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TMCNet:  POSTROCK ENERGY CORP - 10-K - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

[March 28, 2014]

POSTROCK ENERGY CORP - 10-K - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Edgar Glimpses Via Acquire Media NewsEdge) The accompanying consolidated financial statements, including the notes thereto, contain detailed information that should be read in conjunction with the following discussion.

Overview of Our Company We are an independent oil and gas company engaged in the acquisition, exploration, development, production and gathering of crude oil and natural gas.

Our primary production activity is focused in the Cherokee Basin, a 15-county region in southeastern Kansas and northeastern Oklahoma, and Central Oklahoma.

We also have minor oil and gas producing properties in the Appalachian Basin. We previously owned an interstate natural gas pipeline which was sold in September 2012, and we report its results as a discontinued operation in our financial statements.


Strategy Our strategy is to acquire, develop and efficiently manage long-lived oil and gas properties and undeveloped leases in proven producing regions where we recognize the opportunity to add value through additional development, application of modern technologies and techniques, and efficiencies gained through consolidation. Our plans are to exploit our existing asset base and build regionally from our core operations, primarily in the Cherokee Basin and Central Oklahoma at present.

We are currently focused on increasing the percentage of oil and liquids in our production and reserves. As of and for the year ended December 31, 2012, our reserves and our production on an energy equivalent basis, included 19% and 3.4% oil, respectively. As of and for the year ended December 31, 2013, those percentages had increased to 23% and 7.4%, respectively. Our plan is to direct the substantial majority of development capital in 2014 toward oil weighted projects to continue accumulating oil production and reserve growth.

Key Factors Affecting Our Results of Operations •Realized natural gas prices were $3.55/Mcf during 2013 compared to $2.68/Mcf in 2012 and $3.98/Mcf in 2011.

•Low natural gas prices have resulted in reduced natural gas development, which has led to a decline in our natural gas production. Our natural gas production was 14.5 Bcf in 2013, 16.4 Bcf in 2012 and 18.3 Bcf in 2011.

•Realized oil prices were $94.56/Bbl during 2013 compared to $90.13/Bbl in 2012 and $90.60/Bbl in 2011.

•High oil prices have resulted in an increased focus on oil development, which has led to an increase in our oil production. Our oil production was 192,474 barrels in 2013, 95,863 barrels in 2012 and 78,087 barrels in 2011.

•We continued to focus on reducing our costs in both our field operations and our Oklahoma City office.

•Our employee headcount was 209, 216 and 301, at December 31, 2013, 2012 and 2011, respectively.

•Lease operating expenses and gathering expenses were $35.1 million during 2013 compared to $37.6 million in 2012 and $39.8 million in 2011.

•General and administrative expenses were $16.0 million during 2013 compared to $14.8 million in 2012 and $16.0 million in 2011.

•We closed three acquisitions in 2013 related to oil and gas properties in Central Oklahoma with a total purchase price of approximately $13.0 million.

27 -------------------------------------------------------------------------------- Table of Contents How We Evaluate Our Operations Management uses and expects to continue to use a variety of financial and operational metrics to analyze performance and the health of the business. These metrics focus on rates of return and cost efficiency with an emphasis on cash costs. A few of the metrics we focus on include: (1) volume and mix of production and reserves; (2) reserve life; (3) lease operating expense, gathering expense and general and administrative expense; (4) gathering throughput volumes, fuel consumption by our facilities and natural gas sales volumes; and (5) debt balances.

General Trends and Outlook Realized Prices We sell our Cherokee Basin gas production based on the Southern Star index. We sell the majority of our natural gas in the Appalachian Basin based on the Dominion Southpoint index, with the remainder sold on a local basis. The Southern Star prices typically are at a discount to the NYMEX pricing at Henry Hub, the regional pricing point, whereas Appalachian prices typically are at a premium to NYMEX pricing. During 2013, the basis discount in the Cherokee Basin ranged from $0.03 to $0.33/MMBtu. According to the U.S. Energy Information Administration ("EIA"), the Henry Hub spot price averaged $3.73 per MMBtu in 2013. NYMEX strip prices at March 3, 2014, average $4.54/MMBtu, $4.33/MMBtu, and $4.26/MMBtu for the forward 12, 24 and 36 month period, respectively. We sell the majority of our oil production under a contract priced at a fixed discount to NYMEX WTI oil prices. Oil and natural gas prices historically have been very volatile and will likely continue to be so in the future.

We utilize our hedging program to attempt to mitigate the risk that variability of commodity pricing creates for our cash flows. See Part II, Item 7A.

"Quantitative and Qualitative Disclosures About Market Risk" of this Annual Report on Form 10-K for further details on our hedging activity.

Supply and Demand of Oil and Gas North American crude oil and natural gas prices have historically been volatile based on supply and demand dynamics and we expect this volatility to continue into 2014. Although natural gas prices improved in 2013 compared to 2012, natural gas continues to be challenged due to an imbalance between supply and demand across North America. However, arctic air movements across North America during the early weeks of 2014 have caused natural gas demand to surge. As storage inventories have significantly declined in response to the recent weather conditions, natural gas prices have surpassed $5 per Mcf for the first time since the summer of 2010. Further helping demand, new uses of natural gas in industrial, power and other sectors will continue to help support price dynamics. Nevertheless, we still expect natural gas prices to be range-bound as natural gas supply continues to grow. Looking to 2014, we expect natural gas prices will remain relatively consistent or possibly increase moderately from 2013 levels.

