Replies to This Discussion

Permalink Reply by Skip Peel - Mineral Consultant on February 4, 2013 at 7:03

If Pegasi had the prospects that they claim, it's likely a larger energy company would have bought them out or acquired a controlling interest in their leasehold before now.  I would suggest a skeptical approach to Pegasi's public announcements.  We've been discussing them now for a couple of years with little actual development activity having occurred. 

Permalink Reply by Cass County Gal on February 4, 2013 at 9:07

Ah!  Good to know!  Our lease with them is up next year.  We shall see what, if anything, happens!  Thank you so much!

Permalink Reply by Dats Oil Brother on March 27, 2013 at 5:04

Damon, can you provide a source for this info? Stock has been rather strong the last month or two.

Permalink Reply by Cass County Gal on March 27, 2013 at 8:03

I saw that as well.  Having a hard time finding out anything recent

Permalink Reply by Dats Oil Brother on March 27, 2013 at 8:34

They have done a terrible job CC Gal. They will be reporting numbers on 4/1. Maybe we get an Operational Update along with it. Don't know if Damon's post (that disappeared) about Pegasi selling interests in CC, has any merit.

Permalink Reply by Cass County Gal on March 27, 2013 at 8:51

Wow!  I would have thought otherwise from what little I've read.  I thought their first horizontal drill was successful & they were on to the 2nd?  My fingers are crossed, however :)

Permalink Reply by Dats Oil Brother on March 27, 2013 at 10:42

I should clarify. They have done a terrible job keeping people updated. The first well had some issues but it was successful enough to pursue a larger project there.....15 stage HZ well. They go out and raise $4 million for that purpose 6 months ago and then they just vanish. They owe some answers to shareholders. Maybe we get them on 4/1.

Permalink Reply by Skip Peel - Mineral Consultant on March 27, 2013 at 10:54

I'm unsure that any company could drill and complete a 15 stage horizontal well for $4M even if it had a TVD of less than 5000' and a MD of <10000'.  The formations that Pegasi has touted are a good deal deeper.  A well to that depth with a 15 stage lateral would cost 2 to 3 times $4M.

Permalink Reply by Dats Oil Brother on March 28, 2013 at 4:45

You're right Skip. Although, I believe Pegasi only has a 56% interest ( I could be off with this number), $4mm is still not enough. We need an update about what happened to the $4mm, intentions to raise more, and plans for operations in CC.

Permalink Reply by Cass County Gal on March 28, 2013 at 6:31

This is the latest I've found and it's dated March 2013:

Our business strategy in what we have designated the "Cornerstone Project", is to identify and exploit resources in and adjacent to existing or indicated producing areas within the mature Rodessa field. We believe that we are uniquely familiar with the history and geology of the Cornerstone Project area based on our collective experience in the region as well as through our development and ownership of a large proprietary database which details the drilling history of the Cornerstone Project area since 1980. We plan to develop and produce reserves at low cost and will take an aggressive approach to exploiting our contiguous acreage position through utilization of the latest "best in class" drilling and completion techniques. In 2012 we drilled the Morse #1-H well targeting the Bossier formation and completed it using hydraulic fracture stimulation techniques. The Morse #1-H is the first such horizontal well completed in the Rodessa field and we believe that implementing the latest proven drilling and completion techniques to exploit our geological insight in the Cornerstone Project area will enable us to find significant oil and gas reserves.

Plan of Operations

Our corporate strategy can be thought of in terms of the acquisition of leases and the development of resources on leased acreage.

Acquisition of Leases in the Cornerstone Project area

As of March 1, 2013, our leasehold position is approximately 31,697 gross acres and 22,059 net acres, of which our working interest is approximately 12,976 net acres.

� Supporting Our Drilling Program. Our priority is now drilling, and consequently, our leasing program's primary objective is to support our planned drilling program by securing holdout leases in those units where we plan to drill over the next twelve months and renewing leases that are due to expire in those units where we plan to drill.

� Acquiring Additional Drilling Locations. We have an extensive proprietary database that we use to identify additional drilling locations and target acreage for acquisition in the Cornerstone Project area. Most properties in the project area are held by smaller independent companies that lack the resources and expertise to exploit them fully. We intend to pursue these opportunities to selectively expand our portfolio of properties. Acreage additions will complement our existing substantial acreage position in the area and provide us with additional drilling opportunities. During 2011, we completed our lease program with two lease fund partners from which we received $5.2 million. We are in discussion with prospective partners to establish a new lease fund to acquire new acreage in 2013.

