UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, ~~2013~~2014

Commission File Number 000-54842

PEGASI ENERGY RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)

Nevada		20-4711443
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

218 N. Broadway, Suite 204 Tyler, Texas	75702	(903) 595-4139
(Address of principal executive office)	(Zip Code)	(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None.

Securities registered pursuant to Section 12(g) of the Act: Common Stock, par value $0.001 per share

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act. Yeso Nox

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yeso Nox

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesx Noo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o	Accelerated filer o
Non-accelerated filer o	Smaller reporting company x
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act.) Yeso Nox

The aggregate market value of the voting common equity held by non-affiliates as of June 2830, ~~2013~~2014, on the closing sales price of the Common Stock as quoted on the ~~Over-the-Counter~~OTCQB ~~Bulletin~~Market ~~Board~~ was $2820,~~356~~834,~~536~~115.60. For purposes of this computation, all officers, directors, and 5 percent beneficial owners of the registrant are deemed to be affiliates. Such determination should not be deemed an admission that such directors, officers, or 5 percent beneficial owners are, in fact, affiliates of the registrant.

As of ~~March~~April 121, ~~2014~~2015, there were 6970,~~738~~539,~~303~~499 shares of registrant’s common stock outstanding.

Table of Contents

	Part I	Page
Item 1.	Business	3
Item 1A.	Risk Factors	14
Item 1B.	Unresolved Staff Comments	2526
Item 2.	Properties	2526
Item 3.	Legal Proceedings	26
Item 4.	Mine Safety Disclosures	26
	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	27
Item 6.	Selected Financial Data	28
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	28
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	3536
Item 8.	Financial Statements and Supplementary Data	F-1
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	3637
Item 9A.	Controls and Procedures	3637
Item 9B.	Other Information	3638
	Part III
Item 10.	Directors, Executive Officers and Corporate Governance	3739
Item 11.	Executive Compensation	3941
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	4243
Item 13.	Certain Relationships and Related Transactions, and Director Independence	4344
Item 14.	Principal ~~Accountant~~Accounting Fees and Services	4445
	Part IV
Item 15.	Exhibits, Financial Statement Schedules	4546
	Signatures	4850

Table of Contents

PART I.

FORWARD-LOOKING INFORMATION

This Annual Report on Form 10-K (including the section regarding Management's Discussion and Analysis of Financial Condition and Results of Operations) contains forward-looking statements regarding our business, financial condition, results of operations and prospects. Words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “seeks,” “estimates” and similar expressions or variations of such words are intended to identify forward-looking statements, but are not deemed to represent an all-inclusive means of identifying forward-looking statements as denoted in this Annual Report on Form 10-K. Additionally, statements concerning future matters are forward-looking statements.

Although forward-looking statements in this Annual Report on Form 10-K reflect the good faith judgment of our Management, such statements can only be based on facts and factors currently known by us. Consequently, forward-looking statements are inherently subject to risks and uncertainties and actual results and outcomes may differ materially from the results and outcomes discussed in or anticipated by the forward-looking statements. Factors that could cause or contribute to such differences in results and outcomes include, without limitation, those specifically addressed under the heading “Risks Factors” below, as well as those discussed elsewhere in this Annual Report on Form 10-K. Readers are urged not to place undue reliance on these forward-looking statements, which speak only as of the date of this Annual Report on Form 10-K. We file reports with the Securities and Exchange Commission (“SEC”). You can read and copy any materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, NE, Washington, DC 20549. You can obtain additional information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet site (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us.

We undertake no obligation to revise or update any forward-looking statements in order to reflect any event or circumstance that may arise after the date of this Annual Report on Form 10-K. Readers are urged to carefully review and consider the various disclosures made throughout the entirety of this Annual Report, which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operations and prospects.

This Annual Report on Form 10-K includes the accounts of Pegasi Energy Resources Corporation (“Pegasi”) and its wholly-owned subsidiaries, as follows, collectively referred to as “we”, “us” or the “Company”: Pegasi ~~Operating,~~Energy ~~Inc.~~Resources Corporation, a Texas corporation (“~~POI~~PERC”), ~~and~~Pegasi ~~TR Rodessa~~Operating, Inc., a Texas corporation (“~~TR Rodessa~~POI”)~~. In~~ ~~addition,~~and weTR ~~have one additional subsidiary~~Rodessa, ~~Pegasi Energy Resources Corporation~~Inc., a Texas corporation (“~~PERC~~TR Rodessa”)~~, which is inactive and does not conduct any operations~~.

ITEM 1. BUSINESS.

Overview of Business

We are an independent energy company engaged in the exploration for, and production of, crude oil and natural gas. ~~Our~~We ~~focus~~are isexclusively focused on the development of aresources ~~repeatable,~~within ~~low-geological~~the ~~risk,~~Rodessa ~~high-potential~~oil ~~project~~field inof ~~the active~~ East Texas. This oil field has been producing oil and gas ~~region~~since 1929. We ~~currently~~The ~~hold~~Rodessa ~~interests~~oil infield ~~properties~~has ~~located~~to indate ~~Cass~~produced over 400 million barrels of oil and ~~Marion~~2.3 ~~Counties,~~trillion ~~Texas,~~cubic ~~home~~feet toof ~~the Rodessa~~gas ~~oil~~from ~~field~~over 2,000 producing wells. This ~~field~~production has ~~historically~~come ~~been~~from multiple formations including the ~~domain~~Rodessa, Travis Peak, Pettit, Cotton Valley and Bossier, which are all proven hydrocarbon reservoirs. Most of ~~small~~the ~~independent~~Rodessa’s ~~operators~~wells were drilled over 50 years ago and istargeted ~~not~~the shallower horizons. No major energy company ever established a ~~legacy~~dominant position in the field. ~~for~~Most ~~any~~development ~~major~~has ~~oil~~been ~~company~~conducted by independents and mineral ownership has remained highly fragmented. We currently hold interests in properties located in Cass and Marion Counties, Texas.

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~~our ~~Cornerstone~~project ~~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 oil field’s 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. InWe 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~~this ~~Cornerstone~~mature ~~Project~~oil ~~area~~field will enable us to find significant oil and gas reserves that were either overlooked or not amenable to development with the technology previously available.

Corporate History

We previously operated under the name Maple Mountain Explorations, Inc. (“Maple Mountain”), a Nevada corporation. On December 12, 2007, Maple Mountain entered into a share exchange agreement with the shareholders of PERC, pursuant to which we purchased from PERC’s shareholders all issued and outstanding shares of PERC’s common stock in consideration for the issuance of 17,500,000 shares of our common stock. Effective January 23, 2008, we changed our name to Pegasi Energy Resources Corporation.

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Effective July 1, 2011, certain assets of our wholly-owned subsidiary, 59 Disposal Inc., (“59 Disposal”), were sold for a total of $1.3 million, of which we received $1,037,000. 59 Disposal owned an 80% undivided interest in a saltwater disposal facility which disposes saltwater and flow-back waste into subsurface storage. Effective September 30, 2012, we legally closed 59 Disposal, and all remaining asset and liability balances were transferred to PERC at that date.

Our Operations

We began our leasing and farm-in activities in the Rodessa oil field area of the East Texas oil and gas basin in 2000. Our initial leasehold purchase was comprised of approximately 1,500 gross acres, which has grown to approximately 2825,~~697~~072 gross acres. WeOur ~~serve~~development asstrategy, ~~operator~~which ofwe have designated the Cornerstone Project, ~~with~~has been to establish a significant acreage position in the mature Rodessa oil field and develop and produce reserves through proven drilling and completion techniques. In addition, we intend to recomplete and redevelopment some of our older wells to enhance their production rates. We are working on this strategy with our working interest partner, TR Energy Inc. (“TR Energy”), a related party~~, to develop our acreage position in the Cornerstone Project~~. We hold an 80% working interest in the majority of our leases with TR Energy holding a 20% working interest in those leases. We have a few leases in which we hold smaller interests ranging from 25% - 50% with TR Energy and other minority investors holding the remaining working interests. As of ~~March~~ April 1, ~~2014~~2015, we operated 2017 wells, of which 1513 were producing.

We conduct our main exploration and production operations through our wholly-owned subsidiary, POI. We conduct additional pipeline operations through our other wholly-owned subsidiary, TR Rodessa.

TR Rodessa owns an 80% undivided interest in and operates a 40-mile natural gas pipeline and gathering system which we currently use to transport our hydrocarbons to market. TR Energy owns the remaining 20% undivided interest. Excess capacity on this system is used to transport third-party hydrocarbons.

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~~April 1, ~~2014~~2015, our leasehold position is approximately 2824,~~697~~258 gross acres and 1712,~~898~~826 net acres, of which our working interest is approximately 117,~~352~~290 net acres. Our acreage position declined, by approximately 3,000 gross acres and 1,624 net working interest acres, over the last 12 months. This decline followed the expiration of leases, which we chose not to renew for strategic reasons.

· 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 ~~Project~~ area. Most properties in the project area are held by smaller independent companies that lack the resources and expertise to develop 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.

Development of Resources in the Cornerstone Project area

Our acreage is located in a region that has historically proven highly productive. There are multiple target formations available for development on our leased acreage. These include the gas and condensate bearing Travis Peak, the oil and gas bearing upper Cotton Valley sands, the oil bearing Bossier sands and the oil bearing Cotton Valley Limestone. Approximately 70% of our net leased acreage is currently undeveloped (approximately 4,779 undeveloped net acres of a total of 7,290 net acres as of April 1, 2015).

Horizontal Wells Targeting the Bossier/Cotton Valley Limestone. Our priority is to drill horizontal wells targeting the Bossier/Cotton Valley Limestone. The low permeability oil bearing Bossier and Cotton Valley Limestone formations are amenable to development using the latest horizontal drilling and dynamic multi-stage fracking techniques that have proven successful in the Bakken Shale in North Dakota and elsewhere. Our first horizontal well, the Morse #1-H, 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 production rate subsequently decreased and we recorded an average production rate of 7 Bbl/day of crude oil during February 2015, when production was hampered by extreme cold weather that resulted in forced shut downs on account of the failure of the gas lift system’s compression equipment. The decrease in the production rate has been irregular and we have observed several instances of unexpected, sustained surges in production, typically resulting in a doubling of production volume over three-day periods. These surges in production lead us to believe that the reservoir is capable of greater production, and that the Morse #1-H well’s production rate has been compromised by the gas lift system and/or by an obstruction in the well bore. We believe that the successful production of oil from the Morse #1-H, which has produced a cumulative total of 41,793 Bbls of oil to December 31, 2014, supports our development strategy for the Bossier/Cotton Valley Limestone. We have gained a substantial amount of knowledge and experience from the drilling, completion and production of the Morse #1-H well that will enable us to improve the design and execution of our next planned horizontal well. Having proven our development model, we now plan to drill wells with longer laterals involving 15 or more frack stages to improve the well economics. We estimate that the drilling and completion costs of such wells will be approximately $7-$9 million. We are not currently capitalized to drill a program of such wells and are actively engaged in securing the necessary finance to fund a drilling program to develop the Bossier/Cotton Valley Limestone.

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~~Development~~· Vertical Wells. Our secondary priority is to drill vertical wells to develop shallower formations, such as the Travis Peak and Cotton Valley. The Haggard A & B wells, which offset the Norbord #1 discovery of ~~Resources~~2010 and were completed in 2013 and 2012, respectively, fall into this category and have proven highly productive of gas and condensate. In August 2014, we concluded a participation agreement with Pacific World Energy (“PWE”) for the ~~Cornerstone~~drilling ~~Project~~of ~~area~~up to 10 wells on our leased acreage in Marion County. On October 1, 2014, we spudded the first vertical well of this program, the Huntington #4. Drilling reached a final depth of 9,300 feet, production casing of 4 ½” was set and cemented at 9,300 feet and the drilling rig was released on October 27, 2014. Analysis of the well log identified in excess of 175' of gross pay over multiple Cotton Valley and Travis Peak zones. Having now analyzed the drilling results, we are discussing the completion procedure for this well with PWE and plan to complete this well within the first half of 2015.

Approximately two-thirds of our net leased acreage is currently undeveloped (approximately 7,524 undeveloped net acres of a total of 11,352 net acres as of March 1, 2014). The primary focus of our drilling program is to develop the resources of these undeveloped acres and subsequently hold this acreage with production rather than to develop our 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 employ the latest horizontal drilling and dynamic multi-stage fracking techniques that have proven 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-H, 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. 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. The well was shut in again on February 25, 2013, for the performance of a remedial work-over operation. The well returned to production on March 19, 2013. The production rate initially stabilized at a rate of approximately 55 Bbl/day of oil and 75 MCF of gas per day. The production rate subsequently declined to an average of 38 Bbl/day of oil as recorded in January 2014. This decline has been irregular and we have observed unexpected surges in production. During a three day period in November 2013, production surged to a peak of 83 Bbl/day from the previous average of approximately 30 Bbl/day. In early February 2014, production surged to a peak rate of 74 Bbl/day of oil over a three day period and later surged to a peak rate of 72 Bbl/day of oil over an eight day period. Due to these surges, the average production of approximately 35 BB/day during February 2014 was the highest recorded production since July 2013. These surges in production lead us to believe that the reservoir is capable of greater production, and that the Morse #1-H well’s production rate has been compromised by the gas lift system and/or by an obstruction in the well bore. We are actively researching an intervention and intend to perform a workover of the well, which may involve the installation of a mechanical pump to replace the gas lift system; no date has yet been set for such work. We expect that it would take approximately 30 days to install such a mechanical pump system. We believe that the successful production of oil from the Morse #1-H supports our development strategy. We have learned much from the drilling, completion and production of the Morse #1-H 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 frack stages to improve the well economics. We estimate that the drilling and completion costs of such wells will be approximately $7-$9 million. We are not currently capitalized to drill a program of such wells to develop the Bossier/Cotton Valley Limestone and are actively engaged in securing the finance to fund such a drilling program. We have a 56% working interest in the Morse #1-H well.

· 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. In March 2012, we successfully completed the Haggard A well, which is an offset to the Norbord discovery in 2010. The Haggard A was our most productive gas well in 2013. Following unsuccessful work-over attempts in 2013 on the Norbord #1, which ceased production from the Travis Peak formation in September 2012, we plugged and abandoned the well in February 2014. We also decided to abandon the Swamp Fox well and plugged it in February 2014.

Well Economics

We plan to develop our non-producing proven reserves through the recompletion of existing wells and the drilling of new wells. These non-producing proven reserves are attributed to the Travis Peak/Pettit, Cotton Valley and Bossier formations.

Travis Peak/Pettit

Travis Peak/Pettit Recompletions	MMBO		BCF
Proved Developed Non-Producing		-		0.36
Proved Behind Pipe		0.2425		67.8106
Total		0.2425		7.1742

5We plan to exploit the reserves outlined in the table above by recompleting existing vertical wells in the relatively shallow Travis Peak/Pettit formations at depths of between 6,000 and 7,800 feet. These reserves are estimated to be 83% gas. The estimated future development cost of these recompletions is estimated at approximately $3.2 million. We estimate the finding and development cost of these recompletions at $0.35/Mcfe.

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New Vertical Wells Targeting the Travis Peak/Pettit		MMBO				BCF
Proved Undeveloped			0.02				1.87

We plan to ~~exploit~~drill ~~the~~new ~~reserves~~vertical ~~outlined~~wells into ~~the~~depths ~~table~~of ~~above~~between by6,000 ~~recompleting~~and ~~existing~~7,800 ~~vertical~~feet ~~wells~~to inrecover the ~~relatively~~proven ~~shallow~~undeveloped reserves in the Travis Peak/ and Pettit formations atdetailed ~~depths~~in ofthe ~~between~~table ~~6,000 and 7,800 feet~~above. These reserves are estimated to be 8394% gas~~. The~~, ~~estimated~~have a future development cost of ~~these recompletions is estimated at approximately~~ $31.45 million~~. We~~ ~~estimate~~and ~~the~~a finding and development cost of ~~these recompletions at~~ $0.3975/Mcfe.

New Vertical Wells Targeting the Travis Peak/Pettit		MMBO				BCF
Proved Undeveloped			0.13				7.03

We plan to drill new vertical wells to depths of between 6,000 and 7,800 feet to recover the proven undeveloped reserves in the Travis Peak and Pettit formations detailed in the table above. These reserves are estimated to be 90% gas, have a future development cost of $9.5 million and a finding and development cost of $1.21/Mcfe.

Cotton Valley

Cotton Valley Recompletions	MMBO		BCF
Proved Behind Pipe		0.04		1.50
Proved Developed Non-Producing		-		0.10
Proved Behind Pipe		0.05		1.72

By recompleting existing wells in the Upper Cotton Valley at depths of between 8,000 and 9,500 feet, we plan to recover the proved behind pipe reserves detailed in the table above. These reserves are estimated to be 87% gas and their future development cost is estimated at $1.24 million. The finding and development cost is estimated at $0.7066/Mcfe.

Bossier

Bossier Recompletions		MMBO				BCF
Proved Developed Non-Producing			0.0811				0.05

By recompleting existing wells in the Bossier formation at depths of between 9,900 and 10,100 feet, we plan to recover the proved developed non-producing reserves detailed in the table above. These reserves are estimated to be 9093% oil and their future development cost is estimated at $0.5 million. The finding and development cost is estimated at $54.9754/MBoe.

New Horizontal Wells Targeting the Bossier		MMBO				BCF
Proved Undeveloped			0.21				0.253

We plan to drill horizontal wells with lateral sections of 3,000 feet targeting the Bossier formation to recover the proved undeveloped reserves detailed in the table above. These reserves are estimated to be 83% oil and their future development cost is estimated at $5~~.5 million. The finding and development cost is estimated at $21.91/MBoe.~~

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We plan to drill horizontal wells with lateral sections of 3,000 feet targeting the Bossier formation to recover the proved undeveloped reserves detailed in the table above. These reserves are estimated to be 83% oil and their future development cost is estimated at $3.8 million. The finding and development cost is estimated at $15.35/MBoe.

General

The estimated future development costs detailed above are components of the amounts disclosed in the supplemental oil and gas disclosures required by Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic No. 932, Extractive Activities—Oil and Gas. We emphasize that reserve estimates are inherently imprecise and that estimates of reserves related to new discoveries are more imprecise than those for producing oil and gas properties. Accordingly, the estimates are expected to change as future information becomes available. The estimates have been prepared with the assistance of James E. Smith and Associates, an independent petroleum reservoir engineering firm. The finding and development cost is the ratio of estimated future development costs to the estimated ultimate recovery. We use this ratio, with reference to the commodity price to evaluate the commercial viability of drilling a well. The limitation of this measure is that it is based on estimates that are inherently imprecise. The manner in which we have calculated the finding and development costs may differ from how other companies calculate a like measure.

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In order to maximize our rate of return on our vertical wells, we plan on implementing a shotgun-dual or sawtooth production technique. Under this technique, we will drill and complete multiple geologic horizons in a sequential manner as follows:

·	We will initially complete and produce the lower Cotton Valley pay zone (~10,500 ft.);

·	After producing the lower Cotton Valley zone for a period of time, we will move uphole to recomplete the upper Cotton Valley (~8,200 ft.), Travis Peak Zone (~7,500 ft.) and/or Pettit Zone (~6,500 ft.); and

·	After producing the upper Cotton Valley, Travis Peak and/or Pettit Zones for a period of time, we will co-mingle all zones and produce through the end of the wells’ lives.

Oil and Gas Production, Production Prices and Production Costs

The following table summarizes our net oil and gas production, the average sales price per Bbl of oil and per Mcf of gas produced and the average cost of production per Boe of production sold, for the three years ended December 31:

	2013		2012		2011
Production	2014		2013		2012
Production
Net oil production (Bbls)		8,423		10,170		11,516
Net oil production (Bbls)		10,170		11,516		4,063
Net gas production (Mcf)		224,205		164,842		109,277
Net gas production (Mcf)		164,842		109,277		117,461
Total production (Mboe)(1)		45,791		37,644		29,730
Total production (MBoe) (1)		37,644		29,730		23,640
Average sales price per Bbl of oil	$	90.59	$	99.84	$	92.23
Average sales price per Bbl of oil	$	99.84	$	92.23	$	93.63
Average sales price per Mcf of gas	$	4.16	$	3.68	$	2.67
Average sales price per Mcf of gas	$	3.68	$	2.67	$	3.85
Average sales price per Boe	$	37.04	$	43.08	$	45.55
Average sales price per Boe	$	43.08	$	45.55	$	35.21
Average production cost per Boe	$	9.66	$	14.10	$	14.67
Average production cost per Boe	$	14.10	$	14.67	$	10.87
(1) Oil and gas were combined by converting gas to a Boe equivalent on the basis of 6 Mcf of gas to 1 Bbl of oil

(1) Oil and gas were combined by converting gas to a Boe equivalent on the basis of 6 Mcf of gas to 1 Bbl of oil

Productive Wells

The following table sets forth information regarding the total gross and net productive wells as of December 31, ~~2013~~2014, expressed separately for oil and gas. All of our productive wells are located in Texas.

Number of Operating Wells

Oil

~~Gas~~

Gas

Gross

~~Net~~

~~Gross~~Net

~~Net~~

Gross

Net

Texas

7.00

~~5.24~~

5.24

~~5.6~~

7.00

4.80

A productive well is an exploratory well, development well, producing well or well capable of production, but does not include a dry well. A dry well, or a hole, is an exploratory or a development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

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A gross well is a well in which a working interest is owned, and a net well is the result obtained when the sum of fractional ownership working interests in gross wells equals one. The number of gross wells is the total number of wells in which a working interest is owned, and the number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. The “completion” of a well means the installation of permanent equipment for the production of oil or gas, or, in the case of a dry hole, to the reporting of abandonment to the appropriate agency.

Developed and Undeveloped Acreage

The following table sets forth information regarding our gross and net developed and undeveloped oil and natural gas acreage under lease as of December 31, ~~2013~~2014:

Texas	Gross		Net
Developed Acreage		63,~~152~~781		32,~~828~~184
Undeveloped Acreage		21,~~759~~679		76,~~375~~539
Total		2725,~~911~~460		118,~~203~~723

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Drilling Activity

	2013		2012
Drilling activity	2014		2013
Drilling activity
Net productive exploratory wells drilled		-		-
Net productive exploratory wells drilled		-		2
Net dry exploratory wells drilled		-		-

~~During~~Present ~~2013, we did not participate in the drilling of any new wells that were determined to be productive.~~Activities

In August 2014, we entered into a participation agreement with PWE for the drilling of up to 10 wells on our leased acreage in Marion County. The first vertical well was spudded on October 1, 2014 and we plan to complete this well within the first half of 2015.

Delivery Commitments

We are not obligated to provide oil or gas in fixed quantities or at fixed prices under existing contracts.