Crude oil prices remained relatively stable throughout 2013, and oil continues to be more valuable than natural gas on a relative energy-equivalent basis. As a result, we and other producers have been focused on growing oil production.

North American crude oil supply continues to increase due to the continued use of horizontal drilling technology throughout the United States. Global crude oil demand is expected to grow with supply in 2014. As crude oil supply grows, transportation capacity to downstream markets will be increasingly important.

Bottlenecks and other transportation limitations may continue to add volatility among U.S. grades of oil. However, we expect 2014 oil prices will remain relatively consistent with 2013.

Drilling Programs Our 2013 exploration and development capital expenditures totaled $40.0 million.

Included in the $40.0 million, we successfully completed 152 new wells and recompleted 62 wells in the Cherokee Basin, completed three new wells and recompleted nine wells in Central Oklahoma, and recompleted a well in the Appalachian Basin. Our development activity in 2013 was directed toward increasing oil production and reserves in response to the low natural gas price environment. As a result of oil focused development, oil production in 2013 increased 101% over the prior year to 192,474 barrels while oil reserves increased from 2.7 MMBbl at year-end 2012 to 4.4 MMBbl at year-end 2013.

One of our most significant projects has been to reconfigure our entire compression system in the Cherokee Basin. This program was piloted with a proof of concept phase in 2012 and began to be fully implemented in 2013. We expect the project to be complete in the first half of 2014. The project is expected to cost approximately $8.2 million, with roughly $5.5 million of the project cost in 2014, and result in compression rental savings of approximately $3.2 million per year and to reduce fuel use of about 2.5 MMcf/d as compared to what it was prior to the project.

28 -------------------------------------------------------------------------------- Table of Contents Our focus for 2014 will continue to be on growing the percentage of oil included in our production and reserves through development, leasing, and opportunistic acquisitions. We have budgeted approximately $15.0 million for exploration and developmental drilling with the majority of our budget focused on horizontal oil wells in Central Oklahoma. If attractive opportunities arise, additional capital may be directed towards further oil development in Central Oklahoma. We intend to fund our 2014 capital expenditures with cash flow from operations and availability under our credit facility.

Results of Operations Year ended December 31, 2012 compared to the year ended December 31, 2013 The following table presents financial and operating data for the fiscal years ended December 31, 2012 and 2013.

Year Ended December 31, 2012 2013 Increase/(Decrease) ($ in thousands, except per unit data) Natural gas sales $ 43,911 $ 51,489 $ 7,578 17.3 % Crude oil sales $ 8,640 $ 18,200 $ 9,560 110.6 % Gathering revenue $ 2,444 $ 2,611 $ 167 6.8 % Production expense $ 42,213 $ 40,085 $ (2,128) (5.0) % Depreciation, depletion and amortization $ 27,669 $ 27,369 $ (300) (1.1) % Impairment of oil and gas assets $ 5,919 $ - $ (5,919) (100.0) % Gain (loss) on disposal of assets $ (295) $ 194 $ 489 (165.8) % Sales Data - Volumes Natural gas sales (MMcf) 16,389 14,521 (1,868) (11.4) % Oil sales (Bbls) 95,863 192,474 96,611 100.8 % Total sales (MMcfe) 16,964 15,676 (1,288) (7.6) % Average daily sales (MMcfe/d) 46.3 42.9 (3.4) (7.3) % Average Sales Price per Unit Natural gas (Mcf) $ 2.68 $ 3.55 $ 0.87 32.3 % Oil (Bbl) $ 90.13 $ 94.56 $ 4.43 4.9 % Natural gas equivalent (Mcfe) $ 3.10 $ 4.45 $ 1.35 43.5 % Average Unit Costs per Mcfe Production expense $ 2.49 $ 2.56 $ 0.07 2.8 % Depreciation, depletion and amortization $ 1.63 $ 1.75 $ 0.12 7.4 % Natural gas sales increased $7.6 million, or 17.3%, from $43.9 million for the year ended December 31, 2012, to $51.5 million for the year ended December 31, 2013. Higher realized natural gas prices increased revenues by $12.6 million while lower volumes decreased revenues by $5.0 million. Natural gas volumes decreased 1.9 Bcf due to continued suspension of our gas development throughout 2013 as oil development remained more attractive economically. Crude oil revenues increased $9.6 million, or 110.6%, from $8.6 million for the year ended December 31, 2012 to $18.2 million for the year ended December 31, 2013.

Increased oil volumes contributed $8.7 million of the increase in oil revenues.

Average realized natural gas prices increased from $2.68 per Mcf in 2012 to $3.55 per Mcf in 2013 while average oil prices increased from $90.13 per barrel in 2012 to $94.56 per barrel in 2013. Oil and gas sales exclude realized gains or losses from our derivative financial instruments.

Gathering revenue increased $167,000, or 6.8%, from $2.4 million for the year ended December 31, 2012, to $2.6 million for the year ended December 31, 2013.

The increase was due to higher gas prices during 2013.

Production expense consists of lease operating expenses, severance and ad valorem taxes and gathering expense. Production expense decreased $2.1 million, or 5.0%, from $42.2 million for the year ended December 31, 2012, to $40.1 million for the year ended December 31, 2013. Expense in 2012 included a $368,000 charge related to field reorganization. When this charge is excluded, production costs decreased $1.8 million, or 4.2%, from the prior year adjusted cost of $41.8 million. Lower compressor rental costs of $1.1 million, lower repairs and maintenance of $635,000, lower workover costs of $486,000, lower ad valorem taxes of $271,000, and reductions in other operational areas were partially offset by higher production taxes of $614,000 and higher electricity costs of $263,000. As a result of lower production volume, production expense per Mcfe increased from $2.49, or an adjusted $2.47, per Mcfe for the year ended December 31, 2012, to $2.56 per Mcfe for the year ended December 31, 2013.