Development of Resources in the Cornerstone Project area

Over two-thirds of our net leased acreage is currently undeveloped (approximately 8,764 undeveloped net acres of a total of 12,976 net acres as of March 1, 2013). The primary focus of the Company's drilling program is to develop the resources of these undeveloped acres and subsequently hold this acreage with production rather than to develop the Company's existing reserves on developed acreage.

� Horizontal Wells Targeting the Bossier/Cotton Valley Limestone. Our priority is to drill horizontal wells targeting the Bossier/Cotton Valley Limestone. We will employ the latest horizontal drilling and dynamic multi-stage fracking techniques that have proven so successful in the Bakken Shale in North Dakota and elsewhere to develop the low permeability oil bearing Bossier and Cotton Valley Limestone formations. Our first horizontal well, the Morse #1, was drilled with a 2,000 foot horizontal section. This well was completed with a five?stage frack and recorded an average production rate of 281 Bbl/day of high quality crude oil in its first five days of production. The Morse #1 began production on July 3, 2012, and produced a total of approximately 20,600 Bbl of oil and 20,100 MCF of gas in 2012. A jet pump system was initially employed to assist production and the well was later shut in for a period of 33 days between August and September 2012 for the installation of a gas lift production system. Following the introduction of the gas lift system on September 18, 2012, the well produced an average of approximately 202 Bbl/day of oil and 235 MCF of gas per day for the rest of September. The well's production declined abruptly in mid-October before stabilizing at approximately 100 Bbl/day of oil and 125 MCF of gas per day and later declined abruptly again in late December before stabilizing at approximately 50 Bbl/day of oil and 75 MCF of gas per day. The abrupt nature of the declines in production and other factors lead us to believe that a mechanical problem involving an obstruction of or constriction to the production tubing system is the cause of the decline in production rather than the depletion of the reservoir. The well was shut in on February 25, 2013 for the performance of a remedial work-over operation. The well returned to production on March 19, 2013, and in the seven days thereafter, produced an average of 92 Bbl/day of oil and 118 MCF of gas per day. We expect this improved production rate to subsequently decline over time as the reservoir depletes, albeit at a more gradual rate than previously observed. We believe that the successful production of oil from the Morse #1 supports our development strategy. We have learned much from the drilling, completion and production of the Morse #1 that will enable us to improve the design and execution of our next planned horizontal well targeting the Bossier/Cotton Valley Limestone. Having proven our development model, we now plan to drill wells with longer laterals involving 15 to 25 frack stages to improve the well economics. We have obtained the necessary permits for drilling our next horizontal well and hope to commence drilling operations in the second quarter of 2013, subject to the participation of working interest partners. We have a 56% working interest in the Morse #1 well.

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� Vertical Wells. Our secondary priority is to drill vertical wells to offset the Norbord #1 discovery of 2010 in the Travis Peak and to recomplete existing wells to maximize their present value by utilizing a multi-zone production technique. During 2012, we drilled two vertical wells to offset the Norbord discovery of 2010. We successfully completed the Haggard B well in May 2012 and it began production in June 2012. By January 31, 2013, the Haggard B had produced 109,390 MCF of gas and 921 Bbls of condensate from the Travis Peak formation. In addition, we drilled the Haggard A in 2012 and suspended operations pending completion in the Travis Peak formation with fracture stimulation. The completion operation of the Haggard A is currently underway and is expected to finish in April 2013. The Norbord #1 ceased production from the Travis Peak formation in September 2012. In November 2012, we performed a work-over of the well bore to isolate and test perforations. A production test of an oil-bearing zone is scheduled to be completed by the end of March 2013.

Consolidated Results of Operations

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011 Summarized Consolidated Results of Operations Increase 2012 2011 (Decrease) Total revenues $ 1,546,861 $ 1,188,282 $ 358,579 Total other operating expenses 7,401,071 3,133,228 4,267,843 Loss from operations (5,854,210) (1,944,946 ) 3,909,264 Total other expenses (665,567) (3,409,063 ) (2,743,496) Loss from continuing operations before income tax benefit (6,519,777) (5,354,009 ) 1,165,768 Income tax benefit (expense) (3,515) 274,813 (278,328) Loss from continuing operations (6,523,292) (5,079,196 ) 1,444,096 Income from discontinued operations, net of tax - 510,368 (510,368) Net loss $ (6,523,292) $ (4,568,828 ) $ 1,954,464