Summary of Oil and Gas Reserves as of December 31, ~~2013~~2014 and ~~2012~~2013

December 31, 2013 Reserves

December 31, 2012 Reserves

December 31, 2014 Reserves

December 31, 2013 Reserves

Oil

Natural Gas

~~Total~~

Total

~~Oil~~

~~Natural Gas~~Oil

~~Total~~

Natural Gas

Total

Reserves category

(bbls)

(mcf)

(MBOE)

(bbls)

(mcf)

(MBOE)

Reserves Category

(bbls)

(mcf)

(MBOE)

(bbls)

(mcf)

(MBOE)

PROVED

Developed

United States

~~137~~151,~~480~~500

1,~~131~~259,~~178~~775

~~326,009~~

~~130~~361,~~584~~463

~~759,307~~

137,480

~~257,135~~

1,131,178

326,009

Undeveloped

United States

~~620~~521,~~182~~982

1510,~~587~~901,~~482~~366

~~3,218,096~~

~~598~~2,~~069~~338,876

~~13,475,572~~

620,182

~~2,843,998~~

15,587,482

3,218,096

TOTAL PROVED

~~757~~673,~~662~~482

1612,~~718~~161,~~660~~141

~~3,544,105~~

~~728~~2,~~653~~700,339

~~14,234,879~~

757,662

~~3,101,133~~

16,718,660

3,544,105

Proved Undeveloped Reserves (“PUDs”)

~~The~~As ~~production performance~~ of ~~the~~December ~~Haggard~~31, A2014, ~~which~~2,338,876 ~~was~~MBOE ~~completed~~of inproved ~~the~~undeveloped ~~Travis~~reserves ~~Peak~~were ~~and~~reported, ~~entered~~a ~~production~~decrease inof ~~April 2013~~879,220 ~~has~~MBOE ~~exceeded~~from ~~our~~December ~~expectations~~31, 2013. ~~Based~~ The ondecrease ~~the~~is ~~strong~~chiefly ~~performance~~attributable ofto the ~~Haggard~~removal A,of ~~the~~various ~~estimated~~ proved undeveloped reserves ~~for~~that ~~the~~had ~~proposed~~been ~~Travis~~recognized ~~Peak~~over ~~wells~~five ~~that~~years ~~offset~~ago and have yet to be developed. Given the ~~Haggard~~recent price decline ~~and~~in ~~Norbord~~energy ~~wells,~~markets ~~have~~and ~~been~~the ~~revised~~downturn ~~upwards~~in byinvestment in the ~~third~~industry, ~~party~~we ~~engineer.~~intend ~~The~~to ~~increase~~focus ~~from~~our ~~2012~~efforts in the ~~total~~next ~~estimated~~12 ~~proved~~months ~~undeveloped~~on recompletion and redevelopment projects to develop our proven reserves isand ~~detailed~~drilling innew ~~the~~wells ~~table~~as ~~below~~part of a program with investment partners.

	MBbls		MMCF
Proved Undeveloped Reserves as Estimated December 31, 2012		598		13,476
Estimated PUD reserves from additional Travis Peak offset wells		13		1,248
Revisions of previous Travis Peak PUD reserve estimates		9		833
Revisions to other previous PUD estimates		0		31
Proved Undeveloped Reserves as Estimated December 31, 2013		620		15,587

See “Management's Discussion and Analysis of Financial Condition and Results of Operations” regarding our progress to convert our PUDS to proved developed reserves. We currently plan to develop these reserves within the next five years. We do not currently have material concentrations of PUDs in individual fields or countries that have remained undeveloped for five years or more after disclosure as PUDs.

There were no material changes in our proved undeveloped reserves (“PUDs”) associated with other wells during 2013. See “Management's Discussion and Analysis of Financial Condition and Results of Operations” regarding our progress to convert our PUDS to proved developed reserves. We are currently scheduled to drill these locations within the next five years. We do not have material concentrations of PUDs in individual fields or countries that have remained undeveloped for five years or more after disclosure as PUDs.7

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The technical person in charge of the preparation and oversight of our reserve estimates is James E. Smith, a petroleum engineer who founded and is the president of a multi-disciplined engineering firm that offers a total package of services to the oil and gas industry in East Texas and other areas in the southwestern United States. He has over 40 years of experience in the oil and gas industry. A graduate of Texas A&M University, he worked 18 years for the Texas Railroad Commission serving as Field Operations Director, Hearing Examiner, Special Project Engineer in Austin, and as the District Director of both the Kilgore and Abilene District Offices. He is a member of the Society of Petroleum Engineers, the Society of Petroleum Evaluation Engineers, and the SPE Technical Information Group for economics and evaluations. He is a registered petroleum engineer in the state of Texas. He has extensive experience in economic and reservoir evaluation for acquisitions, producing properties and undeveloped prospects. He also planned and supervised the drilling of wells that we drilled in the East Texas project. He is not an employee of ours and does not have an equity position in our oil and gas development. We believe his independence allows him to be objective in the preparation and oversight of our reserve estimates.

The process for preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control procedures, which include verification of data provided for the report and review of the independent third party reserves report. The technical employee responsible for overseeing the process for preparation of the reserves estimates is our Chief Executive Officer, Michael H. Neufeld. Mr. Neufeld holds a B.Sc. Degree in Geology from Louisiana State University and has worked in the oil and gas industry for over 40 years, including roles as Senior Exploration Geologist and Vice President of Exploration at various oil & gas companies, including Penzoil and Hunt Oil Company. He is the sole person in the Company that reviews and approves the reserve estimates.

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Title to Properties

As is customary in the oil and gas industry, only a preliminary title examination is conducted at the time we acquire leases or enter into other agreements to obtain control over interests in acreage believed to be suitable for drilling operations. In many instances, our partners have acquired rights to the prospective acreage and we have a contractual right to have our interests in that acreage assigned to us. In some cases, we are in the process of having those interests so assigned. Prior to the commencement of drilling operations, a thorough title examination of the drill site tract is conducted by independent attorneys. Once production from a given well is established, the operator will prepare a division order title report indicating the proper parties and percentages for payment of production proceeds, including royalties. We believe that titles to our leasehold properties are good and defensible in accordance with standards generally acceptable in the oil and gas industry.

Markets and Customers

The revenue generated by our operations is highly dependent upon the prices of, and demand for, natural gas and crude oil. Historically, the markets for crude oil and natural gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our crude oil and natural gas production are subject to wide fluctuations and depend on numerous factors beyond our control including seasonality, the condition of the United States economy (particularly the manufacturing sector), foreign imports, political conditions in other crude oil-producing and natural gas-producing countries, the actions of the Organization of Petroleum Exporting Countries and domestic regulation, legislation, and policies. Decreases in the prices of crude oil and natural gas have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and our revenue, profitability, and cash flow from operations.

We currently have access to several interstate pipelines as well as local end users, however the market for oil and natural gas that we expect to produce depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial, and individual consumers.

Our oil production is expected to be sold at prices tied to the spot oil markets. Our natural gas production is expected to be sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices.

Regulation

Generally. Our oil and gas exploration, production and related operations and activities are subject to extensive rules and regulations promulgated by federal, state and local governmental agencies. Failure to comply with such rules and regulations can result in substantial penalties. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar types, quantities and locations of production.

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Regulations affecting production. All of the states in which we operate generally require permits for drilling operations, require drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells, the spacing, plugging and abandonment of such wells, restrictions on venting or flaring gas and requirements regarding the ratability of production.

These laws and regulations may limit the amount of oil and gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Moreover, many states impose a production or severance tax with respect to the production and sale of oil and gas within their jurisdiction. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation of production, but there can be no assurance they will not do so in the future.

In the event we conduct operations on federal, state or Indian oil and gas leases, our operations may be required to comply with additional regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements and on-site security regulations, and other appropriate permits issued by the Bureau of Land Management or other relevant federal or state agencies.

Regulations affecting sales. The sales prices of oil and gas are not presently regulated but rather are set by the market. We cannot predict, however, whether new legislation to regulate the price of energy commodities might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, the proposals might have on the operations of the underlying properties.

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The Federal Energy Regulatory Commission (the “FERC”) regulates interstate gas transportation rates and service conditions, which affect the marketing of gas we produce, as well as the revenues we receive for sales of such production. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting interstate transportation. These initiatives also may affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the gas industry. We do not believe that we will be affected by any such FERC action in a manner materially different from other gas producers in our areas of operation.

The price we receive from the sale of oil and gas is affected by the cost of transporting those products to market. Interstate transportation rates for oil, gas and other products are regulated by the FERC. The FERC has established an indexing system for such transportation, which allows such pipelines to take an annual inflation-based rate increase. We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs, which may have the effect of reducing wellhead prices for oil and gas.

Market manipulation and market transparency regulations. Under the Energy Policy Act of 2005 (the “EP Act 2005”), the FERC possesses regulatory oversight over gas markets, including the purchase, sale and transportation of gas by “any entity” in order to enforce the anti-market manipulation provisions in the EP Act 2005. The Federal Trade Commission (the “FTC”) has similar regulatory oversight of oil markets in order to prevent market manipulation. The Commodity Futures Trading Commission (the “CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act. With regard to our physical purchases and sales of crude oil and gas, our gathering of these energy commodities, and any related hedging transactions that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by the FERC, the FTC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

Gathering regulations. Section 1(b) of the Natural Gas Act (the “NGA”) exempts gas gathering facilities from the jurisdiction of the FERC under the NGA. We own certain gas pipelines that we believe meet the traditional tests that the FERC has used to establish a pipeline’s status as a gatherer not subject to the FERC jurisdiction. The distinction between the FERC-regulated transmission facilities and federally unregulated gathering facilities is, however, the subject of substantial, ongoing litigation, so the classification and regulation of our gathering lines may be subject to change based on future determinations by the FERC, the courts or Congress.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and ~~in some instances~~ complaint-based rate regulation. Our gathering operations are also subject to state ratable take and common purchaser statutes, designed to prohibit discrimination in favor of one producer over another or one source of supply over another. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather gas. In addition, our gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services, though we do not believe that we would be affected by any such action in a manner materially differently than other companies in our areas of operation.

~~Environmental Matters~~9

~~Our~~Table ~~operations pertaining to oil and gas exploration, production and related activities are subject to numerous and constantly changing federal, state and local laws governing the emission and discharge~~ of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of certain permits prior to commencing certain activities or in connection with our operations; restrict or prohibit the types, quantities and concentration of substances that we can release into the environment; restrict or prohibit activities that could impact wetlands, endangered or threatened species or other protected areas or natural resources; require some degree of remedial action to mitigate pollution from former operations, such as pit cleanups and plugging abandoned wells; and impose substantial liabilities for pollution resulting from our operations. Such laws and regulations may substantially increase the cost of our operations and may prevent or delay the commencement or continuation of a given project and thus generally could have an adverse effect upon our capital expenditures, earnings or competitive position. Violation of these laws and regulations could result in significant fines or penalties. We have not experienced accidental spills, leaks and other discharges of contaminants at some of our properties, but may do so in the future, as have other similarly situated oil and gas companies, and some of the properties that we have acquired, operated or sold, or in which we may hold an interest but not operational control, may have past or ongoing contamination for which we may be held responsible. We may acquire operations that are located in environmentally sensitive environments, such as coastal waters, wetlands and other protected areas. In addition, we may acquire properties that are located in areas particularly susceptible to hurricanes and other destructive storms, which may damage facilities and cause the release of pollutants. Our environmental insurance coverage may not fully insure all of these risks. The costs of remedying such conditions may be significant, which could have a material adverse impact on our financial condition and operations.Contents

Environmental and Occupational Safety and Health Matters

Our operations pertaining to oil and gas exploration, production and related activities are subject to numerous and constantly changing federal, state and local laws governing occupational safety and health, the emission and discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of permits prior to commencing drilling or other regulated activities in connection with our operations; restrict or prohibit the types, quantities and concentration of substances that we can release into the environment; restrict or prohibit activities that could impact wetlands, endangered or threatened species or other protected areas or natural resources; require some degree of remedial action to mitigate pollution from former operations, such as pit cleanups and plugging abandoned wells; impose specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from our operations. Such laws and regulations may substantially increase the cost of our operations and may prevent or delay the commencement or continuation of a given project and thus generally could have an adverse effect upon our capital expenditures, earnings or competitive position. Violation of these laws and regulations could result in sanctions including administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas. We have not experienced accidental spills, leaks and other discharges of contaminants at some of our properties, but may do so in the future, as have other similarly situated oil and gas companies, and some of the properties that we have acquired, operated or sold, or in which we may hold an interest but not operational control, may have past or ongoing contamination for which we may be held responsible. We may acquire operations that are located in environmentally sensitive environments, such as coastal waters, wetlands and other protected areas, which may obligate us to implement costly mitigative or precautionary measures. In addition, some of our properties are located in areas particularly susceptible to hurricanes and other destructive storms, which may damage facilities and cause the release of pollutants. Our environmental insurance coverage may not fully insure all of these risks. The costs of remedying such conditions may be significant, which could have a material adverse impact on our financial condition and operations.

We believe that we are in substantial compliance with current applicable environmental laws and regulations, and that the cost of compliance with such laws and regulations has not been material and is not expected to be material during 2015. We also do not believe that we will be required to incur material capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in the re-interpretation of enforcement policies could have a significant impact on our operations, as well as the oil and gas industry in general. For instance, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal or clean-up requirements, or drilling, completion, construction or water management activities could have an adverse impact on our operations.

The following is a summary of the more significant existing environmental and worker health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous substances and wastes. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. Despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses crude oil and natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. These persons include the owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We are not aware of any liabilities for which we may be held responsible that would materially and adversely affect us.

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WeThe ~~believe~~Resource ~~that~~Conservation weand ~~are~~Recovery inAct ~~substantial~~(“RCRA”) ~~compliance~~and ~~with~~analogous ~~current~~state ~~applicable environmental~~ laws ~~and~~impose ~~regulations,~~detailed ~~and~~requirements for the ~~cost~~handling, ofstorage, ~~compliance~~treatment ~~with~~and ~~such~~disposal ~~laws~~of hazardous and ~~regulations~~non-hazardous ~~has~~wastes. RCRA ~~not~~specifically ~~been~~excludes ~~material~~drilling ~~and~~fluids, isproduced ~~not~~waters ~~expected~~and toother bewastes ~~material~~associated ~~during 2014. We~~with dothe ~~not~~exploration, ~~believe~~development ~~that~~or weproduction ~~will~~of becrude ~~required~~oil, tonatural ~~incur~~gas ~~material~~or ~~capital~~geothermal ~~expenditures~~energy tofrom ~~comply~~regulation ~~with~~as ~~existing~~hazardous ~~environmental requirements~~wastes. ~~Nevertheless~~However, ~~changes~~these inwastes ~~existing~~may ~~environmental~~be ~~laws~~regulated ~~and~~by ~~regulations~~the orU.S. inEnvironmental Protection Agency (the ~~interpretations~~“EPA”) ~~thereof~~or ~~could~~state ~~have~~agencies aas ~~significant~~non-hazardous ~~impact~~wastes. Moreover, onmany ~~our~~ordinary ~~operations~~industrial wastes, such as ~~well~~paint aswastes, ~~the~~waste ~~oil~~solvents, laboratory wastes and ~~gas~~waste ~~industry~~compressor inoils ~~general. For~~may ~~instance,~~be ~~any~~regulated ~~changes~~as inhazardous ~~environmental~~wastes ~~laws~~if ~~and~~such ~~regulations~~wastes ~~that~~have ~~result~~hazardous incharacteristics. Although ~~more~~the ~~stringent~~costs ~~and~~of ~~costly~~managing hazardous waste ~~handling,~~may ~~storage,~~be ~~transport~~significant, ~~disposal~~we ordo ~~clean-up~~not ~~requirements~~believe ~~could~~that ~~have~~our ancosts ~~adverse~~in ~~impact~~this onregard ~~our~~are ~~operations~~materially more burdensome than those for similarly situated companies.

~~Hazardous~~We ~~substances. The~~currently ~~Comprehensive~~own ~~Environmental~~or ~~Response,~~lease ~~Compensation,~~ and ~~Liability~~have ~~Act~~in ~~(“CERCLA”), also known as~~ the ~~“Superfund”~~past ~~law,~~owned ~~imposes liability, without regard to fault~~ or ~~the~~leased ~~legality~~properties ~~of the original conduct, on certain classes of persons~~ that ~~are~~for ~~considered~~many toyears have ~~contributed~~been toused ~~the~~for ~~release of a “hazardous substance” into the environment. Despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses crude~~ oil and natural gas, weexploration ~~may~~and ~~nonetheless~~production ~~handle~~activities. ~~hazardous~~Although ~~substances~~we ~~within~~have ~~the~~utilized ~~meaning~~operating ofand ~~CERCLA,~~disposal orpractices ~~similar~~that ~~state~~were ~~statutes,~~standard in the ~~course~~industry ofat ~~our~~the ~~ordinary operations and~~time, ashydrocarbons aor ~~result,~~other ~~may~~substances ~~be jointly~~ and ~~severally~~wastes ~~liable~~may ~~under~~have ~~CERCLA~~been ~~for~~disposed ~~all~~of or ~~part of the costs required to clean up sites at which these hazardous substances have been~~ released ~~into~~on ~~the environment. These persons include the owner~~ or ~~operator~~under of the ~~disposal~~properties ~~site~~owned or ~~the~~leased ~~site~~by ~~where~~us ~~the~~or ~~release~~on ~~occurred and companies that disposed~~ or ~~arranged~~under ~~for~~ the ~~disposal~~other oflocations ~~the hazardous substances at the site~~ where ~~the~~these ~~release~~hydrocarbons ~~occurred. Under~~or ~~CERCLA,~~other ~~such~~substances ~~persons may be subject to joint~~ and ~~several~~wastes ~~liability for the costs of cleaning up the hazardous substances that~~ have been ~~released~~taken ~~into the environment and~~ for ~~damages~~treatment toor ~~natural~~disposal. ~~resources~~In addition, ~~and~~certain itof isthese ~~not~~properties ~~uncommon~~have ~~for~~been ~~neighboring~~operated ~~landowners~~by ~~and other~~ third parties towhose ~~file~~treatment ~~claims for personal injury~~ and ~~property~~disposal ~~damage~~or ~~allegedly~~release ~~caused~~of byhydrocarbons ~~the~~or ~~hazardous~~other substances ~~released~~and ~~into~~wastes ~~the~~was ~~environment. We~~not ~~are~~under ~~able~~our to control. ~~directly~~These ~~the~~properties ~~operation~~and ofany ~~only~~hydrocarbons, ~~those~~substances ~~wells~~and ~~with~~wastes ~~respect~~disposed tothereon ~~which~~may webe ~~act~~subject asto ~~operator. Notwithstanding~~CERCLA, ~~our~~RCRA ~~lack~~and ofanalogous ~~direct~~state ~~control~~laws. ~~over~~Under ~~wells~~these ~~operated by others~~laws, ~~the~~we ~~failure~~could ofbe anrequired ~~operator other than us~~ to ~~comply~~remove ~~with~~or ~~applicable~~remediate ~~environmental~~previously ~~regulations~~disposed ~~may,~~wastes in(including ~~certain~~wastes ~~circumstances,~~disposed beof ~~attributed~~or toreleased ~~us. We~~by ~~are~~prior ~~not~~owners ~~aware~~or ofoperators), ~~any~~to ~~liabilities~~clean ~~for~~up ~~which~~contaminated weproperty ~~may~~(including becontaminated ~~held~~groundwater) ~~responsible~~and ~~that~~to ~~would~~perform ~~materially~~remedial ~~and~~operations ~~adversely~~to ~~affect~~prevent usfuture contamination.

~~Waste~~Air ~~handling~~emissions. The ~~Resource~~Clean ~~Conservation~~Air ~~and Recovery~~ Act ~~(“RCRA”)~~ and ~~analogous~~comparable state laws and regulations impose ~~detailed~~restrictions ~~requirements~~on ~~for~~emissions ~~the~~of ~~handling,~~air ~~storage~~pollutants from various industrial sources, ~~treatment~~including compressor stations and ~~disposal~~natural ofgas ~~hazardous~~processing facilities, and ~~solid~~also ~~wastes. RCRA~~impose ~~specifically~~various ~~excludes~~monitoring ~~drilling~~and ~~fluids,~~reporting ~~produced~~requirements. Such ~~waters~~laws and ~~other~~regulations ~~wastes~~may ~~associated~~require ~~with~~that we obtain pre-approval for the ~~exploration,~~construction ~~development~~or modification of certain projects or ~~production~~facilities expected to produce air emissions or result in the increase of ~~crude~~existing ~~oil~~air emissions, ~~natural~~obtain ~~gas~~and strictly comply with air permits containing various emissions and operational limits or ~~geothermal~~utilize ~~energy~~specific ~~from~~emission ~~regulation~~control astechnologies ~~hazardous~~to ~~wastes~~limit emissions. ~~However~~For example, ~~these~~in ~~wastes~~December ~~may~~2014, bethe ~~regulated~~EPA bypublished proposed regulations to revise the ~~U.S.~~National ~~Environmental~~Ambient ~~Protection~~Air ~~Agency~~Quality (Standard for ozone, recommending a standard between 65 to 70 parts per billion, or ppb, for both the “8-hour primary and secondary standards protective of public health and public welfare. The EPA”) orrequested ~~state~~public ~~agencies~~comments on whether the standard should be set as ~~solid~~low ~~wastes~~as 60 ppb or whether the existing 75 ppb standard should be retained. ~~Moreover~~ The EPA anticipates issuing a final rule by October 1, ~~many~~2015. ~~ordinary~~If ~~industrial~~the ~~wastes~~EPA lowers the ozone standard, ~~such~~states ascould ~~paint~~be ~~wastes~~required to implement new, ~~waste~~more ~~solvents~~stringent regulations, ~~laboratory~~which ~~wastes~~could apply to our exploration and ~~waste~~production ~~compressor~~operations. ~~oils~~Compliance ~~may~~with bethese ~~regulated~~or asother ~~hazardous~~new ~~wastes~~regulations ifcould, ~~such~~among ~~wastes~~other ~~have~~things, ~~hazardous~~require ~~characteristics. Although~~installation ~~the~~of ~~costs~~new emission controls on some of ~~managing~~our ~~hazardous~~equipment, ~~waste~~result ~~may~~in belonger ~~significant~~permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business. However, we dobelieve our operations will not ~~believe~~be ~~that~~materially ~~our~~adversely ~~costs~~affected inby ~~this~~any ~~regard~~such requirements, and the requirements are ~~materially~~not expected to be any more burdensome to us than ~~those~~to ~~for~~other similarly situated companies involved in oil and natural gas exploration and production activities.