29 -------------------------------------------------------------------------------- Table of Contents Depreciation, depletion and amortization remained relatively consistent from the prior year as it decreased $300,000 from $27.7 million for the year ended December 31, 2012, to $27.4 million for the year ended December 31, 2013. On a per unit basis, we had an increase of $0.12 per Mcfe from $1.63 per Mcfe for the year ended December 31, 2012, to $1.75 per Mcfe for the year ended December 31, 2013.

General and administrative expenses increased $1.2 million, or 8.0%, from $14.8 million for the year ended December 31, 2012, to $16.0 million for the year ended December 31, 2013. The 2012 period included a $503,000 charge related to reorganization of our Oklahoma City office and $2.2 million of non-cash compensation. Expense in 2013 included $1.6 million of legal fees related to the litigation with CEP and Sanchez Energy, a $454,000 workman's compensation charge, and $4.3 million of non-cash compensation. Excluding these charges, general and administrative expenses totaled $9.7 million, or 20.1%, lower than the prior year. The decrease was due primarily to reduced wages, benefits and bonuses of $601,000, higher capitalized labor of $434,000, and lower contract labor and other services of $299,000.

Other income (expense) consists primarily of realized and unrealized gains or losses from derivative instruments, gain or loss from equity investment, and net interest expense. We recorded a realized gain of $73.2 million and loss of $2.3 million on our derivative contracts for the years ended December 31, 2012 and 2013, respectively. We recorded a $66.7 million unrealized loss and a $1.7 million unrealized gain on our derivative contracts for the years ended December 31, 2012 and 2013, respectively. During 2012, we exited our above-market natural gas swap contracts, originally scheduled to settle in 2013, for proceeds of $30.2 million. These proceeds are included in the 2012 realized gains disclosed above. We recorded a mark-to-market loss of $5.2 million and a mark-to-market gain of $6.8 million on our equity investment in CEP for the years ended December 31, 2012 and 2013, respectively. The gain in 2013 was the result of an increase in the market price of CEP's publicly traded equity, which consequently increased the value of our investment. Interest expense, net, was $10.5 million and $3.7 million for the years ended December 31, 2012 and 2013, respectively.

Interest expense was lower as a result of reduced debt. We recorded a gain on forgiveness of debt of $255,000 for the year ended December 31, 2012 as a result of the restructuring of the QER Loan, discussed in Note 10 in Part II, Item 8.

"Financial Statements and Supplementary Data." There was no gain on forgiveness of debt for the year ended December 31, 2013.

We recorded a loss from discontinued operations of $2.9 million for the year ended December 31, 2012. The loss was related to the operations and subsequent sale of our interstate natural gas pipeline. There were no discontinued operations for the year ended December 31, 2013.

Year ended December 31, 2011 compared to the year ended December 31, 2012 The following table presents financial and operating data for the fiscal years ended December 31, 2011 and 2012.

Year Ended December 31, 2011 2012 Increase/(Decrease) ($ in thousands, except per unit data) Natural gas sales $ 72,812 $ 43,911 $ (28,901) (39.7) % Crude oil sales $ 7,075 $ 8,640 $ 1,565 22.1 % Gathering revenue $ 5,239 $ 2,444 $ (2,795) (53.3) % Production expense $ 47,136 $ 42,213 $ (4,923) (10.4) % Depreciation, depletion and amortization $ 24,088 $ 27,669 $ 3,581 14.9 % Impairment of oil and gas assets $ - $ 5,919 $ 5,919 * % Gain (loss) on disposal of assets $ 10,557 $ (295) $ (10,852) * % Sales Data - Volumes Natural gas sales (MMcf) 18,309 16,389 (1,920) (10.5) % Oil sales (Bbls) 78,087 95,863 17,776 22.8 % Total sales (MMcfe) 18,778 16,964 (1,814) (9.7) % Average daily sales (MMcfe/d) 51.4 46.3 (5.1) (9.9) % Average Sales Price per Unit Natural gas (Mcf) $ 3.98 $ 2.68 $ (1.30) (32.7) % Oil (Bbl) $ 90.60 $ 90.13 $ (0.47) (0.5) % Natural gas equivalent (Mcfe) $ 4.25 $ 3.10 $ (1.15) (27.1) % Average Unit Costs per Mcfe Production expense $ 2.51 $ 2.49 $ (0.02) (0.8) % Depreciation, depletion and amortization $ 1.28 $ 1.63 $ 0.35 27.3 % ____________ * Not meaningful.

30 -------------------------------------------------------------------------------- Table of Contents Natural gas sales decreased $28.9 million, or 39.7%, from $72.8 million for the year ended December 31, 2011, to $43.9 million for the year ended December 31, 2012. Lower realized natural gas prices decreased revenues by $21.3 million while lower volumes decreased revenues by $7.6 million. Natural gas volumes decreased 1.9 Bcf due to suspended gas development during the low gas price environment in 2012 and natural production declines. These decreases were partially offset by higher crude oil revenues of $1.6 million, which increased from $7.1 million during 2011 to $8.6 million during 2012, with most of the increase a result of higher volumes. Average realized natural gas prices decreased from $3.98 per Mcf in 2011 to $2.68 per Mcfe in 2012 while average oil price decreased from $90.60 per barrel in 2011 to $90.13 per barrel in 2012. Oil and gas sales exclude hedge settlements.