Revenues: Total revenues for the year ended December 31, 2012 totaled $1,546,861 compared to $1,188,282 for the year ended December 31, 2011. Oil revenue for the year ended December 31, 2012 was $1,067,113 compared to $385,662 for the year ended December 31, 2011. The majority of this increase of $681,451 was from the completion of the Morse horizontal well in the third quarter of 2012, which generated $689,588 in revenue for the year ended December 31, 2012. This was offset by lower production on some of the older wells. Gas revenue for the year ended December 31, 2012 was $292,412 compared to $452,934 for the year ended December 31, 2011, resulting in a decrease of $160,522. The decrease in gas revenue was mainly due to a decrease in the average price of gas of approximately 31%. In addition, production decreased on the Norbord well in August 2012 due to the depletion of its reservoir. Transportation and gathering revenue decreased $151,106 to $144,693 for the year ended December 31, 2012, compared to $295,799 for the year ended December 31, 2011. The decrease was due to a third party operator who began handling the income from gas being carried through our pipeline in February of 2011 and a decrease in gas production from the Norbord well. Condensate and skim oil was $42,643 and $53,887 for the year ended December 31, 2012 and December 31, 2011, respectively. Condensate and skim oil are by-products from drilling and are only sold when a sufficient amount has been collected, resulting in fluctuations from year to year.

Expenses: Total operating expenses for the year ended December 31, 2012 were $7,401,071, compared to $3,133,228 for the year ended December 31, 2011, resulting in a total increase of $4,267,843. This change is comprised primarily of increases in lease operating expenses, depletion and depreciation, and general and administrative expenses offset by a decrease in cost of gas purchased for resale.

? Lease Operating Expenses: Total lease operating expenses for the year ended December 31, 2012 were $647,749 compared to $443,588 for the year ended December 31, 2011, which resulted in an increase of $204,161. The primary reason for the increase was the completion of the Morse well in October 2012, which resulted in lease operating expenses of $175,744 and production taxes of $31,783 in 2012.

? Depletion and Depreciation: The $150,631 increase in depletion and depreciation to $427,701 for the year ended December 31, 2012 from $277,070 for the year ended December 31, 2011 was primarily due to an increase in the production of oil in 2012. The production in 2012 was 29,730 MBoe for the year compared to 23,640 MBoe for the year 2011. This increase in production caused the percentage of depletion taken to increase, which in turn increased depletion expense.

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? General and Administrative Expense: There was a $4,020,654 increase in general and administrative expense to $6,196,172 for the year ended December 31, 2012, from $2,175,518 for the year ended December 31,2011. The primary reason for the increase was stock-based compensation of $2,719,888 incurred during the year ended December 31, 2012, whereas there was no stock-based compensation incurred in the year ended December 31, 2011. The compensation resulted from the issuance of stock options to selected employees, executives, directors, and consultants as incentive for continuing our development.

Investor relations consulting fees increased $1,170,759 to $1,257,013 for the year ended December 31, 2012, due to contracts we engaged in with several companies to assist us with the implementation and maintenance of ongoing programs to increase the investment community's awareness of our activities, stimulate their interest in us and assist with our press release production and dissemination We paid two of these companies with shares of our common stock during 2012, which were valued at $895,500 using the closing market price on the date of grant.

In addition, fees for management consulting were $20,000 for the year ended December 31, 2011 compared to $175,219 for the year ended December 31, 2012 resulting in an increase of $155,219. The majority of the increase was due to $116,719 paid for contract CFO services prior to the employment of such consultant as our new CFO effective October 5, 2012.

? Cost of Gas Purchased for Resale: Total cost of gas purchased for resale for the year ended December 31, 2012 was $-0- compared to $94,814 for the year ended December 31, 2011, which resulted in a decrease of $94,814. In February 2011, a third party operator began collecting the revenue from other companies' gas that went through our pipelines, which eliminated our need to record cost of gas purchased for resale.

Other Income (Expenses): Total other expenses for the year ended December 31, 2012 was $665,567, compared to $3,409,063 for the year ended December 31, 2011, resulting in a decrease of $2,743,496. The primary reason for the decrease was due to a non-cash loss of $1,846,025 in 2011 resulting from the change in fair value of our warrant derivative liability. The change was caused by an increase in the stock price between December 31, 2010 and December 31, 2011. In the year ended December 31, 2012, the 2007 warrants expired resulting in a year end non-cash gain of $88,868. In addition, modifications to certain warrants in the year ended December 31, 2012, resulted in warrant modification expense of $294,534 compared to $900,660 for the year ended December 31, 2011 for a decrease of $606,126. This was offset by an increase to the change in liquidated damages of $207,430 from a non-cash loss of $33,944 in the year ended December 31, 2011 to a non-cash gain of $173,486 in the year end December 31, 2012. See "Note 10 - Warrants Outstanding," and "Note 18 - Commitments and Contingencies."