~~Air~~Water ~~emissions~~discharges and subsurface injections. The Federal Water Pollution Control Act (the “Clean ~~Air~~Water Act”) and ~~comparable~~analogous state laws and regulations impose restrictions onand ~~emissions~~strict ofcontrols ~~air~~with ~~pollutants~~respect ~~from~~to ~~various~~the ~~industrial~~discharge ~~sources~~of pollutants, including ~~compressor~~spills ~~stations~~ and ~~natural~~leaks ~~gas~~of ~~processing~~oil ~~facilities,~~ and ~~also~~other ~~impose~~substances, ~~various~~into ~~monitoring~~waters ~~and~~of ~~reporting~~the ~~requirements. Such~~United ~~laws~~States ~~and~~as ~~regulations~~well ~~may~~as ~~require~~state ~~that~~waters. The wedischarge ~~obtain~~of ~~pre-approval~~pollutants ~~for~~into ~~the~~regulated ~~construction~~waters oris ~~modification~~prohibited, ofexcept ~~certain~~in ~~projects~~accordance orwith ~~facilities~~the ~~expected~~terms toof ~~produce~~a ~~air~~permit ~~emissions~~issued orby ~~result~~the inEPA ~~the~~or ~~increase~~an ofanalogous ~~existing~~state ~~air~~agency. Pursuant ~~emissions,~~to ~~obtain~~these laws and ~~strictly~~regulations, ~~comply~~we ~~with~~may ~~air~~be ~~permits~~required ~~containing~~to ~~various~~obtain ~~emissions~~ and ~~operational~~maintain ~~limits~~approvals or ~~utilize~~permits ~~specific~~for ~~emission~~the ~~control~~discharge ~~technologies~~of towastewater ~~limit~~or ~~emissions. For~~storm ~~example,~~water infrom ~~August~~our ~~2012,~~operations ~~the~~and ~~EPA~~may ~~adopted~~be ~~new~~required ~~rules that~~to ~~impose~~develop ~~additional~~and ~~air~~implement ~~emission~~spill prevention, control ~~standards~~and oncountermeasure ~~well~~plans, ~~completion~~also ~~activities~~referred ~~and~~to ~~certain~~as ~~production~~“SPCC ~~equipment~~plans,” ~~such~~in asconnection ~~glycol~~with ~~dehydrators~~on-site ~~and~~ storage ~~vessels. Some~~ of ~~these~~significant ~~new~~quantities ~~rules~~of oil, ~~such~~including asrefined apetroleum ~~requirement~~products. ~~for~~We ~~flaring~~maintain ofall ~~gas~~required ~~not~~discharge ~~sent~~permits necessary to aconduct ~~gathering~~our ~~line~~operations, ~~became~~and ~~effective~~we inbelieve ~~October~~we ~~2012,~~are ~~but~~in ~~the~~substantial ~~most~~compliance ~~significant~~with ~~new~~their ~~rule,~~terms. ~~requiring~~The ~~the~~Clean ~~use~~Water ofAct ~~“green~~also ~~completions”~~prohibits ~~emission~~the ~~control~~discharge ~~technology~~of todredge ~~reduce~~and ~~air~~fill ~~emissions~~material ~~during~~in ~~well~~regulated ~~completions~~waters, ~~does~~including ~~not~~wetlands, ~~become~~unless ~~effective~~authorized ~~until~~by ~~January 1, 2015~~permit. Federal ~~Our~~and ~~failure~~state toregulatory ~~comply~~agencies ~~with~~can ~~these~~impose ~~requirements~~administrative, ~~could~~civil ~~subject~~and uscriminal topenalties ~~monetary~~for ~~penalties,~~non-compliance ~~injunctions,~~with ~~conditions~~discharge permits or ~~restrictions~~other onrequirements ~~operations~~of ~~and~~the ~~potentially~~Clean ~~criminal~~Water ~~enforcement~~Act ~~actions. Capital~~and ~~expenditures~~analogous ~~for~~state ~~air~~laws ~~pollution~~and ~~equipment~~regulations. In ~~may~~addition, bethe ~~required~~United inStates ~~connection~~Oil ~~with~~Pollution ~~maintaining~~Act orof ~~obtaining~~1990 ~~operating~~(“OPA”) ~~permits~~ and ~~approvals~~similar ~~relating~~legislation toenacted ~~air~~in ~~emissions~~Texas, atLouisiana ~~facilities~~and ~~owned~~other orcoastal ~~operated~~states byimpose ~~us.~~oil ~~However,~~spill weprevention ~~believe~~and ~~our~~control ~~operations~~requirements ~~will~~and ~~not~~significantly beexpand ~~materially~~liability ~~adversely~~for ~~affected~~damages byresulting ~~any~~from ~~such~~oil ~~requirements,~~spills. OPA ~~and~~imposes ~~the~~strict ~~requirements~~and, ~~are~~with ~~not~~limited ~~expected~~exceptions, tojoint beand ~~any~~several ~~more~~liabilities ~~burdensome~~upon toeach usresponsible ~~than~~party tofor ~~other~~oil ~~similarly~~spill ~~situated~~response ~~companies~~and ~~involved~~removal incosts ~~oil~~ and ~~natural~~a ~~gas~~variety ~~exploration~~of public and ~~production~~private ~~activities~~damages.

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~~Water~~Fluids ~~discharges~~associated with oil and natural gas production, consisting primarily of salt water, are disposed by injection in belowground disposal wells. ~~The~~ ~~Federal~~These ~~Water~~disposal ~~Pollution~~wells ~~Control~~are ~~Act~~regulated (pursuant to the Underground Injection Control (“~~Clean~~UIC”) program established under the federal Safe Drinking Water Act (“SDWA”) and analogous state laws. ~~and~~The ~~regulations~~UIC ~~impose~~program ~~restrictions~~requires ~~and~~permits ~~strict~~from ~~controls~~the ~~with~~EPA ~~respect~~or toan analogous state agency for the ~~discharge~~construction and operation of ~~pollutants~~disposal wells, ~~including~~establishes ~~spills~~minimum ~~and~~standards ~~leaks~~for ofdisposal ~~oil~~well operations, and ~~other~~restricts ~~substances,~~the ~~into~~types ~~waters~~and quantities of ~~the~~fluids ~~United~~that ~~States. The~~may ~~discharge~~be ofdisposed. ~~pollutants~~While ~~into~~we ~~regulated~~believe ~~waters~~that isour ~~prohibited,~~disposal ~~except~~well inoperations ~~accordance~~substantially comply with requirements under the ~~terms~~UIC ofprogram, a ~~permit~~change ~~issued~~in bydisposal ~~the~~well ~~EPA~~regulations or anthe ~~analogous~~inability ~~state~~to ~~agency. Pursuant~~obtain topermits ~~these~~for ~~laws~~new ~~and~~disposal ~~regulations,~~wells wein the future may beaffect ~~required~~our ability to ~~obtain~~dispose ~~and~~of ~~maintain~~salt ~~approvals~~water orand ~~permits~~ultimately ~~for~~increase the ~~discharge~~cost of ~~wastewater~~our oroperations. ~~storm~~For ~~water~~example, ~~from~~there ~~our~~exists ~~operations~~a ~~and~~growing ~~may~~concern bethat ~~required~~the toinjection ~~develop~~of saltwater and ~~implement~~other ~~spill~~fluids ~~prevention,~~into ~~control~~belowground ~~and~~disposal ~~countermeasure~~wells ~~plans~~triggers seismic activity in certain areas, ~~also~~including ~~referred~~Texas, towhere aswe ~~“SPCC~~operate. ~~plans~~In response to these concerns,” in ~~connection~~October ~~with~~2014, ~~on-site~~the ~~storage~~Texas ofRailroad ~~significant~~Commission ~~quantities~~(“TRC”) ofpublished ~~oil,~~a ~~including~~final ~~refined~~rule ~~petroleum~~governing ~~products. We~~permitting ~~maintain~~or ~~all~~re-permitting ~~required~~of ~~discharge~~disposal ~~permits~~wells ~~necessary~~that towould ~~conduct~~require, ~~our~~among ~~operations~~other things, ~~and~~the wesubmission ~~believe~~of weinformation ~~are~~on inseismic ~~substantial~~events ~~compliance~~occurring ~~with~~within ~~their~~a ~~terms. Federal~~specified ~~and~~radius ~~state~~of ~~regulatory~~the ~~agencies~~disposal ~~can~~well ~~impose~~location, ~~administrative~~as well as logs, ~~civil~~geologic cross sections and ~~criminal~~structure ~~penalties~~maps ~~for~~relating ~~non-compliance~~to ~~with~~the ~~discharge~~disposal ~~permits~~area in question. If the permittee or ~~other~~an ~~requirements~~applicant of ~~the~~a ~~Clean~~disposal ~~Water~~well ~~Act~~permit ~~and~~fails ~~analogous~~to ~~state~~demonstrate ~~laws~~that ~~and~~the ~~regulations. In~~injected ~~addition,~~fluids are confined to the ~~United~~disposal ~~States~~zone ~~Oil~~or ~~Pollution~~if ~~Act~~scientific ofdata ~~1990~~indicates ~~(“OPA”)~~such ~~and~~a ~~similar~~disposal ~~legislation~~well ~~enacted~~is inlikely ~~Texas~~to be or determined to be contributing to seismic activity, ~~Louisiana~~then ~~and~~the ~~other~~TRC ~~coastal~~may ~~states~~deny, ~~impose~~modify, ~~oil~~suspend ~~spill~~or ~~prevention~~terminate ~~and~~the ~~control~~permit ~~requirements~~application ~~and~~or ~~significantly~~existing ~~expand~~operating ~~liability~~permit for ~~damages~~that ~~resulting~~well. ~~from~~These ~~oil~~new ~~spills. OPA~~seismic ~~imposes~~permitting ~~strict~~requirements ~~and,~~applicable ~~with~~to ~~limited~~disposal ~~exceptions,~~wells ~~joint~~impose more stringent permitting requirements and ~~several~~likely ~~liabilities~~to ~~upon~~result ~~each~~in ~~responsible~~added ~~party~~costs ~~for~~to ~~oil~~comply ~~spill~~or, ~~response~~perhaps, ~~and~~may ~~removal~~require ~~costs~~alternative ~~and~~methods aof ~~variety~~disposing of ~~public~~salt water and ~~private~~other ~~damages~~fluids, which could delay production schedules and also result in increased costs.

Global warming and climate change. InThe ~~December 2009, the~~ EPA has determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted ~~rules regulating~~regulations ~~greenhouse~~to ~~gas~~restrict emissions of greenhouse gases under existing provisions of the Clean Air Act that, ~~including~~among ~~emissions~~other ofthings, ~~greenhouse~~established ~~gases~~Prevention ~~from~~of ~~certain~~Significant ~~large~~Deterioration ~~stationary~~(“PSD”) ~~sources,~~construction ~~effective~~and ~~January 2,~~Title ~~2011. The~~V ~~EPA’s~~operating ~~rules relating~~permit toreviews ~~emissions~~for of greenhouse gases from certain large stationary sources ofthat ~~emissions~~ are ~~currently~~already ~~subject~~potential tomajor asources ~~number~~ of ~~legal~~principal, ~~challenges~~or criteria, ~~but~~pollutant ~~the~~emissions. ~~federal~~Facilities ~~courts~~required ~~have~~to ~~thus~~obtain ~~far~~PSD ~~declined~~permits tofor ~~issue~~their ~~any~~greenhouse ~~injunctions~~gas emissions also will be required to ~~prevent~~meet ~~the~~“best ~~EPA~~available ~~from~~control ~~implementing,~~technology” orstandards ~~requiring~~that ~~state~~typically ~~environmental~~will ~~agencies~~be toestablished ~~implement,~~by the ~~rules~~states. The EPA has also adopted rules requiring the annual reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including certain onshore oil and natural gas production facilities~~, on an annual basis~~. We believe that we are in compliance with all greenhouse gas emissions reporting requirements applicable to our operations.

InWhile ~~addition,~~the United States Congress has from time to time ~~Congress has~~ considered adopting legislation to reduce emissions of greenhouse gases, ~~and~~in ~~almost~~the ~~one-half~~absence of ~~the~~any ~~states~~such legislation in recent years, a number of state and regional efforts have ~~already~~emerged ~~taken~~that ~~legal~~are ~~measures~~aimed toat ~~reduce~~tracking or reducing emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, ~~such~~to asacquire ~~electric~~and ~~power~~surrender ~~plants,~~emission allowances. Although it is not possible at this time to predict how legislation or ~~major~~new ~~producers~~regulations ofthat ~~fuels~~may be adopted to address greenhouse emissions would impact our business, any such asfuture ~~refineries~~laws and ~~gas~~regulations ~~processing~~that ~~plants,~~require reporting of greenhouse gases or otherwise limit emissions of greenhouse gases from our equipment and operations could require us to ~~acquire~~incur costs to monitor and ~~surrender~~report ~~emission~~on ~~allowances.~~greenhouse ~~The~~gas ~~number~~emissions or reduce emissions of ~~allowances~~greenhouse ~~available~~gases associated with our operations, and such requirements could adversely affect demand for ~~purchase~~the oil and natural gas that we produce. For example, in January 2015, the current administration announced that, in the summer of 2015, the EPA is ~~reduced~~expected ~~each~~to ~~year~~propose new regulations, which are currently anticipated to be finalized in an2016, ~~effort~~that will set methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities as part of the administration’s efforts to ~~achieve~~reduce methane emissions from the ~~overall~~oil ~~greenhouse~~and gas ~~emission~~sector ~~reduction~~by ~~goal~~up to 45% from 2012 levels by 2025. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

~~The~~Hydraulic ~~adoption~~fracturing. Hydraulic offracturing ~~legislation~~is oran ~~regulatory~~important ~~programs~~and common practice that is used to ~~reduce~~stimulate ~~emissions~~production of ~~greenhouse~~natural ~~gases~~gas ~~could~~and/or ~~require~~oil usfrom todense ~~incur~~subsurface ~~increased~~rock ~~operating~~formations. The ~~costs,~~hydraulic ~~such~~fracturing asprocess ~~costs~~involves tothe ~~purchase~~injection of water, sand and ~~operate~~chemicals ~~emission~~under ~~control~~pressure ~~systems,~~into the formation to ~~acquire~~fracture ~~emission~~the ~~allowances~~surrounding orrock ~~comply~~and ~~with~~stimulate ~~new~~production. We ~~regulatory~~commonly oruse ~~reporting~~hydraulic ~~requirements~~fracturing as part of our operations. Hydraulic ~~Any~~fracturing ~~such~~typically ~~legislation~~is regulated by state oil and natural gas commissions or other similar state agencies, but several federal agencies have asserted regulatory ~~programs~~authority ~~could~~over ~~also~~certain ~~increase~~aspects of the ~~cost~~process. ofFor ~~consuming~~example, ~~and~~the ~~thereby~~EPA ~~reduce~~has ~~demand~~issued ~~for~~final Clean Air Act regulations governing performance standards, including standards for the ~~oil~~capture ~~and~~of ~~natural~~air ~~gas~~emissions wereleased ~~produce. Consequently,~~during ~~legislation~~hydraulic ~~and~~fracturing; ~~regulatory~~announced ~~programs~~its intent to ~~reduce~~propose ~~emissions~~in the first half of ~~greenhouse~~2015 ~~gases~~effluent ~~could~~limit ~~have~~guidelines anthat ~~adverse~~wastewater ~~effect~~from onshale ~~our~~gas ~~business,~~extraction ~~financial~~operations ~~condition~~must ~~and~~meet ~~results~~before ofdischarging ~~operations.~~to ~~Finally,~~a ittreatment ~~should~~plant; beand ~~noted~~in ~~that~~May ~~some~~2014, ~~scientists~~issued ~~have~~a ~~concluded~~prepublication ~~that~~of ~~increasing~~its ~~concentrations~~Advance Notice of ~~greenhouse~~Proposed ~~gases~~Rulemaking inregarding ~~the~~Toxic ~~Earth’s~~Substances ~~atmosphere~~Control ~~may~~Act ~~produce~~reporting ~~climate~~of ~~changes~~the ~~that~~chemical ~~have~~substances ~~significant~~and ~~physical~~mixtures ~~effects,~~used ~~such~~in ashydraulic ~~increased~~fracturing. ~~frequency~~Also, ~~and~~the ~~severity~~federal Bureau of ~~storms,~~Land ~~droughts,~~Management ~~floods~~issued a revised proposed rule containing disclosure requirements and other ~~climatic~~mandates ~~events.~~for Ifhydraulic ~~any~~fracturing ~~such~~on ~~effects~~federal ~~were~~lands and the agency is now analyzing comments to ~~occur,~~the ~~they~~proposed ~~could~~rulemaking ~~have~~and anis ~~adverse~~expected ~~effect~~to onpromulgate ~~our~~a ~~financial~~final ~~condition~~rule ~~and~~in ~~results~~the first half of ~~operations~~2015.

Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, chemical disclosure and well construction requirements on hydraulic fracturing activities. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

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InFrom ~~addition,~~time ~~certain~~to ~~governmental~~time, ~~reviews~~Congress ~~are~~has ~~either~~considered ~~underway~~legislation orto ~~being~~provide ~~proposed~~for ~~that~~federal ~~focus~~regulation ~~on environmental aspects~~ of hydraulic fracturing ~~practices. The~~under ~~EPA~~the ~~has~~SDWA ~~commenced~~and ato ~~study~~require disclosure of the ~~potential~~chemicals ~~environmental~~used ~~effects~~in ofthe hydraulic fracturing ~~on water resources~~process. At ~~The~~the ~~EPA’s~~state ~~study~~level, ~~includes~~several 18states, ~~separate~~including ~~research~~Texas, ~~projects~~where ~~addressing~~we ~~topics~~conduct ~~such~~operations, asNew ~~water~~Mexico ~~acquisitions~~and Louisiana, ~~chemical~~have ~~mixing~~adopted, ~~well~~and ~~injection~~other states are considering adopting, ~~flowback~~legal ~~and~~requirements ~~produced~~that ~~water~~could impose more stringent permitting, chemical disclosure and ~~wastewater~~well ~~treatment~~construction ~~and~~requirements ~~waste~~on ~~disposal~~hydraulic fracturing activities. ~~The~~Alternatively, ~~EPA~~states ~~has~~or ~~indicated~~local ~~that~~governments itcould ~~expects~~elect to ~~issue~~prohibit ~~its~~hydraulic ~~study~~fracturing ~~report~~altogether, like the State of New York, which announced such a ban in ~~late~~December 2014~~. Moreover~~, ~~the~~as ~~EPA~~well isas ~~developing~~some ~~effluent~~cities ~~limitations~~in ~~for~~Texas, California and Ohio have done. Local government also may seek to adopt ordinances within their jurisdictions regulating the ~~treatment~~time, place and ~~discharge~~manner of ~~wastewater~~drilling ~~resulting~~activities ~~from~~in general or hydraulic fracturing activities ~~and~~in ~~plans~~particular. toWe ~~propose~~believe ~~these~~that ~~standards~~we byfollow ~~late~~applicable ~~2014. Other~~standard ~~governmental~~industry ~~agencies,~~practices ~~including~~and ~~the~~legal ~~U.S.~~requirements ~~Department~~for ofgroundwater ~~Energy~~protection ~~and~~in ~~the~~our Uhydraulic fracturing activities.S. ~~Department~~Nonetheless, ofif ~~the~~new ~~Interior~~or more stringent federal, ~~are~~state ~~evaluating~~or ~~various~~local ~~other~~legal ~~aspects~~restrictions ofrelating to the hydraulic fracturing~~. These~~ ~~ongoing~~process orare ~~proposed~~adopted ~~studies,~~in ~~depending~~areas onwhere ~~their~~we ~~degree~~operate, ofwe ~~pursuit~~could ~~and~~incur ~~any~~potentially ~~meaningful~~significant ~~results~~added ~~obtained,~~costs ~~could~~to ~~spur~~comply ~~initiatives~~with tosuch ~~further~~requirements, ~~regulate~~experience ~~hydraulic~~delays ~~fracturing~~or ~~under~~curtailment in the ~~Safe~~pursuit ~~Drinking~~of ~~Water~~exploration, ~~Act~~development or ~~other~~production ~~regulatory~~activities, ~~mechanisms~~and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. In addition, the EPA has commenced a study of the potential environmental effects of hydraulic fracturing activities, with a draft report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review in the first half of 2015. These ongoing or any future studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

To our knowledge, there have been no citations, suits or contamination of potable drinking water arising from our hydraulic fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability and excess liability insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.

Endangered species. The federal Endangered Species Act and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species or their critical habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Some of our well drilling operations are conducted in areas where protected species are known to exist. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting drilling operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on protected species. It is also possible that a federal or state agency could order a complete halt to drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we perform drilling activities could impair our ability to timely complete well drilling and development and could adversely affect our future production from those areas. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service (“FWS”) is required to make a determination on listing of numerous species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. For example, in March 2014, the FWS announced the listing of the lesser prairie chicken, whose habitat is over a five-state region, including Texas, where we conduct operations, as a threatened species under the ESA. However, the FWS also announced a final rule that will limit regulatory impacts on landowners and businesses from the listing if those landowners and businesses have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies (“WAFWA”), pursuant to which such parties agreed to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee if its actions harm the lesser prairie chicken’s habitat. The listing of the lesser prairie chicken as a threatened species or, alternatively, entry into certain range-wide conservation planning agreements such as WAFWA, could result in increased costs to us from species protection measures, time delays or limitations on the drilling program’s activities, which costs, delays or limitations may be significant.

Pipeline safety. Some of our pipelines are subject to regulation by the U.S. Department of Transportation (the “DOT”) under the Pipeline Safety Improvement Act of 2002, which was reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, and further amended by the Pipeline Safety, Regulation Certainty, and Job Creation Act of 2011 (the “2011 Pipeline Safety Act amendments”). The DOT, through the Pipeline and Hazardous Materials Safety Administration, has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, oil and condensate transmission pipelines that, in the event of a failure, could affect “high consequence areas.” “High consequence areas” are currently defined to include areas with specified population densities, buildings containing populations with limited mobility, areas where people may gather along the route of a pipeline (such as athletic fields or campgrounds), environmentally sensitive areas and commercially navigable waterways. Under the DOT’s regulations, integrity management programs are required to include baseline assessments to identify potential threats to each pipeline segment, implementation of mitigation measures to reduce the risk of pipeline failure, periodic reassessments, reporting and recordkeeping. These regulatory requirements may be expanded in the future upon completion of studies required by the 2011 Pipeline Safety Act amendments.

OSHA and other laws and regulations. We are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Claims are sometimes made or threatened against companies engaged in oil and gas exploration, production and related activities by owners of surface estates, adjoining properties or others alleging damages resulting from environmental contamination and other incidents of operations. We have been named as a defendant in a number of such lawsuits. While some jurisdictions in which we operate limit damages in such cases to the value of land that has been impaired, courts in other jurisdictions have allowed damage claims in excess of land value, including claims for the cost of remediation of contaminated properties. However, we do not believe that resolution of these claims will have a material adverse impact on our financial condition and operations.