Gathering revenue decreased $2.8 million, or 53.3%, from $5.2 million during the year ended December 31, 2011, to $2.4 million during the year ended December 31, 2012. The decrease is primarily due to the settlement of the royalty lawsuits discussed below, which lowered the rates we receive for gathering royalty interest gas coupled with lower production volumes and lower realized prices.

Production expense decreased $4.9 million, or 10.4%, from $47.1 million during the year ended December 31, 2011, to $42.2 million during the year ended December 31, 2012. Expense in 2012 included a $368,000 charge related to our field reorganization in March 2012. Excluding this charge, production expense was $5.3 million lower than the prior year. The decrease was driven by lower labor costs of $2.0 million, lower repairs and maintenance of $1.0 million and lower vehicle and equipment costs of $1.7 million. These decreases are attributed to field efficiency projects that we began in the latter half of 2011 and continued in 2012. In addition, we incurred lower production taxes of $2.7 million partially driven by the decline in pricing and production. These cost reductions were partially offset by a reduction in capitalized costs of $2.1 million. Excluding the field reorganization charge, production expense per Mcfe decreased $0.04, or 1.6%, from $2.51 per Mcfe during the year ended December 31, 2011, to $2.47 per Mcfe during the year ended December 31, 2012.

Depreciation, depletion and amortization increased $3.6 million, or 14.9%, from $24.1 million during the year ended December 31, 2011, to $27.7 million during the year ended December 31, 2012. The increase was a result of a higher depreciation rate partially offset by a decline in production volumes. On a per unit basis, we had an increase of $0.35 per Mcfe from $1.28 per Mcfe during the year ended December 31, 2011, to $1.63 per Mcfe during the year ended December 31, 2012.

Impairment of our oil and gas properties was $5.9 million for the year ended December 31, 2012. We are required to assess the recoverability of the carrying value of our oil and gas properties against the present value of their future expected net revenues utilizing a twelve month average first of the month price for oil and natural gas. As a result of a decrease in the average natural gas price in 2012 relative to the prior year, the carrying value of our oil and natural gas properties exceeded the present value, thus requiring us to record an impairment during 2012.

We recorded a gain from the disposal of oil and gas assets of $10.6 million during the year ended December 31, 2011, compared to a loss of $295,000 during the year ended December 31, 2012. The gain in 2011 was primarily related to the second and third phases of the Appalachian Basin asset sale partially offset by $1.9 million of losses on the disposal of excess equipment.

General and administrative expenses decreased $1.2 million, or 7.4%, from $16.0 million during the year ended December 31, 2011, to $14.8 million during the year ended December 31, 2012. During the 2011 period, a $757,000 charge was recorded for the closure of our Houston office. During the 2012 period, a $503,000 severance charge was recorded for the restructuring of our Oklahoma City office. Excluding these charges, general and administrative expenses were $0.9 million, or 6.2%, lower than the prior year. The decrease was primarily due to reduced wages and benefits of $1.2 million and lower legal, accounting and audit fees of approximately $1.1 million. The reductions were partially offset by higher non-cash compensation expense of $837,000 and cash bonus compensation of $751,000. Non-cash compensation was higher as a result of the forfeiture of unvested grants in the prior-year period coupled with new award grants in the current year. Bonus compensation was higher as a result of growth in oil production and reserves, benchmarked against various other year-end performance metrics.

Litigation reserve was $11.6 million for the year ended December 31, 2011. The expense during 2011 was due to settlement costs for our royalty owner lawsuits in Oklahoma and Kansas. The royalty owner lawsuits included allegations that we failed to properly make payments to certain royalty owners in the past. Our Oklahoma royalty owner lawsuits were settled and funded in July 2011 for $5.6 million. Our Kansas royalty owner lawsuits were settled in December 2011 for $7.5 million with payments of $3.0 million and $4.5 million made in January 2012 and December 2012, respectively. As part of these settlements, all ambiguity in the calculation of prospective, as well as prior, royalties in our lease agreements was eliminated. Subsequent to the settlements, we have charged post-production costs to royalty and overriding royalty interest owners pursuant to an agreed upon formula. These settlements comprised the last material litigation or dispute related to our predecessor entities or management. The expense recorded in 2011 for these lawsuits established the $5.6 million reserve for the Oklahoma matters and increased the reserve for the Kansas lawsuit by $6.0 million.

