000 options were excluded because they were anti-dilutive.

Recent Accounting Pronouncements

For information concerning recent accounting pronouncements, please see Note 2 of the notes to the unaudited financial statements appearing elsewhere in this quarterly report.

Trends Affecting Our Business

We have experienced increasing costs since our inception in 2003 due to increased demand for oilfield products and services. The cyclical nature of the natural gas industry causes fluctuations in demand for goods and services from oilfield companies, suppliers and others associated with the industry, which in turn affects the prices for those goods and services. Typically, as prices for natural gas increase, so do all the costs associated with natural gas production. Recently, we have seen increases in the cost of tubulars, drilling rigs and cement in particular. We expect that increased demand for the goods and services we use in our business will continue to put pressure on prices in the near to medium term.

Historically, natural gas prices have been extremely volatile, and we expect that volatility to continue. For example, during each of the three and nine months ended September 30, 2008, the NYMEX natural gas index price ranged from a high of $13.58 per MMBtu to a low of $7.22 per MMBtu, while the CIG natural gas index price ranged from a high of $10.26 per MMBtu to a low of $1.00 per MMBtu. During the year ended December 31, 2007, the NYMEX natural gas index price ranged from a high of $8.64 per MMBtu to a low of $5.38 per MMBtu, while the CIG natural gas index price ranged from a high of $7.11 per MMBtu to a low of $0.06 per MMBtu. Changes in natural gas pricing have impacted our revenue streams, production taxes, prices used in reserve calculations, borrowing base calculations and the valuation of potential property acquisitions. During the three and nine months ended September 30, 2008, estimated future gas prices had an impact on both our revenues and the costs attributable to our future operations. We expect that changing natural gas prices will continue to impact our operations and financial results in the future.

Transportation of natural gas and access to throughput capacity have a direct impact on natural gas prices in the Rocky Mountain region, where our operations are concentrated. As drilling activity increases throughout the Rocky Mountain region, additional production may come on line, which could cause bottlenecks or capacity constraints. Generally speaking, a surplus of natural gas production relative to available transportation capacity has a negative impact on prices. Conversely, as capacity increases, and bottlenecks are eliminated, prices generally increase. Although there is currently adequate transportation capacity out of the Powder River Basin, a surplus of natural gas arriving at key marketing hubs from the Powder River Basin and elsewhere relative to available takeaway capacity from these hubs has caused Rocky Mountain gas to generally trade at a discount to the NYMEX natural gas index price. The Rockies Express Pipeline, which was completed to Audrain County, Missouri in early 2008, has increased takeaway capacity by approximately 2 Bcf per day from these hubs. We expect that the completion of additional proposed pipelines will help reduce the differential between gas produced in the Rocky Mountain region and the NYMEX natural gas index price.

Results of Operations

Net income attributable to stockholders for the three months ended September 30, 2008 was $8.9 million, or $0.30 per diluted share, on total revenues of $5.7 million. Net income attributable to stockholders for the three months ended September 30, 2008 included a $10.0 million unrealized gain associated with the change in the fair valuation of our natural gas hedges in place in accordance with the provisions of SFAS No. 133. Absent such a change in the valuation, we would have shown a net loss attributable to stockholders of $1.1 million. This compares to a net loss attributable to stockholders of $1.2 million for the three months ended September 30, 2007 on total revenues of $2.7 million. Adjusted for an unrealized loss in the fair valuation of our natural gas hedges in place of $0.02 million, our results for the three months ended September 30, 2007 would have been a net loss attributable to stockholders of $1.2 million.

Net loss attributable to stockholders for the nine months ended September 30, 2008 was $0.6 million, or $0.02 per diluted share, on total revenues of $18.9 million. Net loss attributable to stockholders for the nine months ended September 30, 2008 included a $3.5 million unrealized gain associated with the change in the fair valuation of our natural gas hedges in place in accordance with the provisions of SFAS No. 133. Absent such a change in the valuation, we would have shown a net loss attributable to stockholders of $4.1 million. This compares to a reported net loss attributable to stockholders of $21.4 million for the nine months ended September 30, 2007 on total revenues of $9.8 million. Adjusted for an unrealized loss in the fair valuation of our natural gas hedges in place of $1.2 million, our results for the nine months ended September 30, 2007 would have been a net loss attributable to stockholders of $20.2 million.

In order to provide a measure of stability to the cash flow in an environment of volatile oil and gas prices and to manage the exposure to commodity price risk, we choose to periodically hedge a portion of our oil and gas production using swap and collar agreements. We account for our derivative instruments under the provisions of SFAS No. 133. SFAS No. 133 requires us to record derivative instruments at their fair value. Management has chosen not to use hedge accounting for these arrangements. Therefore, in accordance with SFAS No. 133, changes in the fair market value are recognized in earnings.

Three Months Ended September 30, 2008 Compared to Three Months Ended . . .