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OSHA and other laws and regulations. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Claims are sometimes made or threatened against companies engaged in oil and natural gas exploration, production and related activities by owners of surface estates, adjoining properties or others alleging damages resulting from environmental contamination and other incidents of operations. We have been named as a defendant in a number of such lawsuits. While some jurisdictions in which we operate limit damages in such cases to the value of land that has been impaired, courts in other jurisdictions have allowed damage claims in excess of land value, including claims for the cost of remediation of contaminated properties. However, we do not believe that resolution of these claims will have a material adverse impact on our financial condition and operations.

Competition

We operate in a highly competitive environment. The principal resources necessary for the exploration and production of crude oil and natural gas are leasehold prospects where crude oil and natural gas reserves may be discovered, drilling rigs and related equipment to explore for such reserves and knowledgeable personnel to conduct operations. We must compete for such resources with both major oil and gas companies and independent operators. Many of these competitors have financial and other resources substantially greater than ours. Although we believe our current operating and financial resources are adequate to preclude any significant disruption of our operations in the immediate future, we cannot assure you that such resources will be available to us indefinitely.

Employees

As of April ~~March~~ 1, ~~2014~~2015, we had ~~seven~~six full-time employees. None of our employees are represented by a labor union, and we consider our employee relations to be excellent. We seek to use contract workers and anticipate maintaining a small full-time employee base. We have a staff services agreement with CoAdvantage (formerly Odyssey One Source, Inc.) on a month-to-month basis whereby we jointly employ personnel and share employment responsibilities for the staff.

ITEM 1A. RISK FACTORS.

You should carefully consider the following risk factors and all other information contained herein as well as the information included in this Annual Report in evaluating our business and prospects. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties, other than those we describe below, that are not presently known to us or that we currently believe are immaterial, may also impair our business operations. If any of the following risks occur, our business and consolidated financial results could be harmed. You should refer to the other information contained in this Annual Report, including our consolidated financial statements and the related notes.

Risks Related to Our Business

We have a history of losses which may continue, and which may negatively impact our ability to achieve our business objectives.

We incurred net losses of $38,~~704~~910,~~533~~607 and $63,~~523~~704,~~292~~533 for the years ended December 31, ~~2013~~2014 and ~~2012~~2013, respectively. We cannot assure you that we can achieve or sustain profitability on a quarterly or annual basis in the future. Our operations are subject to the risks and competition inherent in the establishment of a business enterprise. There can be no assurance that future operations will be profitable. Revenues and profits, if any, will depend upon various factors, including whether we will be able to continue expansion of our revenue. We may not achieve our business objectives and the failure to achieve such goals would have an adverse impact on us.

Our lack of diversification will increase the risk of an investment in PERC, and our consolidated financial condition and results of operations may deteriorate if we fail to diversify.

Our business focus is on the oil and gas industry in a limited number of properties, initially in Texas. Larger companies have the ability to manage their risk by geographic diversification. However, we lack diversification, in terms of both the nature and geographic scope of our business. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, changes in field-wide rules, market limitations, or interruption of the processing or transportation of oil or gas. If we cannot diversify our operations, our financial condition and results of operations could deteriorate.

Oil and natural gas drilling is a speculative activity and involves numerous risks and substantial and uncertain costs that could adversely affect us.

An investment in us should be considered speculative due to the nature of our involvement in the exploration for, and the acquisition, development and production of, oil and natural gas. Oil and natural gas operations involve many risks, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that commercial quantities of oil or natural gas will be discovered or acquired by us or, even if discovered or acquired, that any such reserves would be economically recoverable. Further, any changes in the regulations to which our business is subject, including those related to the hydraulic fracturing production method, could also have a material adverse effect on our business, financial condition, results of operations or prospects.

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We received a report from our independent registered public accounting firm with an explanatory paragraph for the year ended December 31, 2014 with respect to our ability to continue as a going concern. The existence of such a report may adversely affect our stock price and our ability to raise capital. There is no assurance that we will not receive a similar report for our year ending December 31, 2015.

In their report dated April 3, 2015, our independent registered public accounting firm expressed substantial doubt about our ability to continue as a going concern as we have incurred operating losses for several years, have a negative cash flow from operations and an accumulated deficit of $37,015,151 as of December 31, 2014. Our ability to continue as a going concern is subject to our ability to achieve profitable operations or obtain necessary funding from outside sources, including obtaining additional funding from the sale of our securities and/or obtaining loans from various financial institutions, where possible. While we have been able to raise approximately $1.9 million in new financing during the first quarter of 2015, our continued net operating losses increase the difficulty in meeting such goals and there can be no assurances that such methods will prove successful.

Our lack of diversification will increase the risk of an investment in PERC, and our consolidated financial condition and results of operations may deteriorate if we fail to diversify.

We have substantial capital requirements that, if not met, may hinder our operations.

Our business is capital intensive and requires us to spend substantial amounts of capital for exploration and development activities. Low product price environments such as the current downturn in oil prices that we are currently experiencing, as well as operating difficulties and other factors, many of which are beyond our control, may cause our revenues and cash flows from operating activities to decrease and may limit our ability to fund our exploration and development activities. We anticipate that we will make substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future and for future drilling programs. If we have insufficient revenues, we may have a limited ability to expend the capital necessary to undertake or complete future drilling programs. We cannot assure you that debt or equity financing, or cash generated by operations, will be available or sufficient to meet these requirements or for other corporate purposes, or if debt or equity financing is available, that it will be on terms acceptable to us. Moreover, future activities may require us to alter our capitalization significantly. Our inability to access sufficient capital for our operations could have a material adverse effect on our business, financial condition, results of operations or prospects.

debt or equity financing is available, that it will be on terms acceptable to us. Moreover, future activities may require us to alter our capitalization significantly. Our inability to access sufficient capital for our operations could have a material adverse effect on our business, financial condition, results of operations or prospects.

Our proved undeveloped locations are scheduled to be drilled over several years, subjecting us to uncertainties that could materially alter the occurrence or timing of our drilling activities.

We have assigned proved undeveloped reserves to certain of our drilling locations as an estimation of our future multi-year development activities on our existing acreage. These identified locations represent a significant part of our growth strategy. At December 31, ~~2013~~2014, our estimated proved undeveloped reserves were ~~approximately 91~~ 87% of total estimated proved reserves. Our ability to drill and develop these locations depends on a number of uncertainties, including (1) our ability to timely drill wells on lands subject to complex development terms and circumstances; (2) the availability of capital, equipment, services and personnel; (3) seasonal conditions; (4) regulatory and third-party approvals; (5) oil and gas prices; and (6) drilling and recompletion costs and results. Because of these uncertainties, we may defer drilling on, or never drill, some or all of these potential locations. If we defer drilling more than five years from the date proved undeveloped reserves were first assigned to a drilling location, we may be required under SEC guidelines to downgrade the category of the applicable reserves from proved undeveloped to probable. Any reclassification of reserves from proved undeveloped to probable could reduce our ability to borrow money and could reduce the value of our debt and equity securities. At December 31, 2014, we removed 879,220 MBOE of reserves from proved undeveloped, primarily as a result of this 5-year development rule.

Price declines may result in impairments of our asset carrying values.

Commodity prices have a significant impact on the present value of our proved reserves. Accounting rules require us to impair, as a non-cash charge to earnings, the carrying value of our oil and gas properties in certain situations. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable, and an impairment may be required. Any impairment charges we record in the future could have a material adverse effect on our results of operations in the period incurred.

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We may have to limit our exploration and development activity, which may result in a loss of investment.

We have a relatively small asset base and limited access to additional capital. Due to our ~~brief operating history and~~ historical operating losses, our operations to date have not been a source of liquidity. We expect significant cash requirements during fiscal year ~~2014~~2015 for our well drilling and completion programs, potential land acquisitions and overhead and working capital purposes. We cannot assure you that we will have, or be able to obtain, sufficient capital to complete our planned exploration and development programs. If additional financing is not available, or is not available on acceptable terms, we will have to curtail our operations, and investors may lose some or all of their investment.

Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.

Our ability to successfully acquire additional properties, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers will depend on developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. These realities are subject to change and may impair our ability to grow.

To develop our business, we will endeavor to use the business relationships of our management to enter into strategic relationships, which may take the form of joint ventures with other private parties and contractual arrangements with other oil and gas companies, including those that supply equipment and other resources that we will use in our business. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

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Competition in obtaining rights to explore and develop oil and gas reserves and to market our production may impair our business.

The oil and gas industry is highly competitive. Other oil and gas companies may seek to acquire oil and gas leases and other properties and services we will need to operate our business in the areas in which we expect to operate. Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors. Competitors include larger companies, which, in particular, may have access to greater resources, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage. In addition, actual or potential competitors may be strengthened through the acquisition of additional assets and interests. If we are unable to compete effectively or adequately respond to competitive pressures, this inability may materially adversely affect our consolidated results of operations and financial condition.

If we are unable to obtain additional funding our business operations will be harmed and if we do obtain additional financing our then existing shareholders may suffer substantial dilution.

While we believe that our currently available funds can sustain our current level of operations for twelve months, we will require additional capital to fund our planned growth, including drilling and lease acquisition programs. We may be unable to obtain the additional capital required. Furthermore, inability to maintain capital may damage our reputation and credibility with industry participants. Our inability to raise additional funds when required may have a negative impact on our consolidated results of operations and financial condition.

Future acquisitions, exploration, development, production, and leasing activities, as well as our administrative requirements (such as salaries, insurance expenses and general overhead expenses, as well as legal compliance costs and accounting expenses) will require a substantial amount of additional capital and cash flow.

We plan to pursue sources of additional capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means. We may not be successful in locating suitable financing transactions in the time period required or at all, and we may not obtain the capital we require by other means.

Any additional capital raised through the sale of equity may dilute your ownership percentage. This could also result in a decrease in the fair market value of our equity securities because our assets would be owned by a larger pool of outstanding equity. The terms of securities we issue in future capital transactions may be more favorable to our new investors, and may include preferences, superior voting rights and the issuance of warrants or other derivative securities, and issuances of incentive awards under equity employee incentive plans, which may have a further dilutive effect.

Our ability to obtain the required financing may be impaired by such factors as the capital markets (both generally and in the oil and gas industry in particular), our status as a new enterprise without a significant demonstrated operating history, the location of our oil and natural gas properties and prices of oil and natural gas on the commodities markets (which will impact the amount of asset-based financing available to us) and/or the loss of key management. Further, if oil and/or natural gas prices on the commodities markets decrease, then our revenues will likely decrease, and such decreased revenues may increase our capital requirements. If the amount of capital we are able to raise from financing activities, together with our revenues from operations, is not sufficient to satisfy our capital needs (even to the extent that we reduce our operations), we may be required to cease our operations.

We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees, accounting fees, securities law compliance fees, printing and distribution expenses and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we may issue, such as convertible notes and warrants, which may adversely impact our consolidated financial results.

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We may not be able to effectively manage our growth, which may harm our profitability.

Our strategy envisions expanding our business. If we fail to effectively manage our growth, our consolidated financial results could be adversely affected. Growth may place a strain on our management systems and resources. We must continue to refine and expand our business development capabilities, our systems and processes and our access to financing sources. As we grow, we must continue to hire, train, supervise and manage new employees. We cannot assure you that we will be able to:

·	meet our capital needs;

·	expand our systems effectively or efficiently or in a timely manner;

·	allocate our human resources optimally;

·	identify and hire qualified employees or retain valued employees; or

·	incorporate effectively the components of any business that we may acquire in our effort to achieve growth.

If we are unable to manage our growth, our operations and our consolidated financial results could be adversely affected by inefficiency, which could diminish our profitability.

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If we are unable to retain the services of Messrs. Neufeld, Waldron, or Sudderth, or if we are unable to successfully recruit qualified managerial and field personnel having experience in oil and gas exploration, we may not be able to continue our operations.

Our success depends to a significant extent upon the continued services of Mr. Michael Neufeld, our President and Chairman, Mr. Jonathan Waldron, our Chief Financial Officer, and Mr. William Sudderth, our Executive Vice President. The loss of the services of Messrs. Neufeld, Waldron, or Sudderth could have a material adverse effect on our growth, revenues, and prospective business. We do not have key-man insurance on the lives of Messrs. Neufeld, Waldron, or Sudderth. In addition, in order to successfully implement and manage our business plan, we will be dependent upon, among other things, successfully recruiting qualified managerial and field personnel having experience in the oil and gas exploration business. Competition for qualified individuals is intense. There can be no assurance that we will be able to find, attract and retain existing employees or that we will be able to find, attract and retain qualified personnel on acceptable terms.

RISKS RELATED TO OUR INDUSTRY

Oil and natural gas drilling is a speculative activity and involves numerous risks and substantial and uncertain costs that could adversely affect us.

Competition in obtaining rights to explore and develop oil and gas reserves and to market our production may impair our business.

Our exploration for oil and gas is risky and may not be commercially successful, and the 3D seismic data and other advanced technologies we use cannot eliminate exploration risk, which could impair our ability to generate revenues from our operations.

Our future success will depend on the success of our exploratory drilling program. Oil and gas exploration involves a high degree of risk. These risks are more acute in the early stages of exploration. Our expenditures on exploration may not result in new discoveries of oil or natural gas in commercially viable quantities. It is difficult to project the costs of implementing an exploratory drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions, such as over-pressured zones and tools lost in the hole, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof.

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Even when used and properly interpreted, 3D seismic data and visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. In addition, the use of 3D seismic data becomes less reliable when used at increasing depths. We could incur losses as a result of expenditures on unsuccessful wells. If exploration costs exceed our estimates, or if our exploration efforts do not produce results which meet our expectations, our exploration efforts may not be commercially successful, which could adversely impact our ability to generate revenues from operations.

Our exploration activities subject us to greater risks than development activities.

Generally, our oil and gas exploration activities pose a higher economic risk to us than our development activities. Exploration activities involve the drilling of wells in areas where there is little or no known production. Development activities relate to increasing oil or gas production from an area that is known to be productive by drilling additional wells, working over and recompleting existing wells and other production enhancement techniques. Exploration projects are identified through subjective analysis of geological and geophysical data, including the use of 3-D seismic and other available technology. By comparison, the identification of development prospects is significantly based upon existing production surrounding or adjacent to the proposed drilling site.

To the extent we engage in exploration activities, we have a greater risk of drilling dry holes or not finding oil and gas that can be produced economically. The seismic data and other technology we use does not allow us to know with certainty prior to drilling a well whether oil or gas is present or can be produced economically. We cannot assure you that any of our future exploration efforts will be successful. If these activities are unsuccessful, it will have a significant adverse effect on our results of operations, cash flows and capital resources.

We may not be able to develop oil and gas reserves on an economically viable basis and our reserves and production may decline as a result.

To the extent that we succeed in discovering oil and/or natural gas reserves, we cannot assure that these reserves will be capable of production levels we project or in sufficient quantities to be commercially viable. On a long-term basis, our viability depends on our ability to find or acquire, develop and commercially produce additional oil and natural gas reserves. Without the addition of reserves through acquisition, exploration or development activities, our reserves and production will decline over time as reserves are produced. Our future reserves will depend not only on our ability to develop then-existing properties, but also on our ability to identify and acquire additional suitable producing properties or prospects, to find markets for the oil and natural gas we develop and to effectively distribute our production into our markets.

Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-downs of connected wells resulting from extreme weather conditions, problems in storage and distribution and adverse geological and mechanical conditions. While we will endeavor to effectively manage these conditions, we cannot be assured of doing so optimally, and we will not be able to eliminate them completely in any case. Therefore, these conditions could diminish our revenue and cash flow levels and result in the impairment of our oil and natural gas interests.

~~Estimates~~Our ofproved ~~oil~~reserves are estimates and ~~natural~~depend ~~gas~~on ~~reserves~~many ~~that~~assumptions. weAny ~~make~~material ~~may~~inaccuracies bein ~~inaccurate~~these assumptions could cause the quantity and value of our ~~actual~~oil and gas reserves, and our revenues, ~~may~~profitability and cash flows to be ~~lower~~materially ~~than~~different from our ~~financial projections~~estimates.

WeThe ~~will~~accuracy ~~make~~of ~~estimates~~estimated ofproved ~~oil~~reserves and ~~natural~~estimated ~~gas~~future net cash flows from such reserves, ~~upon~~is ~~which~~a wefunction ~~will~~of ~~base~~the ~~our~~quality ~~financial~~of ~~projections. We~~available ~~will~~geological, ~~make~~geophysical, ~~these~~engineering ~~reserve~~and ~~estimates~~economic ~~using~~data and is subject to various assumptions, including assumptions asrequired by the SEC relating to oil and ~~natural~~ gas prices, drilling and operating expenses and other matters. Although we believe that our estimated proved reserves represent reserves that we are reasonably certain to recover, ~~capital~~actual ~~expenditures~~future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and ~~availability~~quantities of ~~funds~~recoverable oil and gas reserves will most likely vary from the assumptions and estimates used to determine proved reserves. ~~Some~~ Any significant variance could materially affect the estimated quantities and value of ~~these~~our ~~assumptions~~oil ~~are~~and ~~inherently~~gas ~~subjective~~reserves, which in turn could adversely affect our cash flows, results of operations, financial condition and the ~~accuracy~~availability of ~~our~~capital ~~reserve~~resources. In addition, we may adjust estimates ~~relies~~of inproved ~~part~~reserves onto ~~the~~reflect ~~ability~~production history, results of ~~our~~exploration ~~management~~and ~~team~~development, ~~engineers~~prevailing oil and gas prices and other ~~advisors~~factors, many of which are beyond our control. Downward adjustments to ~~make~~our ~~accurate~~estimated ~~assumptions~~proved reserves could require us to impair the carrying value of our oil and gas properties, which would reduce our earnings and our stockholders’ equity.

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InThe ~~addition,~~present ~~economic~~value ~~factors~~of ~~beyond~~proved ~~our~~reserves ~~control,~~will ~~such~~not asnecessarily ~~interest~~equal ~~rates,~~the ~~will~~current ~~also~~fair ~~impact~~market ~~the~~ value of our ~~reserves. The~~estimated ~~process of estimating~~ oil and ~~natural~~ gas reserves. In isaccordance ~~complex,~~with ~~and~~reserve ~~will~~reporting ~~require~~requirements usof ~~to use significant decisions and assumptions in~~ the ~~evaluation~~SEC, ofwe ~~available~~are ~~geological,~~required ~~geophysical,~~to ~~engineering~~establish ~~and~~ economic ~~data~~production for ~~each~~reserves ~~property. As~~on aan ~~result,~~average ~~our~~historical ~~reserve estimates will be inherently imprecise~~price. Actual future ~~production,~~prices ~~oil~~ and ~~natural gas~~costs ~~prices,~~may ~~revenues,~~be ~~taxes,~~materially ~~development~~higher ~~expenditures,~~or ~~operating~~lower ~~expenses~~than ~~and~~those ~~quantities~~required ofby ~~recoverable~~the ~~oil~~SEC. The ~~and~~timing ~~natural~~of ~~gas~~both ~~reserves~~the ~~may~~production ~~vary~~and ~~substantially~~expenses ~~from~~with ~~those~~respect weto ~~estimate. If~~the ~~actual~~development and production ~~results~~of ~~vary~~oil ~~substantially~~and ~~from~~gas ~~our~~properties ~~reserve~~will ~~estimates,~~affect ~~this~~the ~~could~~timing ~~materially~~of ~~reduce~~future ~~our~~net ~~revenues~~cash ~~and~~flows ~~result~~from inproved ~~the~~reserves ~~impairment of our oil~~ and ~~natural~~their ~~gas~~present ~~interests~~value.

We may not be able to replace production with new reserves.

In general, the volume of production from an oil and gas property declines as reserves related to that property are depleted. The decline rates depend upon reservoir characteristics. Exploring for, developing or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop or acquire additional reserves. Also, we may not be able to make the necessary capital investments if our cash flows from operations decline or external sources of capital become limited or unavailable. We cannot give assurance that our future exploration, development and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs.

Drilling new wells could result in new liabilities, which could endanger our interests in our properties and assets.

There are risks associated with the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, craterings, sour gas releases, fires and spills, among others. The occurrence of any of these events could significantly reduce our revenues or cause substantial losses, impairing our future consolidated operating results. We may become subject to liability for pollution, blow-outs or other hazards. We intend to obtain insurance with respect to these hazards; however, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. The payment of such liabilities could reduce the funds available to us or could, in an extreme case, result in a total loss of our properties and assets. Moreover, we may not be able to maintain adequate insurance in the future at rates that are considered reasonable. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and the invasion of water into producing formations.

The lack of availability or high cost of drilling rigs, fracture stimulation crews, equipment, supplies, insurance, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, fracture stimulation crews, equipment, supplies, key infrastructure, insurance or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified crews rise as the number of active rigs and completion fleets in service increases. If increasing levels of exploration and production result in response to strong prices of oil and natural gas, the demand for oilfield services will likely rise, and the costs of these services will likely increase, while the quality of these services may suffer. If the lack of availability or high cost of drilling rigs, equipment, supplies, insurance or qualified personnel were particularly severe in Texas, we could be materially and adversely affected because our operations and properties are concentrated in this state.

Decommissioning costs are unknown and may be substantial. Unplanned costs could divert resources from other projects.

We may become responsible for costs associated with abandoning and reclaiming wells, facilities and pipelines which we use for production of oil and natural gas reserves. Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.” We have not yet determined whether we will establish a cash reserve account for these potential costs in respect of any of our properties or facilities, or if we will satisfy such costs of decommissioning from the proceeds of production in accordance with the practice generally employed in onshore and offshore oilfield operations. If decommissioning is required before economic depletion of our properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business.

Our inability to obtain necessary facilities could hamper our operations.

Oil and gas exploration and development activities are dependent on the availability of drilling and related equipment, transportation, power and technical support in the particular areas where these activities will be conducted, and our access to these facilities may be limited. To the extent that we conduct our activities in remote areas, the facilities required may not be proximate to our operations, which will increase our expenses. Demand for scarce equipment and other facilities or access restrictions may affect the availability of such equipment to us and may delay exploration and development activities. The quality and reliability of necessary facilities may also be unpredictable and we may be required to make efforts to standardize our facilities, which may entail unanticipated costs and delays. Shortages and/or the unavailability of necessary equipment or other facilities will impair our activities, either by delaying our activities, increasing our costs or otherwise.

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Prices and markets for oil and natural gas are unpredictable and tend to fluctuate significantly, which could reduce profitability, growth and the value of our business.

Oil and natural gas are commodities whose prices are determined based on world demand, supply and other factors, all of which are beyond our control. World prices for oil and natural gas have fluctuated widely in recent years. The average price per barrel was $9793.9826 in ~~2013~~2014 and $9697.1198 in ~~2012~~2013, and the average wellhead price per thousand cubic feet of natural gas was $34.73 39 in ~~2013~~2014 and $23.6673 in ~~2012~~2013 (source: U.S. Energy Information Administration). We expect that prices will continue to fluctuate in the future. Price fluctuations will have a significant impact upon our revenue, the return from our reserves and on our financial condition generally. Price fluctuations for oil and natural gas commodities may also impact the investment market for companies engaged in the oil and gas industry. Decreases in the prices of oil and natural gas may have a material adverse effect on our consolidated financial condition, the future results of our operations and the quantities of reserves recoverable on an economic basis.