31 -------------------------------------------------------------------------------- Table of Contents Other income (expense) consists primarily of gains (losses) from derivative instruments, gain (loss) from equity investment, gain from forgiveness of debt and net interest expense. We recorded realized gains of $33.7 million and $73.2 million on our derivative contracts for the years ended December 31, 2011 and 2012, respectively. We recorded a $1.7 million unrealized gain and a $66.7 million unrealized loss on our derivative contracts for the years ended December 31, 2011 and 2012, respectively. During 2012, we exited our above market natural gas swap contracts originally scheduled to settle in 2013 for proceeds of $30.2 million. These proceeds are included in the realized gains disclosed above. The mark-to-market losses on our equity investment in CEP were $4.6 million and $5.2 million for the years ended December 31, 2011 and 2012, respectively. These losses are the result of a decline in the market price of CEP's publicly traded equity, which consequently reduced the value of our investment. Interest expense, net, was $10.2 million and $10.5 million for the years ended December 31, 2011 and 2012, respectively. Although our debt was lower in 2012, interest expense was higher due to the $1.2 million write-off of unamortized debt fees associated with our previous credit facility upon the refinancing of that facility in December 2012. We recorded gains on forgiveness of debt of $1.6 million and $255,000 for the years ended December 31, 2011 and 2012, respectively. Both gains are the result of the restructuring of the QER Loan, discussed in Note 10 in Part II, Item 8. "Financial Statements and Supplementary Data." We recorded income from discontinued operations of $643,000 for the year ended December 31, 2011, compared to a loss of $2.9 million for the year ended December 31, 2012. The reduction was driven by the $5.4 million loss on the sale of KPC in September 2012 partially offset by a $1.9 million improvement in the operating results of the pipeline compared to the prior year. Prior to the sale of KPC, revenues were higher in 2012 as a result of increased throughput from growing gas volumes associated with oil production in Osage County, Oklahoma, while expenses were lower as the prior year included costs for a capacity lease that expired in October 2011, an external gas leak that occurred during the first quarter of 2011 and contract services that we did not require in the current year. These improvements more than offset the foregone net revenues from KPC subsequent to its sale in September 2012.

Liquidity and Capital Resources Debt Borrowings Our total debt increased from $57.5 million at December 31, 2012 to $92.0 million at December 31, 2013. The additional debt was used for capital expenditures, including acquisitions. We refinanced our existing credit facility in December 2012, resulting in a new, four-year $200 million senior secured revolving facility.

Historical Cash Flows and Liquidity Cash flows from operating activities have historically been driven by the quantities of our production and the prices received from the sale of this production. Prices of oil and gas have historically been very volatile and can significantly impact the cash from the sale of our production. Use of derivative financial instruments help mitigate this price volatility. Proceeds from or payments for derivative settlements are included in cash flows from operations.

Cash expenses also impact our operating cash flow and consist primarily of production operating costs, production taxes, interest on our indebtedness and general and administrative expenses.

Cash flows from operations totaled $42.7 million, $69.1 million and $11.2 million for the years ended December 31, 2011, 2012 and 2013, respectively. The decrease from 2012 to 2013 is mainly due to the significant reduction in realized cash from derivative contracts in 2013 compared to 2012. The increase from 2011 to 2012 is due to higher realized gains on derivative contracts and lower operating expenses compared to 2011, partially offset by lower revenues in 2012.

Cash flows from investing activities have historically been driven by exploration and development costs, leasehold acquisitions, acquisitions of businesses and sales of oil and gas properties. Net cash used in investing activities was $27.8 million and $49.7 million for the years ended December 31, 2011 and 2013, respectively, compared to net cash received of $35.6 million for the year ended December 31, 2012. Cash used in investing activities in 2013 was largely a result of $52.3 million of capital expenditures. Cash from investing activities in 2012 was the result of $53.4 million in gross proceeds from the KPC sale partially offset by $16.8 million of capital expenditures and $1.5 million set aside as restricted cash prior to our transitioning outstanding letters of credit to our new credit facility. Cash used in investing activities in 2011 was a result of $29.3 million of capital expenditures and $12.9 million of cash for our investment in CEP partially offset by proceeds of $14.4 million (including proceeds of $1.6 million from the sale of stock received as consideration) from asset sales primarily related to the Appalachian Basin sale.

32 -------------------------------------------------------------------------------- Table of Contents The following table sets forth our capital expenditures, including costs we have incurred but not paid for the periods presented: Year Ended December 31, 2011 2012 2013 (in thousands) Capital Expenditures Leasehold acquisition $ 853 $ 203 $ 16,590 Exploration - - - Development 23,825 12,506 40,004 Pipeline 839 563 - Other items 4,736 4,238 4,093Total capital expenditures $ 30,253 $ 17,510 $ 60,687 Cash flows from financing activities have historically been driven by borrowing and repayments on debt instruments, issuances of equity and the costs associated with these activities. Cash used in financing activities was $15.3 million and $104.6 million for the years ended December 31, 2011 and 2012, respectively, while cash from financing activities was $37.9 million for the year ended December 31, 2013. The cash from financing activities in 2013 was from borrowings from our Borrowing Base Facility and from issuance of $4.1 million of our common stock under our at-the-market sales agreement. The cash used in 2012 was primarily debt repayments of $193.0 million to settle our prior credit facilities along with debt and equity issuance costs of $2.3 million. These outflows were partially offset by $57.5 million in proceeds from our Borrowing Base Facility, $32.5 million in proceeds from the issuance of common stock, preferred stock and warrants to White Deer, and $724,000 in proceeds from the issuance of common stock under our at-the-market program described below. The cash used in 2011 was primarily due to $15.3 million in net repayments of debt.

KPC Sale On September 28, 2012, we sold our interstate pipeline subsidiary KPC to MV for $53.5 million in cash, $53.4 million net of a working capital adjustment. Of this amount, $500,000 was deposited into an escrow account pending the acceptable cleanup of a site previously owned by KPC. The cleanup was completed and the escrowed funds were released in January 2013. MV also agreed to make additional payments of $1.0 million for each of the next four years if qualified EBITDA, as defined in the purchase agreement, of KPC for that year exceeds a target amount.