Income Tax Expense: During the year ended December 31, 2012, we recognized a net income tax expense of $3,515 for state margin tax. The 2011 income tax benefit of $274,813 related to continuing operations was offset by income tax expense of $274,813 related to discontinued operations.

Net Loss: As a result of the above described revenues and expenses, we incurred a net loss of $6,523,292 in the year ended December 31, 2012 as compared to a net loss of $4,568,828 in the year ended December 31, 2011.

Liquidity and Capital Resources

We held $1,421,198 in cash at December 31, 2012, made up of a majority of our cash accounts. However, at December 31, 2012, several cash accounts had an overdraft that totaled $17,795, resulting in net cash of $1,403,403. We held $6,749,368 in cash at December 31, 2011, which when netted against the overdrafts of $164,360, resulted in a net cash of $6,585,008. The decrease in cash is related to purchases of leases and well equipment, the increase in our drilling activities, and the use of cash to cover operating expenses. The decrease in cash was offset by an influx of cash from the sale of common stock during the year ended December 31, 2012.

Cash Flows The following table summarizes our cash flows for the years ended December 31: 2012 2011 Total cash provided by (used in): Operating activities $ (2,746,312) $ (252,383) Investing activities (8,282,697) 110,966 Financing activities 5,700,839 6,640,983 Increase (decrease) in cash and cash equivalents $ (5,328,170) $ 6,499,566

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Cash used in operating activities for the year ended December 31, 2012 was $2,746,312, compared to $252,383 used in operating activities for the year ended December 31, 2011, resulting in an increase of $2,493,929. There was an increase of $1,954,464 from the net loss of $4,568,828 for the year ended December 31, 2011 to the net loss of $6,523,292 for the year ended December 31, 2012. This was partially offset by a $1,960,032 increase in the non-cash income and expense items, which totaled $4,274,852 and $2,314,820 for the years ended December 31, 2012 and 2011, respectively.

A non-cash expense for stock based compensation of $2,719,888 was incurred during 2012, whereas there was no stock-based compensation incurred during 2011. The compensation resulted from the issuance of stock options to selected employees, executives, directors, and consultants as incentive for continuing our development. There was an increase of $1,934,893 to a gain of $88,868 for the year ended December 31, 2012 from a loss of $1,846,025 for the year ended December 31, 2011 in the change in fair value of the warrant derivative liability. There was a decrease in warrant modification expense of $606,126 to $294,534 for the year ended December 31, 2012, compared to $900,660 for the year ended December 31, 2011. Both the warrant derivative liability and warrant modification expense changes are discussed above in Other Income (Expense) under the Summarized Consolidated Results of Operations. There was an increase of $875,500 to $895,500 in stock issued to consultants for the year ended December 31, 2012. This is also discussed above in the General and Administrative Expense section. Depletion, depreciation, and accretion expense had an increase of $157,850 to $454,074 for the year ended December 31, 2012 related to the addition of new wells and future development costs contained in the 2012 Reserve Report. These were offset by the decrease of a $736,653 gain reported for the year ended December 31, 2011, relating to the sale of certain assets in our previously wholly-owned subsidiary, 59 Disposal Inc., as discussed in "Note 16 - Discontinued Operations".

There was a decrease in the change in various payables from $2,200,465 for the year ended December 31, 2011 to $966,160 for the year ended December 31, 2012, which was mainly due to payments made during 2012 on prior year drilling costs. There was also an increase of $1,342,655 to $1,390,919 in receivables from working interest investors to reimburse us for the substantial amount of drilling and completion work expenses on the Morse #1 well during the year ended December 31, 2012. Approximately $1.2 million of the receivables increase was from a related party investor. The remaining change in cash of $73,113 for the year ended December 31, 2012, compared to $150,576 in the year ended December 31, 2011 was from changes in various operating assets.

Cash used in investing activities for the year ended December 31, 2012 was $8,282,697, compared to $110,966 provided by investing activities for the year ended December 31, 2011, resulting in an increase of $8,393,663. There was $8,037,047 spent on lease and well equipment, and intangible drilling and completion costs for work done on the Haggard A, Haggard B and Morse wells during the year ended December 31, 2012. There was only $1,272,783 spent during the year ended December 31, 2011, resulting in an increase of $6,764,264. In addition, there was $245,485 spent on the purchases of property and equipment during the year ended December 31, 2012 compared to $1,994 in purchases during the year ended December 31, 2011. We received $1,037,000 of proceeds from the sale of 59 Disposal and proceeds of $344,081 for the sale of a working interest in the year ended December 31, 2011 and there were no similar transactions in 2012.