Increases in our operating expenses will impact our operating results and financial condition.

Exploration, development, production, marketing (including distribution costs) and regulatory compliance costs (including taxes) will substantially impact the net revenues and profits we derive from the oil and natural gas that we produce. These costs are subject to fluctuations and variation in the different locales in which we operate, and we may not be able to predict or control these costs. If these costs exceed our expectations, this may adversely affect our consolidated results of operations. In addition, we may not be able to earn net revenue at our predicted levels, which may impact our ability to satisfy our obligations.

Penalties we may incur could impair our business.

Failure to comply with government regulations could subject us to civil and criminal penalties, could require us to forfeit property rights, and may affect the value of our assets. We may also be required to take corrective actions, such as installing additional equipment or taking other actions, each of which could require us to make substantial capital expenditures. We could also be required to indemnify our employees in connection with any expenses or liabilities that they may incur individually in connection with regulatory action against them. As a result, our future business prospects could deteriorate due to regulatory constraints, and our profitability could be impaired by our obligation to provide such indemnification to our employees.

Compliance with laws and regulations governing our activities could be costly and could negatively impact production.

Our oil and gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws.

The state in which we operate requires permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. The state also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the spacing, plugging and abandonment of such wells. The statutes and regulations of certain states ~~may~~ also limit the rate at which oil and gas can be produced from our properties.

The FERC regulates interstate gas transportation rates and service conditions, which affect the marketing of gas we produce, as well as the revenues we receive for sales of such production. Since the mid-1980s, the FERC has issued various orders that have significantly altered the marketing and transportation of gas. These orders resulted in a fundamental restructuring of interstate pipeline sales and transportation services, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales services such pipelines previously performed. These FERC actions were designed to increase competition within all phases of the gas industry. The interstate regulatory framework may enhance our ability to market and transport our gas, although it may also subject us to greater competition and to the more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances.

Our sales of oil reand natural gas are not presently regulated and are made at market prices. The price we receive from the sale of ~~oil~~these products is affected by the cost of transporting itthem to market. The FERC has implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rate to inflation, subject to certain conditions and limitations. We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs, which may have the effect of reducing wellhead prices for oil and natural gas.

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Under the EP Act 2005, the FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our gas operations have not been regulated by the FERC under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional entities to FERC annual reporting. Additional rules and legislation pertaining to those and other matters may be considered or adopted by the FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability.

Our oil and gas exploration and production and related activities are subject to extensive environmental regulations and to laws that can give rise to substantial liabilities from environmental contamination.

Our operations are subject to extensive federal, state and local environmental laws and regulations, which impose limitations on the emission and discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of hazardous materials and solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities to investigate or remediate contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage, may arise at many locations, including properties in which we have an ownership interest but no operational control, properties we formerly owned or operated and sites where our wastes have been treated or disposed of, as well as at properties that we currently own or operate. Such liabilities may arise even where the contamination does not result from any noncompliance with applicable environmental laws regardless of fault. Under a number of environmental laws, such liabilities may also be strict, joint and several, meaning that we could be held responsible for more than our share of the liability involved, or even the entire share. Environmental requirements generally have become more stringent in recent years, and compliance with those requirements more expensive.

We have incurred expenses in connection with environmental compliance, and we anticipate that we will continue to do so in the future. Failure to comply with extensive applicable environmental laws and regulations could result in significant civil or criminal penalties and remediation costs, as well as the issuance of administrative or judicial orders limiting operations or prohibiting certain activities. Some of our properties, including properties in which we have an ownership interest but no operating control, may be affected by environmental contamination that may require investigation or remediation. Some of our operations are located in environmentally sensitive environments, such as coastal waters, wetlands and other protected areas. Some of our operations are in areas particularly susceptible to damage by hurricanes or other destructive storms, which could result in damage to facilities and discharge of pollutants. In addition, claims are sometimes made or threatened against companies engaged in oil and gas exploration and production by owners of surface estates, adjoining properties or others alleging damage resulting from environmental contamination and other incidents of operation, and such claims have been asserted against us as well as companies we have acquired. Compliance with, and liabilities for remediation under, these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect our business, financial condition and results of operations.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil and gas that we produce.

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment, because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, including emissions of greenhouse gases from certain large stationary sources. The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including certain onshore oil and gas production facilities, on an annual basis.

In addition, from time to time Congress has considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

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The adoption of legislation or regulatory programs to reduce emission of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emission control systems, to acquire emission allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important and common practice that is used to stimulate production of gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, chemical disclosure and well construction requirements on hydraulic fracturing activities. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

On August 16, 2012, the EPA adopted final regulations under the Clean Air Act that, among other things, require additional emission controls for gas and NGL production, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with such production activities. The final regulations require the reduction of VOC emissions from gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. For well completion operations occurring at such well sites before January 1, 2015, the final regulations allow operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions. These regulations also establish specific new requirements regarding emissions from dehydrators, storage tanks and other production equipment. Compliance with these requirements could increase our costs of development and production.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on water resources. The EPA’s study includes 18 separate research projects addressing topics such as water acquisition, chemical mixing, well injection, flowback and produced water, and wastewater treatment and disposal. The EPA has indicated that it expects to issue its study report in late 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by late 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These efforts could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanisms, ultimately make it more difficult or costly for us to perform hydraulic fracturing and increase our costs of compliance and doing business.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from various sources for use in our operations. During the past several years, West Texas and Southeastern New Mexico have experienced the lowest inflows of water in recent history, and these drought conditions expanded into the southern plains states in 2012. As a result of this severe drought, some local water districts may begin restricting the use of water subject to their jurisdiction for drilling and hydraulic fracturing in order to protect the local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

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~~Exploratory~~Federal ~~drilling~~and ~~involves~~state ~~many~~legislation ~~risks~~ and weregulatory ~~may~~initiatives ~~become~~relating ~~liable~~to ~~for~~hydraulic ~~pollution~~fracturing orcould ~~other~~result ~~liabilities~~in ~~which~~increased ~~may~~costs ~~have~~and anadditional ~~adverse~~operating ~~effect~~restrictions onor ~~our consolidated financial position~~delays.

~~Drilling~~Hydraulic ~~operations~~fracturing ~~generally~~involves ~~involve~~the ainjection ~~high~~of ~~degree~~water, ofsand, ~~risk~~and chemicals under pressure into dense subsurface rock formations to fracture the surrounding rock and stimulate production. We ~~Hazards~~commonly ~~such~~use hydraulic fracturing as ~~unusual~~part orof ~~unexpected~~our ~~geological~~operations. Hydraulic ~~formations,~~fracturing ~~power~~typically ~~outages,~~is ~~labor~~regulated ~~disruptions,~~by ~~blow-outs,~~state ~~sour~~oil and natural gas ~~leakage~~commissions, ~~fire,~~but ~~inability~~the EPA has asserted federal regulatory authority pursuant to ~~obtain~~the ~~suitable~~SDWA orover ~~adequate~~certain ~~machinery,~~hydraulic ~~equipment~~fracturing oractivities ~~labor,~~involving ~~and~~the ~~other~~use ~~risks~~of ~~are~~diesel, ~~involved.~~and Wein ~~may~~February ~~become~~2014, ~~subject~~issued topermitting ~~liability~~guidance for ~~pollution~~such oractivities. ~~hazards~~Also, ~~against~~in ~~which~~May we2014, ~~cannot~~the ~~adequately~~EPA ~~insure~~issued oran ~~for~~Advanced ~~which~~Notice weof ~~may~~Proposed ~~elect~~Rulemaking ~~not~~under tothe ~~insure.~~Toxic ~~Incurring~~Substances ~~any~~Control ~~such~~Act ~~liability~~that ~~may~~would ~~have~~require acompanies ~~material~~to ~~adverse~~disclose ~~effect~~information onregarding ~~our~~the ~~consolidated~~chemicals ~~financial~~used ~~position~~in ~~and~~hydraulic ~~operations~~fracturing.

~~Any~~At ~~change~~the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example in May 2013, the Texas Railroad Commission adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Local government ~~regulation~~also may seek to adopt ordinances within their jurisdictions regulating the time, place and/ manner of drilling activities in general or ~~administrative~~hydraulic ~~practices~~fracturing ~~may~~activities ~~have~~in aparticular ~~negative~~or ~~impact~~prohibit onthe ~~our~~performance ~~ability~~of well drilling in general or hydraulic fracturing in particular. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and ~~our~~perhaps ~~profitability~~even be precluded from drilling wells.

The ~~laws,~~White ~~regulations,~~House ~~policies~~Council oron ~~current~~Environmental ~~administrative~~Quality is coordinating an administration-wide review of hydraulic fracturing practices, and the EPA has commenced a study of ~~any~~the ~~government~~potential ~~body~~environmental effects of hydraulic fracturing on water resources. The EPA has indicated that it expects to issue its study report in the first half of 2015. Moreover, ~~organization~~the orEPA ~~regulatory~~is ~~agency~~developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards sometime in 2015. Other governmental agencies, including the ~~United~~U.S. ~~States~~Department orof ~~any~~Energy and the U.S. Department of the Interior, are evaluating various other ~~jurisdiction~~aspects of hydraulic fracturing. These ongoing or proposed studies, ~~may~~depending beon ~~changed~~their findings, ~~applied~~could spur initiatives to further regulate hydraulic fracturing under the SDWA or ~~interpreted~~other regulatory mechanisms. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in aareas ~~manner~~where ~~which~~we ~~will~~operate, ~~fundamentally~~we ~~alter~~could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the ~~ability~~pursuit of ~~our~~exploration, ~~Company~~development, toor ~~carry~~production onactivities, ~~our~~and ~~business~~perhaps even be precluded from drilling wells.

~~The~~Our ~~actions,~~operations ~~policies~~are orsubstantially ~~regulations,~~dependent oron ~~changes~~the ~~thereto,~~availability of ~~any~~water. Restrictions ~~government~~on ~~body~~our orability ~~regulatory~~to ~~agency,~~obtain orwater ~~other special interest groups,~~ may have aan ~~detrimental~~adverse effect on ~~us.~~our ~~Any~~financial orcondition, ~~all~~results of ~~these~~operations ~~situations may have a negative impact on our ability to operate~~ and~~/or~~ ~~our~~cash ~~profitably~~flows.

~~Our~~Water ~~insurance~~is ~~may~~an beessential ~~inadequate~~component of both the drilling and hydraulic fracturing processes. Historically, we have been able to ~~cover~~purchase ~~liabilities~~water from various sources for use in our operations. If we are unable to obtain water to use in our operations from local sources, we may ~~incur~~be unable to economically produce oil and gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

~~Our~~We ~~involvement in the exploration for and development of oil and gas properties~~ may result in our becoming subject to liability for pollution, blow-outs, property damage, personal injury or other hazards. Although we will obtain insurance in accordance with industry standards to address such risks, such insurance has limitations on liability that may not be ~~sufficient~~insured toagainst ~~cover the full extent of such liabilities. In addition, such risks may not, in~~ all circumstances, be insurable or, in certain circumstances, we may choose not to obtain insurance to protect against specific risks due to the high premiums associated with such insurance or for other reasons. The payment of ~~such uninsured liabilities would reduce~~ the ~~funds~~operating ~~available~~hazards to ~~us. If~~which weour ~~suffer~~business ~~a significant event or occurrence that~~ is ~~not fully insured, or if the insurer of such event is not solvent, we could be required to divert funds from capital investment or other uses towards covering our liability for such events~~exposed.

Our operations are subject to the usual hazards incident to the drilling and production of oil and gas, such as windstorms, lightning strikes, blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids (including fluids used in hydraulic fracturing activities), fires, severe weather and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations, all of which could result in a substantial loss. We maintain insurance against some, but not all, of the risks described above. Such insurance may not be adequate to cover losses or liabilities. Also, we cannot give assurance of the continued availability of insurance at premium levels that justify its purchase.

Our business will suffer if we cannot obtain or maintain the necessary licenses.

Our operations will require licenses, permits and in some cases renewals of licenses and permits from various governmental authorities. Our ability to obtain, sustain or renew such licenses and permits on acceptable terms is subject to changes in regulations and policies and to the discretion of the applicable government agencies, among other factors. Our inability to obtain, or our loss of or denial of extension, to any of these licenses or permits could hamper our ability to produce revenues from our operations.

Certain United States federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation.

Recently, there has been significant discussion among members of Congress regarding potential legislation that, if enacted into law, would eliminate certain key United States federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, among other proposals:

· the repeal of the limited percentage depletion allowance for oil and natural gas production in the United States;

· the replacement of expensing intangible drilling and development costs in the year incurred with an amortization of those costs over several years;

· the elimination of the deduction for certain domestic production activities; and

· an extension of the amortization period for certain geological and geophysical expenditures.

It is unclear whether these or similar changes will be enacted. The passage of this legislation or any similar changes in federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to U.S. oil and natural gas exploration and development. Any such changes could have an adverse effect on our financial position, results of operations and cash flows.

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Certain United States federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of proposed legislation.

Legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to:

·	the repeal of the percentage depletion allowance for oil and natural gas properties;

·	the elimination of current deductions for intangible drilling and development costs;

·	the elimination of the deduction for certain domestic production activities; and

·	an extension of the amortization period for certain geological and geophysical expenditures.

It is unclear whether these or similar changes will be enacted. The passage of this legislation or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development. Any such changes could have an adverse effect on our financial position, results of operations and cash flows.

Challenges to our properties may impact our consolidated financial condition.

Title to oil and gas interests is often not capable of conclusive determination without incurring substantial expense. While we intend to make appropriate inquiries into the title of properties and other development rights we acquire, title defects may exist. In addition, we may be unable to obtain adequate insurance for title defects, on a commercially reasonable basis or at all. If title defects do exist, it is possible that we may lose all or a portion of our right, title and interests in and to the properties to which the title defects relate. If our property rights are reduced, our ability to conduct our exploration, development and production activities may be impaired.

We will rely on technology to conduct our business and our technology could become ineffective or obsolete.

We rely on technology, including geographic and seismic analysis techniques and economic models, to develop our reserve estimates and to guide our exploration, development and production activities. We will be required to continually enhance and update our technology to maintain its efficacy and to avoid obsolescence. The costs of doing so may be substantial, and may be higher than the costs that we anticipate for technology maintenance and development. If we are unable to maintain the efficacy of our technology, our ability to manage our business and to compete may be impaired. Further, even if we are able to maintain technical effectiveness, our technology may not be the most efficient means of reaching our objectives, in which case we may incur higher operating costs than we would were our technology more efficient.

RISKS RELATED TO OUR COMMON STOCK

There has been a limited trading market for our common stock.

It is anticipated that there will be a limited trading market for our common stock on the ~~Over-the-Counter~~OTCQB ~~Markets~~market ~~Group~~ (“OTCQB”). The lack of an active market may impair your ability to sell your shares at the time you wish to sell them or at a price that you consider reasonable. The lack of an active market may also reduce the fair market value of your shares. An inactive market may also impair our ability to raise capital by selling shares of capital stock and may impair our ability to acquire other companies or assets by using common stock as consideration.

You may have difficulty trading and obtaining quotations for our common stock.

The common stock may not be actively traded, and the bid and asked prices for our common stock on the OTCQB may fluctuate widely. As a result, investors may find it difficult to dispose of, or to obtain accurate quotations of the price of, our securities. This severely limits the liquidity of the common stock, and would likely reduce the market price of our common stock and hamper our ability to raise additional capital.

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Our common stock is not currently traded at high volume, and you may be unable to sell at or near ask prices or at all if you need to sell or liquidate a substantial number of shares at one time.

Our common stock is currently traded, but with very low, if any, volume, based on quotations on the OTCQB, meaning that the number of persons interested in purchasing our common stock at or near bid prices at any given time may be relatively small or non-existent. This situation is attributable to a number of factors, including the fact that we are a small company which is still relatively unknown to stock analysts, stock brokers, institutional investors and others in the investment community that generate or influence sales volume, and that even if we came to the attention of such persons, they tend to be risk-averse and would be reluctant to follow an unproven company such as ours or purchase or recommend the purchase of our shares until such time as we became more seasoned and viable. As a consequence, there may be periods of several days or more when trading activity in our shares is minimal or non-existent, as compared to a seasoned issuer which has a large and steady volume of trading activity that will generally support continuous sales without an adverse effect on share price. We cannot give you any assurance that a broader or more active public trading market for our common stock will develop or be sustained, or that trading levels will be sustained.

Shareholders should be aware that, according to Commission Release No. 34-29093, the market for “penny stocks” has suffered in recent years from patterns of fraud and abuse. Such patterns include (1) control of the market for the security by one or a few broker-dealers that are often related to the promoter or issuer; (2) manipulation of prices through prearranged matching of purchases and sales and false and misleading press releases; (3) boiler room practices involving high-pressure sales tactics and unrealistic price projections by inexperienced sales persons; (4) excessive and undisclosed bid-ask differential and markups by selling broker-dealers; and (5) the wholesale dumping of the same securities by promoters and broker-dealers after prices have been manipulated to a desired level, along with the resulting inevitable collapse of those prices and with consequent investor losses. Our management is aware of the abuses that have occurred historically in the penny stock market. Although we do not expect to be in a position to dictate the behavior of the market or of broker-dealers who participate in the market, management will strive within the confines of practical limitations to prevent the described patterns from being established with respect to our securities. The occurrence of these patterns or practices could increase the future volatility of our share price.

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The market price of our common stock may, and is likely to continue to be, highly volatile and subject to wide fluctuations.

The market price of our common stock is likely to be highly volatile and could be subject to wide fluctuations in response to a number of factors that are beyond our control, including:

dilution caused by our issuance of additional shares of common stock and other forms of equity securities in connection with future capital financings to fund our operations and growth, to attract and retain valuable personnel and in connection with future strategic partnerships with other companies;

·	announcements of new acquisitions, reserve discoveries or other business initiatives by our competitors;

·	our ability to take advantage of new acquisitions, reserve discoveries or other business initiatives;

·	fluctuations in revenue from our oil and gas business as new reserves come to market;

·	changes in the market for oil and natural gas commodities and/or in the capital markets generally;

·	changes in the demand for oil and natural gas, including changes resulting from the introduction or expansion of alternative fuels;

·	quarterly variations in our revenues and operating expenses;

·	changes in the valuation of similarly situated companies, both in our industry and in other industries;

·	changes in analysts’ estimates affecting our company, our competitors and/or our industry;

·	changes in the accounting methods used in or otherwise affecting our industry;

·	additions and departures of key personnel;

·	announcements by relevant governments pertaining to incentives for alternative energy development programs;

·	fluctuations in interest rates and the availability of capital in the capital markets; and

·	significant sales of our common stock, including sales by future investors in future offerings we expect to make to raise additional capital.

These and other factors are largely beyond our control, and the impact of these risks, singly or in the aggregate, may result in material adverse changes to the market price of our common stock and/or our consolidated results of operations and financial condition.

We do not expect to pay dividends in the foreseeable future.

We do not intend to declare dividends for the foreseeable future, as we anticipate that we will reinvest any future earnings in the development and growth of our business. Therefore, investors will not receive any funds unless they sell their common stock, and stockholders may be unable to sell their shares on favorable terms or at all. Investors cannot be assured of a positive return on investment or that they will not lose the entire amount of their investment in the common stock.

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Our officers, directors and principal shareholders own a controlling interest in our voting stock and investors will not have any voice in our management.

Our officers, directors and principal shareholders in the aggregate, beneficially own or control the votes of approximately 6265.976% of our outstanding common stock. As a result, these stockholders, acting together, will have the ability to control substantially all matters submitted to our stockholders for approval, including:

·	election of our board of directors;

·	removal of any of our directors;

·	amendment of our certificate of incorporation or bylaws; and

·	adoption of measures that could delay or prevent a change in control or impede a merger, takeover or other business combination involving us.

As a result of their ownership and positions, our directors, executive officers and principal shareholders collectively are able to influence all matters requiring stockholder approval, including the election of directors and approval of significant corporate transactions. In addition, sales of significant amounts of shares held by our directors, executive officers or principal shareholders, or the prospect of these sales, could adversely affect the market price of our common stock. Management's stock ownership may discourage a potential acquirer from making a tender offer or otherwise attempting to obtain control of us, which in turn could reduce our stock price or prevent our stockholders from realizing a premium over our stock price.

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Our common stock is subject to the "penny stock" rules of the SEC and the trading market in our securities is limited, which makes transactions in our stock cumbersome and may reduce the value of an investment in our stock.

The SEC has adopted Rule 15g-9 which establishes the definition of a "penny stock," for the purposes relevant to us, as any equity security that has a market price of less than $5.00 per share or with an exercise price of less than $5.00 per share, subject to certain exceptions. For any transaction involving a penny stock, unless exempt, the rules require:

·	that a broker or dealer approve a person's account for transactions in penny stocks; and

·	the broker or dealer receive from the investor a written agreement to the transaction, setting forth the identity and quantity of the penny stock to be purchased.

In order to approve a person's account for transactions in penny stocks, the broker or dealer must:

·	obtain financial information and confirm the investment experience and objectives of the person; and

·	make a reasonable determination that the transactions in penny stocks are suitable for that person and that the person has sufficient knowledge and experience in financial matters to be capable of evaluating the risks of transactions in penny stocks.

The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prescribed by the SEC relating to the penny stock market, which, in highlight form:

·	sets forth the basis on which the broker or dealer made the suitability determination; and

·	that the broker or dealer received a signed, written agreement from the investor prior to the transaction.

Generally, brokers may be less willing to execute transactions in securities subject to the "penny stock" rules. This may make it more difficult for investors to dispose of our common stock and cause a decline in the market value of our stock.

Disclosure also has to be made about the risks of investing in penny stocks in both public offerings and in secondary trading and about the commissions payable to both the broker-dealer and the registered representative, current quotations for the securities and the rights and remedies available to an investor in cases of fraud in penny stock transactions. Finally, monthly statements have to be sent disclosing recent price information for the penny stock held in the account and information on the limited market in penny stocks.

FINRA sales practice requirements may also limit a shareholder’s ability to buy and sell our stock.

In addition to the “penny stock” rules described above, FINRA has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. The FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock and have an adverse effect on the market for our shares.

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ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

ITEM 2. PROPERTIES.

Our principal executive offices are located at 218 N. Broadway, Suite 204 Tyler, Texas 75702. Our telephone number is (903) 595-4139.

The principal executive office occupies 2,200 square feet. The original lease expired in 2010 and the principal executive office is now leased on a month -to -month basis at a rate of $1,300/month.