White Deer Investment At December 31, 2013, White Deer holds $102.8 million in liquidation preference of our Series A Cumulative Redeemable Preferred Stock (the "Series A Preferred Stock") along with warrants to purchase 20,161,351 shares of our common stock at a weighted average exercise price of $1.54 per share. In addition, White Deer also holds 113,521 shares of our Series B Voting Preferred Stock (the "Series B Preferred Stock"), each share entitled to 100 votes, and 10,958,601 shares of our common stock. Our issuance of equity to White Deer occurred in five transactions as disclosed below.

•On September 21, 2010, we issued to White Deer $60 million initial liquidation preference of our Series A Preferred Stock along with 7 1/2 year warrants to purchase 19,047,619 shares of our common stock at an exercise price of $3.15 per share.

•On February 9, 2012, we issued to White Deer 2,180,233 shares of our common stock at $3.44 per share for an aggregate purchase price of $7.5 million.

•On August 1, 2012, we issued to White Deer 3,076,923 shares of our common stock at $1.95 per share, $6.0 million initial liquidation preference of our Series A Preferred Stock and warrants to purchase 3,076,923 shares of common stock at an exercise price of $1.95 per share. Total proceeds from the issuance were $12.0 million.

•On December 20, 2012, we issued to White Deer 4,577,464 shares of our common stock at $1.42 per share, $6.5 million initial liquidation preference of our Series A Preferred Stock and warrants to purchase 4,577,464 shares of common stock at an exercise price of $1.42 per share. Total proceeds from the issuance were $13.0 million.

•On December 13, 2013, we issued to White Deer 1,123,981 shares of our common stock with a fair value of $1.5 million in exchange for the retirement of warrants exercisable for 22,241,333 shares of our common stock together with a like number of one one-hundredths of a share of Series B Voting preferred Stock that were issued as a unit with the warrants. For additional details, see Note 12 in Part II, Item 8. "Financial Statements and Supplementary Data." 33 -------------------------------------------------------------------------------- Table of Contents The Series A Preferred Stock is entitled to a cumulative dividend of 12% per year on its liquidation preference, compounded quarterly. Prior to December 31, 2014, we can elect to pay dividends on the Series A Preferred Stock in cash.

During this period, if such dividends are not paid in cash, the liquidation preference of the Series A Preferred Stock will increase by the amount of the dividend and we will issue additional warrants exercisable for a number of shares of our common stock equal to the amount of the dividend divided by, with respect to the Series A Preferred Stock issued in September 2010, the closing price of the common stock on the trading day prior to the dividend payment date or, with respect to the Series A Preferred Stock issued in August and December 2012, $1.95 and $1.42, respectively, with the exercise price of such warrants equal to such applicable price.

We have not paid cash dividends since White Deer's initial investment in September 2010 but instead have chosen to increase the liquidation preference on the Series A Preferred Stock by $30.3 million, the cumulative amount of accrued dividends through December 31, 2013. Excluding the warrants retired in the Warrant Exchange, as a result of paying dividends in kind since the initial investment, we have also issued warrants to purchase 12,506,964 shares of our common stock at a weighted average exercise price of $1.48 per share. We are required to redeem the Series A Preferred Stock on March 21, 2018, at 100% of the liquidation preference. See Note 12 in Part II, Item 8 of this Annual Report for further details on the securities issued as a result of White Deer's investment.

Credit Agreement On December 20, 2012, we completed a refinancing of our existing revolving credit facility with a new group of banks. The refinancing was structured as an amendment to the existing facility to minimize costs. At refinancing, the existing facility was amended and restated by the Third Amended and Restated Credit Agreement (the "Borrowing Base Facility"). The Borrowing Base Facility, which is currently our sole credit facility, is a $200 million senior secured revolving facility secured by a first lien on substantially all of our assets except the assets of Constellation Energy Partners Management, LLC, one of our consolidated subsidiaries. See Note 10 in Part II, Item 8. in this Annual Report on Form 10-K for a summary of the material terms of this facility.

At December 31, 2013, the borrowing base under the Borrowing Base Facility was $115.0 million with outstanding borrowings of $92.0 million and $1.3 million in outstanding letters of credit. We had $21.7 million available under the Borrowing Base Facility at that date.

Sources of Liquidity in 2013 and Capital Requirements We rely on our cash flows from operating activities as a source of internally generated liquidity. During two of the past three years, our cash flows from operating activities have been sufficient to fund our investing activities. In 2013 we borrowed $34.5 million to fund capital expenditures. Our long-term ability to generate liquidity internally depends in part on our ability to hedge future production at attractive prices as well as our ability to control operating expenses. We generated cash of $33.7 million and $73.6 million from settlements of our oil and gas derivatives during 2011 and 2012, respectively, while we owed cash of $2.3 million in 2013. The cash we generated in 2012 includes $30.2 million from the early exit of above market natural gas swap contracts originally scheduled to settle in 2013. These contracts were settled early in connection with our debt refinancing in 2012. Our natural gas contracts that settled during 2010 to 2012 were entered into prior to 2010 and were priced in the range of $6.26 to $7.28 per MMBtu. We have natural gas and crude oil swap contracts covering a portion of our production between 2014 to 2016. At March 3, 2014, our outstanding natural gas swaps have a weighted average price of $4.01 per MMBtu while our open crude oil swaps have a weighted average price between $93.07 per barrel. Our outstanding contracts are disclosed below under Commodity Price Risk.

From time to time, we may issue equity to fund certain transactions, such as our CEP investment, to repay outstanding debt and for working capital purposes. As discussed above, we issued additional equity to White Deer on three separate occasions in 2012 for gross proceeds of $32.5 million.