Cash provided by financing activities for the year ended December 31, 2012 totaled $5,700,839, compared to $6,640,983 for the year ended December 31, 2011, resulting in a decrease in cash of $940,144. In the year ended December 31, 2012, we received $5,855,086 in net proceeds from the sale of common stock and units of common stock and warrants compared to $6,820,868 in the year ended December 31, 2011. The remaining change in cash provided by financing activities for the year ended December 31, 2012, was primarily a result of changes in the cash overdraft. There was a $146,565 decrease in our cash overdrafts for the year ended December 31, 2012, compared to a decrease of $175,758 in our cash overdrafts for the year ended December 31, 2011.

Sources of Liquidity

Production revenues have not been sufficient to finance our operating expenses; therefore, we have had to raise capital in recent years to fund our activities. Planned lease acquisitions and exploration, development, production and marketing activities, as well as administrative requirements (such as salaries, insurance expenses, general overhead expenses, legal compliance costs and accounting expenses) will require a substantial amount of additional capital and cash flow.

The abrupt declines in production suffered by the Morse #1 have had an adverse impact on revenue. A workover procedure to remedy a suspected mechanical problem with the production system is currently underway and expected to be completed by the end of March 2013. We anticipate that the well will return to production at a rate in excess of 100 Bbl/day of oil.

We expect that additional funds raised from future financing activities will be needed, together with improved production revenue from the Morse, to finance our operations for the next twelve months. The extent of our drilling program in 2013 is dependent on our ability to raise additional capital. There are no guarantees that we will be able to raise additional funds on terms acceptable to us, if at all. We will also consider farm-out agreements, whereby we would lease parts of our properties to other operators for drilling purposes and we would receive payment based on the production.

We are actively pursuing sources of additional capital through various financing transactions or arrangements, including farm-outs, joint venturing of projects, debt financing, equity financing and other means.

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September 2012 Financing

In September 2012, we sold in a private placement a total of 3,355,223 Units (the "Units"), each Unit consisting of two shares of common stock and a three-year warrant to purchase one share of common stock at an exercise price of $1.00 per share, for an aggregate purchase price of $4,026,081. The warrants have an exercise price of $1.00 per share of common stock and will be exercisable for a period of three years from the date of issuance. Placement, selling and consultant fees for the private placement totaled $157,940.

In connection with the financing, we granted each purchaser registration rights. We were obligated to use our commercially reasonable efforts to cause a registration statement registering for resale the common stock underlying the warrants to be filed no later than 120 days from the date of termination of the financing and use our commercially reasonable efforts to affect the registration. As of March 22, 2013, we have not yet filed the registration statement.

March 2012 Financing

In March 2012, we sold 4,444,445 shares of common stock at $0.45 per share to one non-affiliated non-U.S. person, for a purchase price of $2,000,000. We incurred legal and escrow fees of $13,055.

Off Balance Sheet Arrangements

We do not have any off balance sheet arrangements that are reasonably likely to have a current or future effect on our consolidated financial condition, revenues, results of operations, liquidity or capital expenditures.

Critical Accounting Policies

Our critical accounting policies, including the assumptions and judgments underlying them, are disclosed in the notes to consolidated financial statements which accompany the consolidated financial statements. These policies have been consistently applied in all material respects and address such matters as revenue recognition and depreciation methods. The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the recorded amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

Accounts Receivable

We perform ongoing credit evaluations of our customers' financial condition and extend credit to virtually all of our customers. Collateral is generally not required, nor is interest charged on past due balances. Credit losses to date have not been significant and have been within management's expectations. In the event of complete non-performance by our customers, our maximum exposure is the outstanding accounts receivable balance at the date of non-performance.

Property and Equipment

Property and equipment are stated at cost and depreciated using the straight-line method over the estimated useful lives of the assets, which range from five to thirty-nine years. Expenditures for major renewals and betterments . . .

Permalink Reply by Dats Oil Brother on March 28, 2013 at 8:30

Thanks for posting this CC Gal. They report the next well in the 2nd quarter but need to raise money to drill it. So, who knows.....we wait and see.

Permalink Reply by Cass County Gal on March 28, 2013 at 11:20

Are you leased with them as well?

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