Our field operations are conducted out of our Jefferson, Texas office at 3546 N. US Hwy. 59, Jefferson, Texas 75657, and the phone number is (903) 665-8225. ~~The~~Through ~~lease is for 5~~2014,~~300~~ ~~square~~we ~~feet~~leased ~~and~~this ~~the~~property ~~monthly~~for ~~rent is~~ $4,500 per month. The ~~office~~monthly ~~space~~cost isincluded ~~being~~5,200 ~~leased~~square onfeet aof ~~monthly~~office ~~basis. The~~space ~~monthly~~and ~~cost includes~~ surface-use rights for the storing of pipe and other field equipment in the yard. On February 1, 2015, we reduced our office space by approximately 1,300 square feet and reduced our rent to $3,750 per month.

Our oil and gas assets are located in Cass and Marion counties in northeast Texas. As of ~~March~~April 1, ~~2014~~2015, we operated 2017 wells, of which 1513 were producing. WeIn ~~recently~~2014 we drilled one new well, plugged ~~two~~and abandoned three non-producing wells, and we intend to perform work-over operations on the ~~five~~other non-producing wells.

As of April 1, 2015, our leasehold position is approximately 24,258 gross acres and 12,826 net acres of which our working interest is 7,290 acres. We hold working interests of between 25% and 80% in individual leases. Our leasing program’s primary objective is to support the planned drilling program by securing holdout leases in those units where we plan to drill over the next twelve months and renew leases that are due to expire in the units where we plan to drill. Most of our proved undeveloped acreage is subject to lease expiration if initial wells are not drilled within a specified period, generally not exceeding three years. Our intention is to renew all leases within our planned drilling zones that expire in the next three years.

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As of March 1, 2014, our leasehold position is approximately 28,697 gross acres and 17,898 net acres of which our working interest is 11,352 acres. We hold working interests of between 25% and 80% in individual leases. Our leasing program’s primary objective is to support the planned drilling program by securing holdout leases in those units where we plan to drill over the next twelve months and renew leases that are due to expire in the units where we plan to drill. Most of our proved undeveloped acreage is subject to lease expiration if initial wells are not drilled within a specified period, generally not exceeding three years. Our intention is to renew all leases within our planned drilling zones that expire in the next three years.

In addition to the operating of the wells, we own an 80% undivided interest in approximately 40 miles of a natural gas pipeline.

ITEM 3. LEGAL PROCEEDINGS.

From time to time, we may become involved in various lawsuits and legal proceedings which arise in the ordinary course of business. However, litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm our business. We are currently not aware of any such legal proceedings or claims that we believe will have, individually or in the aggregate, a material adverse effect on our business, consolidated financial condition, or operating results.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

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PART II.

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

~~MARKET~~Market ~~INFORMATION~~Information

Our common stock is currently available for quotation on the OTCQB under the symbol “PGSI.” Prior to September 23, 2013, our common stock was available for quotation on the Over-the-Counter Bulletin Board under the symbol “PGSI.”

For the periods indicated, the following table sets forth the high and low ~~bid~~closing prices per share of common stock. These prices represent inter-dealer quotations without retail markup, markdown, or commission and may not necessarily represent actual transactions.

Year Ended December 31, 2013
Year ended December 31, 2014	High		Low
	High		Low
First Quarter	$	0.85	$	0.55
First Quarter	$	1.09	$	0.54
Second Quarter	$	0.90	$	0.50
Second Quarter	$	1.03	$	0.69
Third Quarter	$	0.57	$	0.35
Third Quarter	$	0.89	$	0.55
Fourth Quarter	$	0.44	$	0.14
Fourth Quarter	$	0.70	$	0.36

Year Ended December 31, 2012
Year ended December 31, 2013	High		Low
	High		Low
First Quarter	$	1.09	$	0.54
First Quarter	$	0.84	$	0.43
Second Quarter	$	1.03	$	0.69
Second Quarter	$	1.05	$	0.60
Third Quarter	$	0.89	$	0.55
Third Quarter	$	0.95	$	0.65
Fourth Quarter	$	0.70	$	0.36
Fourth Quarter	$	0.70	$	0.46

~~HOLDERS~~Holders

As of ~~March~~April 121, ~~2014~~2015, we had approximately 8998 holders of our common stock. The number of record holders was determined from the records of our transfer agent and does not include beneficial owners of common stock whose shares are held in the names of various security brokers, dealers, and registered clearing agencies. The transfer agent of our common stock is ~~Holladay~~Pacific Stock Transfer Company, ~~2939~~4045 ~~North~~South ~~67th~~Spencer ~~Place~~Street, Suite C403, ~~Scottsdale~~Las Vegas, ~~Arizona~~Nevada ~~85251~~89119.

~~DIVIDENDS~~Dividends

We have never paid any cash dividends on our capital stock and do not anticipate paying any cash dividends on our common stock in the foreseeable future. We intend to retain future earnings to fund ongoing operations and future capital requirements of our business. Any future determination to pay cash dividends will be at the discretion of the Board and will be dependent upon our consolidated financial condition, results of operations, capital requirements, and such other factors as the Board deems relevant.

~~RECENT~~Recent ~~SALES~~Sales OFof ~~UNREGISTERED~~Unregistered ~~SECURITIES AND EQUITY PURCHASES BY THE COMPANY~~Securities

~~On October 2, 2013, we issued 50,000 to a consultant for services rendered~~None. The shares were issued in reliance on the exemption from registration afforded by Section 4(a)(2) and/or Rule 506 of Regulation D promulgated under the Securities Act of 1933, as amended (“Securities Act”).

OnEquity ~~December~~Compensation ~~20,~~Plan ~~2013, we sold in a private placement a total of 1,944,119 Units (the “Units”), to certain investors for aggregate cash proceeds of $1,749,707.~~Information

~~Each~~The ~~Unit~~following ~~had~~table asets ~~purchase~~forth ~~price~~certain ofinformation ~~$0.90~~as ~~per Unit and consisted~~ of ~~two~~ ~~(2)~~December ~~shares of common stock~~31, $02014.001 par value (the “Common Stock”) and a warrant to purchase one (1) share of common stock (the “Warrants”). The Warrants have an exercise price of $0.70 per share of Common Stock and will be exercisable for a period of five years from the date of issuance.

Plan Category	Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights		Available for Future Issuance Under Equity Compensation Plans (Excluding Shares Reflected in the First Column)

Equity compensation plans approved by shareholders		16,750,000	$	0.66		-
Equity compensation plans not approved by shareholders		-	$	-		-
Total		16,750,000	$	0.66		-

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The Units sold in the private placement were not registered under the Securities Act, or the securities laws of any state, and were offered and sold in reliance on the exemption from registration afforded by Section 4(a)(2), Rule 506 of Regulation D and Rule 903 of Regulation S promulgated under the Securities Act and corresponding provisions of state securities laws, which exempt transactions by an issuer not involving any public offering. Based on representations from the investors, the Company determined that the investors are either “accredited investors,” as such term is defined in Regulation D promulgated under the Securities Act or not a “U.S. person,” as that term is defined in Rule 902(k) of Regulation S promulgated under the Securities Act, and such investors acquired our common stock, for investment purposes for their own respective accounts and not as nominees or agents, and not with a view to the resale or distribution thereof, and that the investors understood that the shares of our common stock may not be sold or otherwise disposed of without registration under the Securities Act or an applicable exemption therefrom.

EQUITY COMPENSATION PLAN INFORMATION

The following table sets forth certain information as of December 31, 2013.

Plan Category	Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights	Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Shares Reflected in the First Column)
Equity compensation plans approved by shareholders	9,700,060	$	0.57	7,049,940
Equity compensation plans not approved by shareholders	-	$	-	-
Total	9,700,060	$	0.57	7,049,940

ITEM 6. SELECTED FINANCIAL DATA.

Not required under Regulation S-K for “smaller reporting companies.”

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Forward Looking Statements

This Management's Discussion and Analysis of Financial Condition and Results of Operations ~~include~~includes a number of forward-looking statements that reflect management's current views with respect to future events and financial performance. You can identify these statements by forward-looking words such as “may,” “will,” “expect,” “anticipate,” “believe,” “estimate” and “continue,” or similar words. Those statements include statements regarding the intent, belief or current expectations of us and the management team as well as the assumptions on which such statements are based. Prospective investors are cautioned that any such forward-looking statements are not guarantees of future performance and involve risk and uncertainties, and that actual results may differ materially from those contemplated by such forward-looking statements.

Readers are urged to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the Securities and Exchange Commission. Important factors ~~not currently~~ known to ~~management~~ us could cause actual results to differ materially from those in forward-looking statements. We undertake no obligation to update or revise forward-looking statements to reflect changed assumptions, the occurrence of unanticipated events or changes in the future operating results over time. We believe that ~~our~~its assumptions are based upon reasonable data derived from and known about our business and operations and the business and operations of the Company. No assurances are made that actual results of operations or the results of our future activities will not differ materially from ~~our~~its assumptions. Factors that could cause differences include, but are not limited to, expected market demand for ~~our~~the ~~products~~Company’s services, fluctuations in pricing for materials, and competition.

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Company Overview

We are an independent energy company engaged in the exploration for, and the production of, crude oil and natural gas. Our ~~focus~~strategy is onto ~~the~~employ ~~development~~modern ofdrilling aand ~~repeatable,~~completion ~~low-geological~~techniques ~~risk,~~to ~~high-potential~~redevelop ~~project~~formations that have been proven by historical production to be hydrocarbon reservoirs in a mature field. We are exclusively focused on the ~~active~~redevelopment of the Rodessa oilfield of East Texas. The Rodessa oil ~~and~~field ~~gas~~has ~~region. We~~to ~~currently~~date ~~hold~~produced ~~interests~~over in400 ~~properties~~million ~~located~~barrels inof ~~Cass~~oil and ~~Marion~~2.3 ~~Counties,~~trillion ~~Texas~~cubic feet of gas from over 2,000 ~~home~~producing towells. First developed in the ~~Rodessa~~ ~~oil~~1930’s, ~~field. This~~this field has historically been the domain of small independent operators and is not a legacy field for any major oil company. We have been active in the region for over a decade, and in this time, we have developed a proprietary technical database from the Rodessa oilfield’s extensive drilling history, which gives us a superior insight into the multiple proven reservoirs that are available for development. The drilling and production history of the oilfield has proven the productivity of multiple horizons, including the Rodessa, Pettit, Travis Peak, Cotton Valley, Bossier and Cotton Valley Limestone. We have a longstanding commitment to this region where mineral ownership is highly fragmented and believe that the strength of our local relationships is a critical factor in acquiring mineral leases. We currently hold interests in properties located in Cass and Marion Counties, Texas.

Our ~~business~~development 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. WeBy ~~believe~~focusing ~~that we are uniquely familiar with the history and geology of the Cornerstone Project area based~~ on ~~our~~a ~~collective~~mature ~~experience~~proven infield, ~~the~~we ~~region~~believe asthat ~~well~~we ascan ~~through~~significantly ~~our~~reduce ~~development and ownership of a large proprietary database which details~~ the ~~drilling~~geological ~~history~~risk of ~~the~~our ~~Cornerstone Project area since 1980~~projects. We plan to develop and produce reserves at low cost and will take an aggressive approach to exploiting our contiguous acreage position ~~through~~by ~~utilization~~utilizing of the latest “best in class” drilling and completion techniques. In We 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~~this ~~Cornerstone~~mature ~~Project~~oil ~~area~~field will enable us to ~~find~~develop significant oil and gas ~~reserves~~resources that were not amenable to development with the technology available to earlier developers.

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

· 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 develop 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.28

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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 project area. Most properties in the project area are held by smaller independent companies that lack the resources and expertise to develop 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.

Development of Resources in the Cornerstone Project area

~~Approximately~~Our ~~two-thirds~~acreage ofis ~~our~~located ~~net~~in a region that has historically proven highly productive. There are multiple target formations available for development on our leased acreage. isThese ~~currently~~include ~~undeveloped~~the ~~(approximately~~gas 7and condensate bearing Travis Peak,~~524~~ ~~undeveloped~~the ~~net~~oil ~~acres~~and ofgas abearing ~~total~~upper ofCotton 11Valley sands,~~352~~ ~~net~~the ~~acres~~oil asbearing ofBossier ~~March~~sands 1,and ~~2014).~~the ~~The~~oil ~~primary~~bearing ~~focus~~Cotton ofValley ~~our~~Limestone. ~~drilling~~Approximately ~~program~~70% isof toour ~~develop~~net ~~the~~leased ~~resources~~acreage ofis ~~these~~currently undeveloped ~~acres~~(approximately ~~and~~4,779 ~~subsequently~~undeveloped ~~hold~~net ~~this~~acres ~~acreage~~of ~~with~~a ~~production~~total ~~rather~~of ~~than~~7,290 tonet ~~develop~~acres ~~our~~as ~~existing~~of ~~reserves~~April on1, ~~developed acreage~~2015).

· Horizontal Wells Targeting the Bossier/Cotton Valley Limestone. Our priority is to drill horizontal wells targeting the Bossier/Cotton Valley Limestone. WeThe ~~employ~~low permeability oil bearing Bossier and Cotton Valley Limestone formations are amenable to development using the latest horizontal drilling and dynamic multi-stage fracking techniques that have proven 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-H, 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. AThe ~~jet~~production ~~pump~~rate ~~system~~subsequently ~~was~~decreased ~~initially employed to assist production~~ and ~~the~~we ~~well~~recorded ~~was~~an ~~later~~average ~~shut~~production inrate ~~for~~of a7 ~~period~~Bbl/day of 33crude ~~days~~oil ~~between~~during ~~August~~February ~~and September 2012~~2015, ~~for~~when ~~the~~production ~~installation~~was ofhampered aby ~~gas~~extreme ~~lift~~cold ~~production~~weather ~~system.~~that ~~The~~resulted ~~well~~in ~~was~~forced shut indowns ~~again~~ on ~~February~~account ~~25,~~of ~~2013, for~~ the ~~performance~~failure of athe ~~remedial~~gas ~~work-over~~lift ~~operation.~~system’s ~~The~~compression ~~well returned to production on March 19, 2013~~equipment. The ~~production~~decrease ~~rate~~in ~~initially~~the ~~stabilized at a rate of approximately 55 Bbl/day of oil and 75 MCF of gas per day. The~~ production rate ~~subsequently declined to an average of 38 Bbl/day of oil as recorded in January 2014. This decline~~ has been irregular and we have observed ~~unexpected~~several ~~surges~~instances inof ~~production.~~unexpected, ~~During~~sustained asurges ~~three day period~~ in ~~November 2013~~production, ~~production~~typically ~~surged~~resulting toin a ~~peak~~doubling of ~~83 Bbl/day from the previous average of approximately 30 Bbl/day. In early February 2014,~~ production ~~surged~~volume ~~to a peak rate of 74 Bbl/day of oil~~ over a three -day ~~period and later surged to a peak rate of 72 Bbl/day of oil over an eight day period~~periods. ~~Due to these surges, the average production of approximately 35 BB/day during February 2014 was the highest recorded production since July 2013.~~ These surges in production lead us to believe that the reservoir is capable of greater production, and that the Morse #1-H well’s production rate has been compromised by the gas lift system and/or by an obstruction in the well bore. We ~~are~~believe ~~actively~~that ~~researching an intervention and intend to perform a workover of~~ the ~~well,~~successful ~~which~~production ~~may involve the installation~~ of aoil ~~mechanical~~from ~~pump to replace~~ the ~~gas~~Morse ~~lift~~#1-H, ~~system;~~which ~~no date~~ has ~~yet~~produced ~~been~~a ~~set~~cumulative ~~for~~total ~~such~~of ~~work.~~41,793 WeBbls ~~expect~~of ~~that~~oil itto ~~would~~December ~~take~~31, ~~approximately~~2014, 30supports ~~days~~our todevelopment ~~install~~strategy ~~such~~for athe ~~mechanical~~Bossier/Cotton ~~pump~~Valley ~~system~~Limestone. We ~~believe~~have ~~that~~gained ~~the~~a ~~successful~~substantial ~~production~~amount of ~~oil~~knowledge ~~from~~and ~~the~~experience ~~Morse #1-H supports our development strategy. We have learned much~~ from the drilling, completion and production of the Morse #1-H well 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 or more frack stages to improve the well economics. We estimate that the drilling and completion costs of such wells will be approximately $7-$9 million. We are not currently capitalized to drill a program of such wells ~~to develop the Bossier/Cotton Valley Limestone~~ and are actively engaged in securing the necessary finance to fund ~~such~~ a drilling program. Weto ~~have~~develop ~~a 56% working interest in~~ the ~~Morse~~Bossier/Cotton ~~#1-H~~Valley ~~well~~Limestone.

· Vertical Wells. Our secondary priority is to drill vertical wells to develop shallower formations, such as the Travis Peak and Cotton Valley. The Haggard A & B wells, which offset the Norbord #1 discovery of 2010 inand ~~the~~were ~~Travis~~completed ~~Peak~~in 2013 and to2012, ~~recomplete~~respectively, ~~existing~~fall ~~wells~~into tothis ~~maximize~~category ~~their~~and ~~present~~have ~~value~~proven byhighly ~~utilizing~~productive aof ~~multi-zone~~gas ~~production~~and ~~technique~~condensate. In ~~March~~August ~~2012~~2014, we ~~successfully~~concluded ~~completed~~a ~~the~~participation ~~Haggard~~agreement Awith ~~well,~~Pacific ~~which~~World isEnergy an(“PWE”) ~~offset~~for the drilling of up to ~~the~~10 ~~Norbord~~wells ~~discovery~~on our leased acreage in ~~2010~~Marion County. ~~The~~On ~~Haggard~~October A1, ~~was~~2014, ~~our~~we ~~most~~spudded ~~productive~~the ~~gas~~first vertical well inof ~~2013.~~this ~~Following~~program, ~~unsuccessful~~the ~~work-over~~Huntington ~~attempts~~#4. inDrilling ~~2013~~reached ona ~~the~~final ~~Norbord~~depth #1of 9,300 ~~which~~feet, ~~ceased~~ production ~~from~~casing ~~the~~of ~~Travis~~4 ~~Peak~~½” ~~formation~~was inset ~~September~~and ~~2012,~~cemented weat ~~plugged~~9,300 feet and ~~abandoned~~the drilling rig was released on October 27, 2014. Analysis of the well log identified in ~~February~~excess ~~2014~~of 175' of gross pay over multiple Cotton Valley and Travis Peak zones. WeHaving ~~also~~now ~~decided~~analyzed tothe ~~abandon~~drilling results, we are discussing the ~~Swamp~~completion ~~Fox~~procedure for this well with PWE and ~~plugged~~plan itto incomplete ~~February~~this ~~2014~~well within the first half of 2015.

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Consolidated Results of Operations

Year Ended December 31, ~~2013~~2014 Compared to Year Ended December 31, ~~2012~~2013

Summarized Consolidated Results of Operations

	2013			2012			Increase (Decrease)
	2014			2013			Increase (Decrease)
Total revenues	$	1,~~876~~999,~~629~~955		$	1,~~546~~876,~~861~~629		$	~~329~~123,~~768~~326
Total operating expenses		47,~~806~~625,~~270~~711			74,~~401~~806,~~071~~270			(2,~~594~~819,~~801~~441	)
Loss from operations		(25,~~929~~625,~~641~~756	)		(52,~~854~~929,~~210~~641	)		(2,~~924~~696,~~569~~115	)
Total other expenses		(774,892	)		(665,567	)		109,325
Total other expenses, net		(3,284,851	)		(774,892	)		(2,509,959	)
Loss from operations before income tax expense		(3,704,533	)		(6,519,777	)		(2,815,244	)
Loss before income tax expense		(8,910,607	)		(3,704,533	)		(5,206,074	)
Income tax expense		-			~~(3,515~~-	)		~~(3,515~~-	)
Net loss	$	(38,~~704~~910,~~533~~607	)	$	(63,~~523~~704,~~292~~533	)	$	(25,~~818~~206,~~759~~074	)

Revenues: Total revenues for the year ended December 31, 2014 totaled $1,999,955 compared to $1,876,629 for the year ended December 31, 2013. Oil revenue for the year ended December 31, 2014 was $763,073 compared to $1,015,373 for the year ended December 31, 2013. This decrease of $252,300 represented a 25% decrease and was a consequence of a 17% decline in sales volumes and a 9% decrease in the realized oil sales price from $99.84 per barrel for the year ended December 31, 2013 to $90.59 per barrel for the year ended December 31, 2014. The primary reason for the decline in sales volume during the year ended December 31, 2014 was a decrease in production from the Morse #1-H well and the Norbord #1 well, with the Norbord #1 well having been plugged and abandoned in February 2014.

Gas revenue increased 54% from $613,432 for the year ended December 31, 2013 to $941,684 for the year ended December 31, 2014. This increase of $328,252 was primarily a result of a 36% increase in sales volume from 2013 to 2014 and a 13% increase in the realized sales price. We received a realized sales price of $4.16 per MCF for the year ended December 31, 2014 compared to $3.68 per MCF for the year ended December 31, 2013. The increase in the sales volume during the year ended December 31, 2014 were primarily a result of increases of gas production revenue of:

·	$150,680 from the Haggard A well, primarily due to the increase in our interest in the well following the completion of title work during the second quarter of 2014; and

·	$183,150 from the Haggard B well due to the buyout in May 2014 of one of our investor’s working interest in this well.

Transportation and gathering revenue increased by $61,350 from $206,041 for the year ended December 31, 2013 to $267,391 for the year ended December 31, 2014. The increase was primarily a consequence of increased pipeline volumes and charges per MCF. Condensate and skim oil sales amounted to $27,807 for the year ended December 31, 2014 compared to $41,782 for the year ended December 31, 2013. Condensate and skim oil are by-products from drilling and are only sold when a sufficient amount has been collected, resulting in fluctuations from period to period.

Expenses: Total operating expenses for the year ended December 31, 2014 were $7,625,711, compared to $4,806,270 for the year ended December 31, 2013, resulting in a total increase of $2,819,441. This change was primarily a result of a large increase in general and administrative expenses resulting from non-cash stock-based compensation expenses incurred during the year ended December 31, 2014.

General and Administrative Expenses: There was a $2,806,310 increase in general and administrative expenses to $5,880,900 for the year ended December 31, 2014 from $3,074,590 for the year ended December 31, 2013. The primary reason for the increase was an increase of $2,698,163 in non-cash stock-based compensation expense. On January 30, 2014, our board of directors issued stock options to purchase 7,049,940 shares of common stock at an exercise price of $0.79 per share with a five year term to employees and directors to reward their efforts and to incentivize their performance in creating shareholder value. These awards generated a non-cash stock-based compensation expense of $2,381,979. Further non-cash stock-based compensation expense of $578,255 was incurred in the first quarter of 2014 on the extension of the expiration date of options. In 2013, stock-based compensation expense was limited to $655,181 in charges related to the vesting of options granted to the CFO in October 2012. The vesting of these options generated expense of $393,110 in 2014.