We have an effective $100 million universal shelf registration statement on Form S-3. We are initially limited to selling debt or equity securities under the shelf registration statement in one or more offerings over a 12 consecutive month period for a total initial public offering price not exceeding one third of our public equity float. The registration statement is intended to give us the flexibility to sell securities if and when market conditions and circumstances warrant, to provide funding for growth or other strategic initiatives, for debt reduction or refinancing and for other general corporate purposes. The actual amount and type of securities or combination of securities and the terms of those securities will be determined at the time of sale, if such sale occurs. If and when a particular series of securities is offered, the prospectus supplement relating to that offering will set forth our intended use of the net proceeds. In addition, we have entered into an at-the-market issuance sales agreement with a sales agent relating to the offering from time to time of shares of our common stock under the shelf registration statement. Sales of shares of our common stock, if any, may be made directly on the NASDAQ Global Market, on any other existing trading market for the common stock or through a market maker, or in privately negotiated transactions, subject to our approval.

Our sales agreement is limited to the sale of up to a number of shares of common stock with an initial offering price not to exceed the amount that can be sold under the registration statement. As of the date of the 34 -------------------------------------------------------------------------------- Table of Contents sales agreement, such amount is limited to approximately $20.3 million. During the first half of 2013, we sold 2,592,313 shares of common stock under the program for $4.0 million, net of $115,000 in agent commissions. We renewed our at-the-market program in late August 2013. There were no sales of common stock in the third and fourth quarters.

We rely on our Borrowing Base Facility as an external source of long and short-term liquidity. At March 3, 2014, we had $95 million of outstanding borrowings and $20 million of availability under this facility. The borrowing base under our Borrowing Base Facility will be redetermined on May 1, 2014, based on reserves at December 31, 2013. The borrowing base under that facility is determined based on the value of our oil and natural gas reserves at our lenders' forward price forecasts, which are generally derived from futures prices. With the current availability under our Borrowing Base Facility and expected cash flows from operations, we believe that we have sufficient liquidity to fund our capital expenditures and financial obligations through 2014.

Contractual Obligations We have certain contractual commitments in the ordinary course of business, including debt service requirements, purchase obligations and operating lease commitments. The following table summarizes these commitments at December 31, 2013: Payments Due by Period Less Than 1 - 3 4 - 5 More Than Total 1 Year Years Years 5 Years (in thousands) Borrowing Base Facility $ 92,000 $ - $ 92,000 $ - $ - Interest on bank credit facility (1) 8,652 2,913 5,739 - - Purchase obligations 2,374 1,314 1,059 1 - Operating lease obligations 7,256 3,558 3,315 383 - Total commitments $ 110,282 $ 7,785 $ 102,113 $ 384 $ - ____________ (1) Interest due by period is an estimate as the credit facility has variable interest rate.

Off-Balance Sheet Arrangements At December 31, 2013, we did not have any relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. In addition, we do not engage in trading activities involving non-exchange traded contracts. As such, we are not exposed to any financing, liquidity, market, or credit risk that could arise if we had engaged in such activities.

Critical Accounting Policies The preparation of our consolidated financial statements requires us to make assumptions and estimates that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. We base our estimates on historical experiences and various other assumptions that we believe are reasonable; however, actual results may differ. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements.

Oil and Gas Reserves Our most significant financial estimates are based on estimates of proved oil and gas reserves. Proved reserves represent estimated quantities of oil and gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production, and timing of development expenditures, including many factors beyond our control. The estimation process relies on assumptions and interpretations of available geologic, geophysical, engineering, and production data and, the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geologic interpretation, and judgment. In addition, as a result of changing market conditions, commodity prices and future development costs will change from year to year, causing estimates of proved reserves to also change. Estimates of proved reserves are key components of our most significant financial estimates involving our unevaluated properties, our rate for recording depreciation, depletion and amortization and our full cost ceiling limitation. Our reserves are estimated on an annual basis by independent petroleum engineers.

35 -------------------------------------------------------------------------------- Table of Contents Oil and Natural Gas Properties The method of accounting for oil and gas properties determines what costs are capitalized and how these costs are ultimately matched with revenues and expenses. We use the full cost method of accounting for oil and natural gas properties. Under the full cost method, all direct costs and certain indirect costs associated with the acquisition, exploration, and development of our oil and gas properties are capitalized.

Oil and gas properties are depleted using the units-of-production method. The depletion expense is significantly affected by the unamortized historical and future development costs and the estimated proved oil and gas reserves.

Estimation of proved oil and gas reserves relies on professional judgment and the use of factors that cannot be precisely determined. Holding all other factors constant, if proved oil and gas reserves were revised upward or downward, earnings would increase or decrease, respectively. Subsequent proved reserve estimates that are materially different from those reported would change the depletion expense recognized during the future reporting period. No gains or losses are recognized upon the sale or disposition of oil and gas properties unless the sale or disposition would have a significant impact on the depreciation, depletion, and amortization rate.

Under the full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of future net revenues, discounted at 10% per annum, plus the lower of cost or fair value of unevaluated properties less income tax effects (the "ceiling limitation"). Future net revenues used to calculate the ceiling do not include cash outflows associated with settling asset retirement obligations. We perform a quarterly ceiling test to evaluate whether the net book value of our full cost pool exceeds the ceiling limitation.