In addition, investor relations consulting fees of $302,500 were incurred during the year ended December 31, 2014, whereas only $35,500 of such fees was incurred during the year ended December 31, 2013. We engaged an investor relations firm in late March 2014 to assist us with the implementation and maintenance of ongoing programs to increase the investment community’s awareness of our activities and to stimulate their interest in our company.

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~~Revenues~~· Lease Operating Expense: Total ~~revenues~~lease operating expenses for the year ended December 31, ~~2013~~2014 ~~totaled~~were $1887,~~876,629~~041 compared to $1,~~546~~074,~~861~~466 for the year ended December 31, ~~2012~~2013. ~~Oil~~ ~~revenue~~The ~~for~~decrease ~~the~~of ~~year~~$187,425 ~~ended~~is ~~December~~primarily ~~31,~~a ~~2013~~result ~~was~~of ~~$1,015,398~~a ~~compared~~decline toof $1273,~~067,113~~282 ~~for~~in ~~the~~lease ~~year~~operating ~~ended~~expenses ~~December~~for ~~31,~~the ~~2012.~~Morse ~~This~~#1-H ~~decrease~~well, ofwhich ~~$51,715~~was ~~represented~~largely a 5%consequence ~~decrease~~of the decline in ~~oil~~production ~~revenue~~volumes. ~~and~~Following ~~was~~the aplugging ~~consequence~~and abandonment of athe ~~12%~~Norbord ~~decline~~well in ~~sales~~2014, ~~volumes~~its ~~offset~~lease byoperating anexpense 8%decreased ~~increase~~by $65,835 in 2014 compared to 2013. With the ~~realized~~increased ~~oil~~gas ~~sales~~production ~~price~~volumes from the Haggard A and B wells, their lease operating expense increased by $9122,275 and $68,865, respectively, in 2014 compared to 2013.32 ~~per~~We ~~barrel~~acquired ~~for~~seven wells, including the ~~year~~Cass ~~ended~~County ~~December~~Fee 31#1, from a third party in 2012. toThe ~~$99~~Cass County Fee #1 was originally completed in 1972, and by 2014, its production had declined below an economic rate.84 ~~per~~During ~~barrel~~2014, ~~for~~we performed a work-over of the ~~year~~Cass ~~ended~~County ~~December~~Fee 31#1, ~~2013~~returning it to an economic rate of production. , The ~~primary~~cost ~~reasons~~of ~~for~~ the ~~fluctuation~~work-over operation resulted in ~~sales~~an ~~volume~~increase ~~during~~in the ~~year~~well’s ~~ended~~lease ~~December~~operating 31expenses of $47,694 ~~2013~~in ~~were:~~2014 compared to 2013.

· ~~The~~Depletion ~~Morse~~and ~~#1-H~~Depreciation Expense: Total depletion and depreciation for the year ended December 31, 2014 was ~~shut~~$601,865, incompared to $470,739 for ~~three~~the ~~weeks~~year ~~during~~ended December 31, 2013. ~~while~~The aincrease ~~workover~~of $131,126 was ~~performed~~primarily a consequence of increased gross production, which resulted from an increase in our share of production due to the completion of title work on the Haggard A well and the May 2014 buyout agreement of an investor’s working interest in the Haggard B well. In addition to the production increase of 22%, the total amount of reserves fell by approximately 26% in 2014 compared to 2013, resulting in a ~~net~~64% increase in the depreciation, depletion and amortization (“DD&A”) rate, and the depreciable base fell by 18%, primarily as a result of the reduction in future development costs following the reduction in reserves. The compounded result of an increase of 64% in the DD&A rate and a decrease of ~~$179,585~~18% in ~~revenue;~~the depreciable base was a 34% increase in DD&A charges.

·Other ~~The~~Income ~~Haggard~~(Expenses): Total Aother ~~well~~expenses ~~did~~for ~~not~~the ~~have~~year ~~any~~ended ~~production~~December ~~during~~31, 2014 were $3,284,851, compared to $774,892 for the year ended December 31, ~~2012~~2013, ~~but~~resulting ~~generated~~in an increase of $882,~~811~~509,959. The inprimary ~~revenue~~reason for the increase was a warrant modification expense of $2,642,266 incurred during the year ended December 31, 2014, whereas no such expense was incurred during the same period in 2013;. This ~~and~~expense was incurred in connection with a warrant modification offer to investors that closed on March 31, 2014. Certain investors agreed to modify the terms of their warrants, whereby the expiration date was extended for three years in exchange for agreeing to increase the exercise price.

·Net ~~The~~Loss: As ~~Haggard~~a Bresult ~~well~~of ~~only had production in~~ the ~~last~~above ~~quarter~~described ofrevenues ~~2012~~and ~~which~~expenses, ~~generated~~we ~~$16,027~~incurred ina ~~revenue~~net ~~but~~loss ~~had~~of $558,~~394~~910,607 in ~~revenue during~~ the year ended December 31, ~~2013~~2014, ~~resulting~~compared into ana ~~increase~~net loss of $393,~~367~~704,533 in the year ended December 31, 2013.

~~Gas~~Liquidity revenue increased 110% from $292,412 for the year ended December 31, 2012 to $613,408 for the year ended December 31, 2013. This increase was primarily a result of a 51% increase in sales volume from 2012 to 2013 and aCapital 38% increase in the realized sales price. We received a realized sales price of $3.68 per MCF for the year ended December 31, 2013 compared to $2.67 per MCF for the year ended December 31, 2012. Gas sales of $251,464 from the Haggard A and $75,874 from the Haggard B accounted for the majority of the increase of $320,996 for the year ended December 31, 2013, which were partially offset from the loss of gas sales of $75,990 from the Norbord during the year ended December 31, 2012, as that well was abandoned in early 2013.Resources

~~Transportation~~We ~~and~~held ~~gathering~~$373,506 ~~revenue~~in ~~increased~~cash ~~$61~~at December 31,~~348~~ ~~from~~2014, which when netted against an overdraft of $~~144~~5,~~693~~673, ~~for~~gave ~~the~~us ~~year~~net ~~ended~~cash ~~December~~of 31$367,833. ~~2012~~By comparison, towe held $~~206~~2,~~041~~467,761 ~~for~~in ~~the~~cash ~~year~~at ~~ended~~ December 31, 2013~~. The~~, ~~increase~~and ~~was~~net ~~primarily~~cash aof ~~consequence~~$2,212,133 after an overdraft of ~~increased~~$255,628 ~~volumes~~was ~~transported~~deducted. ~~Condensate~~The ~~and~~overall ~~skim~~year-on-year ~~oil~~decrease in cash was ~~$41,782~~a consequence of cash used to fund operating expenses and ~~$42,643~~cash used for ~~the~~investment, ~~year~~which ~~ended~~exceeded ~~December~~cash ~~31,~~from ~~2013~~operating revenues and ~~December~~cash ~~31,~~generated ~~2012,~~from ~~respectively~~financing activities.

~~Expenses: Total~~Going ~~operating~~Concern expenses for the year ended December 31, 2013 were $4,806,270, compared to $7,401,071 for the year ended December 31, 2012, resulting in a total decrease of $2,594,801. This change was primarily a result of a large decrease in general and administrative expenses offset by increases in lease operating expenses, pipeline operating expenses and depletion and depreciation.Consideration

·In ~~General~~their ~~and~~report ~~Administrative~~dated ~~Expenses:~~April ~~There was a $~~3,~~121~~ 2015,~~582~~ ~~decrease~~our inindependent ~~general~~registered ~~and~~public ~~administrative~~accounting ~~expenses~~firm tostated ~~$3,074,590~~that our financial statements for the year ended December 31, ~~2013~~2014 ~~from~~were ~~$6,196,172~~prepared ~~for~~assuming ~~the~~that ~~year~~we ~~ended~~would ~~December~~continue ~~31,~~as ~~2012.~~a ~~The~~going ~~primary~~concern. ~~reason~~Our ~~for~~ability ~~the~~to ~~decrease~~continue ~~was~~as ~~stock-based~~a ~~compensation~~going ofconcern ~~$2,719,888~~is ~~incurred~~an ~~during~~issue ~~the~~raised ~~year~~due ~~ended~~to ~~December~~incurring ~~31,~~operating ~~2012,~~losses ~~whereas~~for ~~there~~several ~~was~~years ~~only~~and ~~$655,181~~having ~~stock-based~~negative ~~compensation~~cash ~~incurred~~flows infrom ~~the~~operations. In ~~2013~~addition, awe ~~decrease~~have an accumulated deficit of $237,~~064~~015,~~707.~~151 ~~The~~as ~~compensation~~of ~~resulted~~December ~~from~~31, ~~the~~2014 ~~issuance~~and ofrequire ~~stock~~additional ~~options~~financing to ~~selected~~fund ~~employees,~~future ~~executives,~~operations. Our ~~directors,~~financial ~~and~~statements ~~consultants~~contain additional note disclosures describing the circumstances that led to this disclosure.

InOur ~~addition,~~operations ~~investor~~have ~~relations~~not ~~consulting~~been ~~fees~~sufficient ~~decreased~~to ~~$1,021,970~~generate cash flow to ~~$35,500~~fund ~~for~~operations ~~the~~and ~~year~~we ~~ended~~have ~~December~~financed ~~31,~~our ~~2013,~~activities ~~due~~using toequity ~~contracts~~and wedebt ~~engaged~~financings inand ~~for~~drilling ~~2012~~participations. ~~with~~Our ~~companies~~cash toflow ~~assist~~from usoperations ~~with~~is sensitive to the ~~implementation~~prices ~~and~~paid ~~maintenance~~for ofour ~~ongoing~~oil ~~programs~~and tonatural ~~increase~~gas ~~the~~as ~~investment~~well ~~community’s~~as ~~awareness~~to the quantities of ~~our~~oil ~~activities,~~and ~~stimulate~~natural ~~their~~gas ~~interest~~we insell. Our usability ~~and~~to ~~assist~~continue ~~with~~as ~~our~~a ~~press~~going ~~release~~concern ~~production~~is ~~and~~subject ~~dissemination. These~~to ~~contracts~~our ~~were~~ability ~~not~~to ~~renewed~~obtain innecessary ~~2013.~~funding Infrom ~~addition~~outside sources, ~~advertising~~including ~~and~~obtaining ~~marketing~~additional ~~costs~~funding ~~decreased~~from ~~$226,598~~the tosale ~~$86,170~~of ~~for~~our ~~the~~securities ~~year~~or ~~ended~~obtaining ~~December~~loans 31from various financial institutions, ~~2013~~where ~~due~~possible. toOur ~~various~~continued ~~contracts~~net ~~held~~operating losses increase the difficulty in ~~2012~~meeting ~~with~~such ~~companies~~goals ~~for~~and ~~investor~~there ~~relations~~can be no assurances that ~~were~~such ~~not~~methods ~~renewed~~will inprove ~~2013~~successful. While ~~These~~we ~~were~~continually ~~offset~~look byfor anadditional ~~increase~~financing ~~of $171~~sources,~~173~~ in ~~salaries~~the ~~and~~current ~~wages~~economic ~~during~~environment, the ~~year~~procurement ~~ended~~of ~~December~~outside ~~31,~~funding ~~2013,~~is ~~compared~~difficult toand ~~the~~there ~~same~~can ~~period~~be inno ~~2012,~~assurance ~~due~~that tosuch ~~the~~financing ~~engagement~~will ofbe ~~the~~available ~~chief~~on ~~financial~~terms ~~officer~~acceptable into ~~October~~us, ~~2012~~if at all.

· Lease Operating Expense: Total lease operating expenses for the year ended December 31, 2013 were $1,074,466 compared to $647,749 for the year ended December 31, 2013. The increase of $426,717 is a result of: (1) $153,063 in increased lease operating expenses for the Morse #1-H well, which was in production for the full year in 2013 (except for a brief three week period for workover performed) compared to approximately four months of production during 2012; (2) $133,290 in lease operating expenses for the Haggard A, which commenced production in the second quarter of 2013 and incurred no lease operating expense in 2012; (3) the purchase of seven wells in June 2012, which resulted in an increase of $62,696 in lease operating expenses for the year ended December 31, 2013 compared to lease operating expenses incurred for only six months during the year ended December 31, 2012; (4) an increase of $36,352 in lease operating expenses for the Haggard B, which commenced production in the second quarter of 2012 and incurred lease operating expense for the full year during 2013; and (5) an increase of $26,385 in lease operating expenses for the Norbord well following an increase in our share of lease operating expenses from 25% in the year ended December 31, 2012 to 80% in the year ended December 31, 2013.

· Depletion and Depreciation Expense: Total depletion and depreciation for the year ended December 31, 2012 was $427,701, compared to $470,739 for the year ended December 31, 2013. The increase of $43,038 was due to the addition of new wells and development costs.

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Other Income (Expenses): Total other expenses for the year ended December 31, 2013 was $774,892, compared to $665,567 for the year ended December 31, 2012, resulting in an increase of $109,325. The primary reason for the increase was a non-cash gain from the change in fair value of the derivative liability of $88,868 recognized in the year ended December 31, 2012. The 2007 derivative warrants expired in December 2012 eliminating the associated derivative warrant liability.

Income Tax Expense: During the year ended December 31, 2012, we recognized a net income tax expense of $3,515 for state franchise taxes, whereas no such expense was recorded in the year ended December 31, 2013.

Net Loss: As a result of the above described revenues and expenses, we incurred a net loss of $3,704,533 in the year ended December 31, 2013, compared to a net loss of $6,523,292 in the year ended December 31, 2012.

Liquidity and Capital Resources

We held $2,467,761 in cash at December 31, 2013, made up of a majority of our cash accounts. However, at December 31, 2013, several cash accounts had an overdraft that totaled $255,628 resulting in net cash of $2,212,133. We held $1,421,198 in cash at December 31, 2012, which when netted against the overdrafts of $17,795, resulted in a net cash of $1,403,403. The overall increase in cash was due to net funds raised from the sale of stock and cash generated from operating activities which exceeded cash used in the investing activities, which included purchases of oil and gas mineral leases and well equipment.

Cash Flows

The following table summarizes our cash flows for the years ended December 31:

	2013			2012
	2014			2013
Total cash provided by (used in):
Operating activities	$	~~582~~(1,~~972~~414,403	)	$	(2582,~~746,312~~972	)
Investing activities		(1,~~770~~110,~~162~~919	)		(81,~~282~~770,~~697~~162	)
Financing activities		2431,~~233,753~~067			52,~~700~~233,~~839~~753
Increase (decrease) in cash and cash equivalents	$	1(2,~~046~~094,~~563~~255	)	$	(51,~~328~~046,~~170~~563	)

Cash Provided by (Used in) Operating Activities: For the year ended December 31, ~~2013~~2014, cash ~~provided~~used byin operating activities was $~~582~~1,~~972~~414,403, compared to $2582,~~746,312~~972 ~~used~~of incash generated by operating activities for the year ended December 31, ~~2012~~2013, resulting in ana ~~increase~~decrease of cash provided by operations of $31,~~329~~997,~~284~~375.

The net loss of $68,~~523~~910,~~292~~607 for the year ended December 31, ~~2012,~~2014 ~~decreased~~was byan increase of $25,~~818~~206,~~759~~074 tofrom $3,704,533 for the year ended December 31, 2013. Non-cash income and expense ~~decreased~~increased ~~$2,945,567~~to ~~from~~ $46,~~274~~829,~~852~~805 for the year ended December 31, ~~2012~~2014 tofrom $1,329,285 for the year ended December 31, 2013.

Non-cash expense for stock-based compensation ~~decreased~~increased by $2,~~064~~698,~~707~~163, tofrom $655,181 incurred during the year ended December 31, 2013, ~~from~~to $23,~~719~~353,~~888~~344 incurred during the year ended December 31, ~~2012~~2014. ~~This~~On ~~compensation~~January ~~resulted~~30, ~~from~~2014, ~~the~~our ~~issuance~~board of directors issued stock options to ~~selected~~purchase ~~employees~~7,049,940 ~~executives~~shares ~~and~~of ~~directors~~common asstock ~~incentive~~at ~~for~~an ~~continuing~~exercise ~~our~~price ~~development~~of $0.79 ~~There~~per ~~was~~share with a ~~decrease~~five ofyear ~~$860,000~~term into ~~non-cash~~employees ~~expense~~and ~~for~~directors ~~stock~~to ~~issued~~reward their efforts and to ~~consultants~~incentivize ~~for~~their ~~the~~performance ~~year~~in ~~ended~~creating ~~December~~shareholder ~~31,~~value. These ~~2013~~awards togenerated ~~$35,500,~~non-cash ~~compared~~stock-based tocompensation expense of $~~895~~2,~~500~~381,979. ~~for~~Further ~~the~~non-cash ~~year~~stock-based ~~ended~~compensation ~~December~~expense 31of $578,255 ~~2012~~was ~~due~~incurred toin the ~~various~~first ~~contracts~~quarter in2014 ~~2012~~on ~~that~~the ~~were~~extension ~~terminated~~of orthe ~~not~~expiration ~~renewed~~date inof ~~2013~~stock options. ~~The~~Stock-based ~~change~~compensation expense of $393,110 was recorded in ~~fair~~2014 ~~value~~to ofrecognize the ~~warrant~~vesting ~~derivative~~of ~~liability~~options ~~for~~granted to the ~~year~~CFO ~~ended~~in ~~December~~October ~~31,~~2012. ~~2013~~There was an increase of $~~-0-~~162,750 ~~compared~~in to non-cash ~~income~~expense offor ~~$88,868~~stock issued to consultants for the year ended December 31, ~~2012. Both~~2014, ~~the~~from ~~warrant~~$35,500 ~~derivative~~for ~~liability and~~ the ~~change~~year inended ~~their~~December ~~fair~~31, ~~value~~2013 ~~were~~to $~~-0-~~198,250, ~~for 2013~~ due to the ~~expiration~~engagement of ~~the~~an ~~associated~~investor ~~warrants~~relations ~~in December 2012~~firm. There was aan ~~decrease~~increase in warrant modification expense of $~~160~~2,~~432~~508,164, tofrom $134,102 for the year ended December 31, 2013, ~~compared~~ to $~~294~~2,~~534~~642,266 for the year ended December 31, ~~2012~~2014, ~~due~~as toa result of the ~~expiration~~modification of investor warrants. In the first quarter of 2014, we offered to modify warrants held by investors. ~~Depletion~~The modification offer increased the exercise prices and extended the term of their warrants by three years. In 2013, ~~depreciation~~modification expense was limited to $134,102 ~~and~~from ~~accretion~~the issuance of warrants to purchase 645,968 shares of common stock. DD&A expense increased by $50132,~~174~~205, to $~~504~~636,~~248~~453 for the year ended December 31, ~~2013~~2014, primarily as a consequence of increased production and a reduction in our estimated reserves.

Operating assets ~~decreased~~increased by $170,~~606,568~~429 for the year ended December 31, ~~2013~~2014, compared to ana ~~increase~~decrease ofby $1,~~464~~606,~~032~~568 for the year ended December 31, ~~2012~~2013, resulting in a ~~change~~decrease of $31,~~070~~676,~~600~~997 in cash flow. $21,~~472~~278,~~789~~436 of this ~~change~~decrease isresulted ~~the~~from ~~result~~a decrease of ~~related party receivables decreasing~~ $1,269,781 in related party receivables for the year ended December 31, 2013, compared to an increase of $18,~~203,008~~655 for the year ended December 31, ~~2012~~2014. Joint interest billings receivable decreased $233,421 infor the year ended December 31, 2013, ~~and~~compared ~~increased~~to a decrease of $~~187~~28,~~911~~091 infor the year ended December 31, ~~2012~~2014, resulting in a ~~change~~decrease ofin ~~approximately~~cash flow of $~~421~~205,~~332~~330. The ~~decrease~~accounts inreceivable, ~~these~~related ~~receivables~~parties ~~was~~balance ~~due~~increased inby ~~part~~$13,418 tofor ~~payments received and~~ the ~~netting of revenues from working interest owners during the~~ year ended December 31, ~~2013. In addition~~2014, ~~there~~which was asimilar ~~substantial~~to ~~amount of drilling and completion work expenses on~~ the ~~Morse #1-H well during 2012 which resulted in an~~ increase ~~in receivables~~ of $113,~~390,919,~~582 ~~whereas with less drilling activity~~ in 2013~~, the receivables due from working interest partners decreased~~. ~~Trade~~Other ~~accounts~~current ~~receivable~~assets decreased by $~~103~~8,~~988~~755 infor ~~2013,~~the ~~whereas~~year ~~they~~ended ~~increased~~December ~~by $99~~31,~~180~~ in2014 ~~2012,~~compared ~~resulting~~to ina andecrease ~~increase in cash flow~~ of $~~203~~12,~~168~~960 in 2013. ~~The remaining changes in operating assets of approximately $26,689 consisted of changes in accounts receivable, related parties and other assets.~~

Operating liabilities increased by $1,351,652 for the year ended December 31, 2013, compared to an increase of $736,828 for the year ended December 31, 2014, resulting in a decrease in cash flow of $614,824. The accounts payable balance declined by $19,194 for the year ended December 31, 2014, compared to an increase by $45,592 for 2013, resulting in a decrease in cash flow of $64,786. Following the completion of legal title work on the Haggard A property in the second quarter of 2014, we distributed revenue that had been previously held in suspense, thus decreasing the revenue payable balance. This accounts for the majority of the decrease in the revenue payable balance of $391,461 for the year ended December 31, 2014 compared to an increase of $160,877 for the year ended December 31, 2013, resulting in a decrease in cash flow of $552,338. The remaining changes in other operating liabilities resulted in an increase in cash flow $2,300 and consisted of minor changes in accounts payable, related parties, liquidated damages payable and other payables.

Cash Used in Investing Activities: For the year ended December 31, 2014, cash used in investing activities was $1,110,919, compared to $1,770,162 for the year ended December 31, 2013, resulting in an increase in cash flow of $659,243. We invested $1,070,431 in 2014 for the purchase and renewal of mineral leases, compared to $1,758,160 spent in 2013, resulting in an increase in cash flow of $687,729. In addition, there was $40,383 spent on the purchases of property and equipment during the year ended December 31, 2014, compared to $11,892 in purchases during the year ended December 31, 2013, resulting in a decrease of $28,491 cash flow.