If capitalized costs (net of accumulated depreciation, depletion, and amortization) less related deferred taxes are greater than the discounted future net revenues or ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of our full cost pool is a non-cash charge that reduces earnings and impacts stockholders' equity in the period of occurrence and typically results in lower depreciation, depletion, and amortization expense in future periods. Once incurred, a write-down is not reversible at a later date. The risk that we will be required to write-down the carrying value of our oil and natural gas properties increases during a period when oil or gas prices are depressed. In addition, a write-down may occur if estimates of proved reserves are substantially reduced or estimates of future development costs increase significantly.

Unevaluated Properties The costs directly associated with unevaluated properties and properties under development are not initially included in the amortization base and relate to unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination together with interest costs capitalized for these projects. Unevaluated leasehold costs are transferred to the amortization base once determination has been made or upon expiration of a lease. Geological and geophysical costs associated with a specific unevaluated property are transferred to the amortization base with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. All items included in our unevaluated property balance are assessed on a quarterly basis for possible impairment or reduction in value. Any impairment to unevaluated properties is transferred to the amortization base.

Future Abandonment Costs We have significant legal obligations to plug, abandon and dismantle existing wells and facilities that we have acquired, constructed, or developed.

Liabilities for asset retirement obligations are recorded at fair value in the period incurred. Upon initial recognition of the asset retirement liability, the asset retirement cost is capitalized by increasing the carrying amount of the long-lived asset by the same amount as the liability. Asset retirement costs included in the carrying amount of the related asset are subsequently allocated to expense as part of our depletion calculation. Additionally, increases in the discounted asset retirement liability resulting from the passage of time are recorded as depreciation expense.

Estimating the future asset retirement liability requires us to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. We use the present value of estimated cash flows related to our asset retirement obligations to determine the fair value.

Present value calculations inherently incorporate numerous assumptions and judgments. These include the ultimate retirement and restoration costs, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement liability, a corresponding adjustment will be made to the carrying cost of the related asset. There were no significant revisions for the years ended December 31, 2012 and 2013.

We have not recorded any asset retirement obligations relating to our gathering systems at December 31, 2012 and 2013 because we do not have any legal or constructive obligations relative to asset retirements of the gathering systems (see discussion in Note 9-Asset Retirement Obligations to the consolidated financial statements included in this Annual Report on Form 10-K).

36 -------------------------------------------------------------------------------- Table of Contents Derivative Instruments Due to the historical volatility of oil and gas prices, we have implemented a hedging strategy aimed at reducing the variability of prices we receive for our production. Currently, we may use collars, fixed-price swaps and fixed price sales contracts as our mechanism for hedging commodity prices. Our current derivative instruments are not accounted for as hedges for accounting purposes in accordance with FASB ASC 815 Derivatives and Hedging. As a result, we account for our derivative instruments on a mark-to-market basis, and changes in the fair value of derivative instruments are recognized as gains and losses which are included in other income and expense in the period of change. While we believe that the stabilization of prices and production afforded us by providing a revenue floor for our production is beneficial, this strategy may result in lower revenues than we would have if we were not a party to derivative instruments in times of rising natural gas prices. For the year ended December 31, 2013, we recognized a total loss on derivative financial instruments in the amount of $599,000, consisting of a $2.3 million realized loss and a $1.7 million unrealized gain. We currently estimate the fair value of our commodity swaps with a discounted cash flow model utilizing, when possible, published forward commodity price curves and credit adjusted discount rates.

Income Taxes We record our income taxes using an asset and liability approach in accordance with the provisions of FASB ASC 740 Income Taxes. We recognize deferred tax assets and liabilities for the expected future tax consequences of temporary differences (primarily property and equipment and the net operating loss carry forward) between the book carrying amounts and the tax bases of assets and liabilities using enacted tax rates at the end of the period. Under FASB ASC 740, the effect of a change in tax rates of deferred tax assets and liabilities is recognized in the year of the enacted change. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. At December 31, 2012 and 2013, a full valuation allowance was recorded against our deferred tax assets.

We have net operating loss ("NOL") carryforwards that are available to reduce our U.S. taxable future income. Our ability to utilize NOL carryforwards to reduce our future federal taxable income and federal income tax is subject to various limitations under Internal Revenue Code ("IRC") Section 382. The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the issuance or exercise of rights to acquire stock, the purchase or sale of stock by 5% stockholders, as defined in the Treasury regulations, and the offering of our stock during any three year period resulting in an aggregate change of more than 50% in the beneficial ownership of our Company. We experienced ownership changes within the meaning of IRC Section 382 on November 14, 2005, March 5, 2010, and September 21, 2010 and are therefore subject to IRC Section 382 limitations on our NOL carryforwards. See Note 11 in Part II, Item 8. of this Annual Report on Form 10-K for further discussion of these limitations.

FASB ASC 740 provides guidance on the measurement of the income tax benefit associated with uncertain tax positions, derecognition, classification, interest and penalties and financial statement disclosure. We regularly analyze tax positions taken or expected to be taken in a tax return based on the threshold condition prescribed under FASB ASC 740. Tax positions that do not meet or exceed this threshold condition are considered uncertain tax positions. We accrue interest and penalties related to uncertain tax positions as income tax expense.

Recent Accounting Pronouncements Recent accounting pronouncements relevant to us are discussed within Note 2 in Part II, Item 8. of this Annual Report on Form 10-K. There have been no recent accounting pronouncements that have had a material impact on our consolidated financial statements. Furthermore, we are not aware of any new accounting standards we will be required to adopt in the future that will have a material impact on our consolidated financial statements.

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