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~~Operating~~Cash ~~liabilities~~Provided ~~increased~~ by ~~$1,351,652~~Financing ~~for~~Activities: For the year ended December 31, 2013, ~~compared~~cash toprovided anby ~~increase~~financing ofactivities totaled $~~966~~2,~~160~~233,753, compared to $431,067 for the year ended December 31, ~~2012~~2014, resulting in a ~~change~~decrease of $~~385~~1,~~492~~802,686 in cash flow. ~~Accounts~~ ~~payable~~In ~~increased~~the byyear ~~$45,592~~ended inDecember ~~2013~~31, ~~whereas~~2014, itwe ~~had~~received ~~declined~~ $~~392~~694,~~833~~900 in ~~2012,~~net ~~resulting~~proceeds infrom anthe ~~increase~~sale of ~~$438,425. This~~common ~~increase~~stock ~~was~~and ~~related~~units toof ~~the~~common ~~workover~~stock ~~expenses~~and onwarrants, ~~the~~compared ~~Morse~~to #$1-H,999,231 ~~Norbord~~received ~~and~~in ~~Haggard~~the Byear ~~wells~~ended ~~incurred~~December ~~during~~31, 2013. The ~~changes~~remaining change in ~~liquidated~~cash ~~damages~~provided ~~increased~~by ~~$180,118,~~financing ~~from~~activities ~~a decrease of $173,486~~ for the year ended December 31, ~~2012~~2014 towas anprimarily ~~increase~~a result of ~~$6,632~~changes ~~for~~in the ~~year~~cash ~~ended~~overdraft. toThere ~~December~~was ~~31,~~a ~~2012~~$249,955 ~~which~~decrease ~~was due to modifications to warrant agreements~~ in ~~2012. Revenue~~our ~~payable~~cash ~~increased~~overdrafts ~~$160,877~~ for the year ended December 31, ~~2013~~2014, acompared ~~decrease~~to an increase of $~~213~~237,~~679,~~833 ~~compared~~in toour ~~the~~cash ~~$374,556~~overdrafts ~~increase~~for ~~during~~ the year ended December 31, ~~2012. The~~2013, ~~majority~~resulting ofin ~~this~~a decrease ~~was due to the release of monies during 2013 for amounts held~~ in ~~legal~~financing ~~suspense~~cash ~~for~~flow ~~royalty~~required ~~owners~~to ~~pending~~cover ~~completion~~the ofCompany’s ~~title~~cash ~~work~~overdrafts ~~and division orders. The remaining changes in other operating liabilities~~ of ~~approximately~~ $19487,~~370 consisted of changes in accounts payable, related parties and other payables~~788.

Cash Used in Investing Activities: For the year ended December 31, 2013, cash used in investing activities was $1,770,162, compared to $8,282,697 for the year ended December 31, 2012, resulting in a decrease of $6,512,535. We spent $8,037,047 on lease and well equipment, and intangible drilling and completion costs for work done on the Haggard A, Haggard B, and Morse #1-H wells during the year ended December 31, 2012, compared to $1,758,160 spent in 2013 on the completion of the Haggard B and the purchase of mineral leases, resulting in a decrease of $6,278,887. In addition, there was $245,485 spent on the purchases of property and equipment during the year ended December 31, 2012, compared to $11,892 in purchases during the year ended December 31, 2013, resulting in a decrease of $233,593.

Cash Provided by Financing Activities: For the year ended December 31, 2013, cash provided by financing activities totaled $2,233,753 compared to $5,700,839 for the year ended December 31, 2012, resulting in a decrease of $3,467,086. 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 $1,999,231 in the year ended December 31, 2013. The remaining change in cash provided by financing activities for the year ended December 31, 2013 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 an increase of $237,833 in our cash overdrafts for the year ended December 31, 2013, resulting in an increase of $384,398.

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.

We expect that additional funds raised from future financing activities will be ~~needed~~required to finance our operations for the next twelve months. The extent of our drilling program in ~~2014~~2015 is dependent on our ability to raise additional capital and our participation partner providing funding as required. 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.

~~December 2013 -~~ February 2014 Financing

In ~~December~~February ~~2013~~2014, we sold ~~in a private placement a total of 1~~781,~~999,674~~000 units, each unit consisting of two shares of common stock and a five-year warrant to purchase one share of common stock at an exercise price of $0.70 per share, for an aggregate purchase price of $~~1,799,707. In February 2014, we sold 781,000 additional units for an aggregate purchase price of $~~702,900. Aggregate offering expenses for the private placement totaled $538,~~475~~000.

In connection with the financing, we granted each purchaser registration rights. We are 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.

September 2013 Financing

In September 2013, we sold in a private placement a total of 250,000 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 $250,000. Offering expenses for the private placement totaled $5,000.

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.

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First Quarter 2015 Financing

In January 2015, we entered into securities purchase agreements (the “Securities Purchase Agreement”) with certain accredited investors (“Investors”) whereby we issued and sold to the Investors 12% Senior Secured Convertible Notes (“Notes”) in the aggregate amount of $875,000 and warrants (“Warrants”) to purchase up to 2,430,555 shares of our common stock. Pursuant to the Securities Purchase Agreement, we had the right, until February 23, 2015 (the “Additional Investment Period”), the sell up to an additional $625,000 of Notes and Warrants, on the same terms and conditions (the “Additional Securities”).

To secure our obligations under the Notes, we granted the Investors a security interest in certain assets of PERC pursuant to a Deed of Trust, Mortgage, Security Agreement, Financing Statement and Assignment of Production, as amended (the “Security Agreement”). In addition, pursuant to a guarantee (the “Guarantee”), PERC agreed to guarantee the punctual payment, as and when due and payable, of all amounts owed by us in respect of the Securities Purchase Agreement, the Notes and the other transaction documents executed in connection with the Securities Purchase Agreement. As well, we granted the Investors certain registration rights pursuant to a registration rights agreement, pursuant to which we are obligated to file a registration statement registering for resale the common stock issuable upon conversion of the Notes and exercise of the Warrants no later than May 9, 2015 (the “Registration Rights Agreement”).

On March 27, 2015, we entered into an omnibus amendment agreement (the “Amendment”) with the Investors pursuant to which, among other things:

·	We and the Investors amended the Securities Purchase Agreement to extend the Additional Investment Period until March 31, 2015, to increase the Warrant ratio from 33% to 100% and allowed for up to $1 million of Additional Securities to be sold;

We and the Investors amended the Notes to increase the minimum conversion price from $0.05 to $0.09, to require payments (including prepayments) to principal and interest to be on a pro rata basis, to provide for additional consideration to the Investors upon our failure to timely process conversion requests, and to increase the maximum beneficial ownership limitation from 9.99% to 19.99%;

·	We and the Investors amended the Warrants to provide for cashless exercise at any time, to increase the maximum beneficial ownership limitation from 9.99% to 19.99%, and to provide for additional consideration to the Investors upon our failure to timely process exercise notices;

·	We and the Investors amended the Registration Rights Agreement to clarify the liquidated damages due upon a default by us; and

·	We issued all the Investors additional Warrants (the “Consideration Warrants”) to purchase 4,861,116 shares of common stock, so that the Warrants, together with the Consideration Warrants, equaled the new Warrant ratio of 100%.

On March 27, 2015, we entered into a securities purchase agreement with an accredited investor, pursuant to which we issued and sold to the investor a $1,000,000 Note and Warrants to purchase 8,333,334 shares of common stock (the “Subsequent Investment”). In connection therewith, the Guarantee was amended and restated to include the Subsequent Investment and we covenanted to file an amendment to the Security Agreement to include the Subsequent Investment. To date, in connection with the offering, we sold Notes in the aggregate principal amount of $1,875,000 and Warrants (including Consideration Warrants) to purchase 15,625,005 shares of common stock, resulting in net proceeds of approximately $1.78 million.

The Notes are due upon written demand of Investors holding a majority in interest of outstanding Notes, provided, however, that such demand cannot be made prior to January 9, 2016 and will bear interest at the rate of 12% per annum.

The Notes are convertible, in whole or in part, into shares of our common stock at the option of the investor, at the lower of (i) $0.12 or (ii) the higher of (x) $0.09 or (y) the volume weighted average price of our common stock for the 10 trading days immediately preceding the date of conversion, subject to adjustment upon certain events, as set forth in the Note.

We have the right, at any time after the date that the Registration Statement is declared effective, to redeem some or all of the outstanding Notes, upon 30 days prior written notice. If the Notes are redeemed prior to the first anniversary of issuance, the redemption price shall equal 110% of the amount of principal and interest being redeemed.

The Warrants are exercisable, at the option of the investor, for seven (7) years after issuance, in whole or in part, at an exercise price equal to the lower of (i) $0.132 or (ii) the higher of (x) $0.06 or (y) 110% of the volume weighted average price of our common stock for the 10 trading days immediately preceding the date of exercise, subject to adjustment upon certain events, as set forth in the Warrant.

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Off Balance Sheet Arrangements

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 that extend the useful lives are capitalized. Expenditures for normal maintenance and repairs are expensed as incurred. Upon the sale or abandonment, the cost of the equipment and related accumulated depreciation are removed from the accounts and any gains or losses thereon are recognized in the operating results of the respective period.

Oil and Gas Properties

We use the full-cost method of accounting for our oil and gas producing activities, which are all located in Texas. Accordingly, all costs associated with the acquisition, exploration, and development of oil and gas reserves, including directly-related overhead costs, are capitalized.

All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the units-of-production method using estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment will be added to the capitalized costs to be amortized.

In addition, the capitalized costs are subject to a “ceiling test,” which limits such costs to the aggregate of the “estimated present value,” discounted at a ten percent interest rate, of future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties and less the income tax effects related to the properties.

Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in the operating results of the respective period.

~~Derivative~~Stock-based ~~Instruments~~Compensation

~~For~~We ~~derivative~~have ~~instruments that are~~ accounted for asstock-based ~~liabilities,~~compensation under the ~~derivative~~provisions ~~instrument~~of isFASB ~~initially~~ASC ~~recorded~~Topic at718-10, ~~its~~Compensation-Stock ~~fair~~Compensation. We ~~value~~recognize ~~and is then re~~stock-~~valued~~based atcompensation ~~each~~expense ~~reporting date, with changes~~ in ~~fair~~the ~~value~~consolidated ~~recognized~~financial instatements ~~earnings~~for ~~each~~equity-classified ~~reporting~~employee ~~period.~~stock-based ~~For~~compensation ~~warrant~~awards ~~derivative~~based ~~instruments,~~on the ~~Company~~grant ~~uses~~date ~~the~~fair ~~Black-Scholes model to~~ value of the ~~derivative instruments at inception and subsequent valuation dates~~awards. ~~The~~ Non-employee ~~classification of derivative instruments, including whether such instruments should be recorded as a liability or as equity, is re~~share-~~assessed~~based atawards ~~the~~are ~~end~~accounted offor ~~each~~based ~~reporting~~upon ~~period, in accordance with~~ FASB ASC Topic ~~815~~505-50, ~~Derivatives and Hedging. Derivative instrument liabilities are classified in the balance sheet as current or non~~Equity-~~current~~Based ~~based~~Payments onto ~~whether or not the net~~Non-~~cash settlement of the derivative instrument could be required within 12 months of the balance sheet date~~Employees.

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Fair Value of our Debt and Equity Instruments

Many of our various debt and equity transactions require us to determine the fair value of a debt or equity instrument in order to properly record the transaction in our consolidated financial statements. Fair value is generally determined by applying widely acceptable valuation models, (e.g. the Black Scholes model) using the trading price of the underlying instrument or by comparison to instruments with comparable maturities and terms.

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Revenue Recognition

We utilize the accrual method of accounting for crude oil and natural gas revenues, whereby revenues are recognized based on our net revenue interest in the wells. Crude oil inventories are immaterial and are not recorded.

Gas imbalances are accounted for using the entitlement method. Under this method, revenues are recognized only to the extent of our proportionate share of the gas sold. However, we have no history of significant gas imbalances.

Income Taxes

Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which such temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the operating results of the period that includes the enactment date. In addition, a valuation allowance is established to reduce any deferred tax asset for which it is determined that it is more likely than not that some portion of the deferred tax asset will not be realized.

Recently Issued Accounting Pronouncements

In ~~July~~May ~~2013~~2014, the FASB issued ~~ASU~~Accounting ~~2013-11,~~Standards ~~“Income~~Update ~~Taxes~~No. –2014-09, ~~Presentation~~Revenue offrom anContracts ~~Unrecognized~~with ~~Tax~~Customers ~~Benefit~~(“ASU ~~When~~2014-09”), awhich ~~Net~~supersedes ~~Operating~~nearly ~~Loss~~all ~~Carryforward~~existing orrevenue ~~Tax~~recognition ~~Credit~~guidance ~~Carryforward~~under ~~Exists”~~GAAP. The ~~objective~~core inprinciple ~~this~~of ~~update~~ASU ~~covers~~2014-09 ~~FASB ASC Topic 740 and~~ is to ~~eliminate~~recognize ~~the~~revenue ~~diversity~~when inpromised ~~presentation~~goods ofor ~~unrecognized~~services ~~tax~~are ~~benefits~~transferred ~~when~~to acustomers ~~net~~in ~~operating~~an ~~loss~~amount ~~carryforward,~~that areflects ~~similar~~the ~~tax~~consideration ~~loss,~~to orwhich aan ~~tax~~entity ~~credit~~expects ~~carryforward~~to ~~exists.~~be ~~The~~entitled ~~amendments~~for inthose ~~this~~goods ~~update~~or ~~will~~services. beASU ~~effective~~2014-09 ~~for~~defines ~~fiscal~~a ~~periods~~five ~~beginning~~step ~~after~~process ~~December~~to ~~15,~~achieve ~~2013.~~this ~~The~~core ~~adoption~~principle ofand, ~~ASU~~in ~~2013-11~~doing isso, ~~not~~more ~~expected~~judgment toand ~~have~~estimates amay ~~material~~be ~~impact~~required onwithin the ~~Company’s~~revenue ~~consolidated~~recognition ~~financial~~process ~~position~~than orare ~~results~~required ofunder ~~operations~~existing GAAP.

InThe ~~February~~standard ~~2013,~~is ~~the~~effective ~~FASB~~for ~~issued~~annual ~~Accounting~~periods ~~Standards~~beginning ~~Update~~after ~~(“ASU”)~~December ~~2013-04~~15, ~~“Liabilities~~2016, –and ~~Obligations~~interim ~~Resulting~~periods ~~from~~therein, ~~Joint~~using ~~and~~either ~~Several~~of ~~Liability~~the ~~Arrangements~~following ~~for~~transition ~~Which~~methods: ~~the~~(i) ~~Total~~a ~~Amount~~full retrospective approach reflecting the application of the ~~Obligations~~standard Isin ~~Fixed~~each atprior reporting period with the ~~Reporting~~option ~~Date”.~~to ~~The~~elect ~~amendments~~certain inpractical ~~this~~expedients, ~~update~~or ~~cover~~(ii) a ~~wide~~retrospective ~~range~~approach with the cumulative effect of ~~topics~~initially inadopting ~~the~~ASU ~~ASC.~~2014-09 ~~These~~recognized ~~amendments~~at ~~provide~~the ~~guidance~~date ~~for~~of ~~joint~~adoption ~~and~~(which ~~several~~includes ~~liability~~additional ~~arrangements~~footnote ~~for~~disclosures). ~~amounts~~We ~~fixed~~are atcurrently evaluating the ~~reporting~~impact ~~date.~~of ~~The~~adoption ~~amendments~~of inASU ~~this~~2014-09 ~~update~~on ~~will~~our beconsolidated ~~effective~~financial ~~for~~statements ~~fiscal~~and ~~periods~~have ~~beginning~~not ~~after~~yet ~~December~~determined ~~15,~~the ~~2013.~~method ~~The~~we ~~adoption~~will ofadopt ~~ASU~~by ~~2013-04~~which isto ~~not~~implement ~~expected~~the standard. We are studying the new standard and starting to ~~have~~evaluate aand ~~material~~determine the impact the new standard will have on the ~~Company’s~~timing ~~consolidated~~of ~~financial~~revenue ~~position~~recognition orunder ~~results~~our customer agreements. We cannot, however, provide any estimate of ~~operations~~the impact of adopting the new standard at this time.

On August 27, 2014, the FASB issued Accounting Standards Update No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”), which requires management to assess a company’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. Under this new standard, disclosures are required when conditions give rise to substantial doubt about a company’s ability to continue as a going concern within one year from the financial statement issuance date. The new standard is effective for the annual period ending after December 15, 2016, and all annual and interim periods thereafter. We do not expect the adoption of these disclosures to have a significant impact on our consolidated financial statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Not required under Regulation S-K for “smaller reporting companies.”

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ITEM 8. FINANCIAL STATEMENTS.

PEGASI ENERGY RESOURCES CORPORATION

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

		Page
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets as of December 31, 2013 and 2012		F-3
Consolidated Balance Sheets as of December 31, 2014 and 2013		F-3
Consolidated Statements of Operations for the years ended December 31, 2013 and 2012		F-5
Consolidated Statements of Operations for the years ended December 31, 2014 and 2013		F-5
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2013 and 2012		F-6
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2014 and 2013		F-6
Consolidated Statements of Cash Flows for the years ended December 31, 2013 and 2012		F-7
Consolidated Statements of Cash Flows for the years ended December 31, 2014 and 2013		F-7
Notes to Consolidated Financial Statements		F-8

F-1

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Pegasi Energy Resources Corporation and subsidiaries

We have audited the accompanying consolidated balance sheets of Pegasi Energy Resources Corporation and subsidiaries (the “Company”) as of December 31, ~~2013~~2014 and ~~2012~~2013, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years then ended. The Company’s management is responsible for these consolidated financial statements. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of ~~its~~their internal control over financial reporting. An Our audit ~~includes~~included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Pegasi Energy Resources Corporation and its subsidiaries as of December 31, ~~2013~~2014 and ~~2012~~2013, and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming that the entity will continue as a going concern. The Company has historically incurred operating losses, has negative cash flows from operating activities, and an accumulated deficit of approximately $37.0 million as of December 31, 2014. Management’s plans in regard to these matters are described in Note 2 to the consolidated financial statements. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. These consolidated financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classification of liabilities that may result from the outcome of this uncertainty.

/s/ Whitley Penn LLP

Dallas, Texas

~~March~~April 243, ~~2014~~2015

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PEGASI ENERGY RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

	December 31,			December 31,
	2013			2012
	2014			2013
Assets
Current assets:
Cash and cash equivalents	$	2373,~~467,761~~506		$	12,~~421~~467,~~198~~761
Accounts receivable, trade		~~300~~385,~~132~~334			~~404~~300,~~120~~132
Accounts receivable, related parties		2640,~~584~~002			1326,~~002~~584
Joint interest billing receivable, related parties, net		~~119~~58,~~188~~727			1119,~~388,969~~188
Joint interest billing receivable, net		4217,~~302~~280			~~275~~42,~~423~~302
Other current assets		4536,~~718~~963			5845,~~678~~718
Total current assets		3911,~~001,685~~812			3,~~561~~001,~~390~~685
Property and equipment:
Equipment		6667,~~855~~435			66,855
Pipelines		~~946~~981,~~012~~933			~~934~~946,~~419~~012
Leasehold improvements		7,022			7,022
Vehicles		56,174			56,174
Office furniture		89,~~148~~961			~~136~~89,~~283~~148
Website		-			15,000
Total property and equipment		1,202,525			1,165,211
Total property and equipment		1,165,211			1,215,753
Less accumulated depreciation		(557,160	)		(473,163	)
Less accumulated depreciation		(473,163	)		(449,931	)
Property and equipment, net		645,365			692,048
Property and equipment, net		692,048			765,822
Oil and gas properties:
Oil and gas properties, proved		17,583,190			17,193,227
Costs subject to depreciation, depletion, and amortization		21,391,472			18,086,443
Oil and gas properties, unproved		14,298,503			13,090,037
Costs not subject to depreciation, depletion, and amortization		12,337,167			14,298,503
Capitalized asset retirement obligations		503,253			491,338
Total oil and gas properties		33,728,639			32,384,946
Total oil and gas properties		32,384,946			30,774,602
Less accumulated depreciation, depletion, and amortization		(2,468,546	)		(1,951,186	)
Less accumulated depletion and depreciation		(1,951,186	)		(1,565,559	)
Oil and gas properties, net		31,260,093			30,433,760
Oil and gas properties, net		30,433,760			29,209,043
Other assets:
Restricted cash – drilling program		90347,~~559~~129			2990,~~435~~559
Certificates of deposit		78,560			78,450
Deferred financing costs		10,000			-
Certificates of deposit		78,665			78,560
Easements		34,848			34,848
Total other assets		~~203~~470,~~967~~642			~~142~~203,~~733~~967
Total assets	$	3433,~~331~~287,~~460~~912		$	3334,~~678~~331,~~988~~460

The accompanying notes are an integral part of these consolidated financial statements.

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PEGASI ENERGY RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS (continued)

	December 31,			December 31,
	2013			2012
	2014			2013
Liabilities and Stockholders' Equity
Current Liabilities:
Cash overdraft	$	~~255~~5,~~628~~673		$	17255,~~795~~628
Accounts payable		1999,~~401,014~~554			1,~~515~~401,~~153~~014
Accounts payable, related parties		23,~~924~~450,~~089~~175			2,~~399~~924,~~524~~089
Revenue payable		~~852~~460,~~079~~618			~~691~~852,~~202~~079
Interest payable, related parties		2,291,652			1,659,336
Interest payable, related party		2,923,980			-
Liquidated damages payable		4048,~~892~~808			3440,~~260~~892
Other payables		5940,~~627~~780			7759,~~957~~627
Current portion of notes payable and capital leases		86,~~703~~740			8,~~111~~703
Total current liabilities		7,833,684			6,403,338
Current notes payable, related party		8,160,646			-
Drilling prepayments		90,559			29,435
Total current liabilities		16,096,974			5,542,032
Notes payable and capital leases		9,190			17,893
Drilling prepayments		347,129			90,559
Notes payable, related parties		8,160,646			8,160,646
Interest payable, related party		-			2,291,652
Asset retirement obligations		674,092			628,668
Notes payable and capital leases		2,493			9,190
Total liabilities		16,768,171			15,239,980
Notes payable, related party		-			8,160,646
Commitments and contingencies (Note 17)
Asset retirement obligations		891,092			674,092
Total liabilities		17,337,688			16,768,171
Commitments and contingencies (Note 16)
Stockholders' equity:
Preferred stock: $0.001 par value; 5,000,000 shares authorized; none issued and outstanding		-			-
Common stock: $0.001 par value; 150,000,000 shares authorized; 68,169,923 and 62,602,377 shares issued and outstanding, respectively		68,170			62,603
Common stock: $0.001 par value; 150,000,000 shares authorized; 70,539,499 and 68,169,923 shares issued and outstanding, respectively		70,540			68,170
Additional paid-in capital		4552,~~599~~894,~~663~~835			4245,~~776~~599,~~416~~663
Accumulated deficit		(2837,~~104~~015,~~544~~151	)		(2428,~~400~~104,~~011~~544	)
Total stockholders' equity		1715,~~563~~950,~~289~~224			1817,~~439~~563,~~008~~289
Total liabilities and stockholders' equity	$	3433,~~331~~287,~~460~~912		$	3334,~~678~~331,~~988~~460

The accompanying notes are an integral part of these consolidated financial statements.

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PEGASI ENERGY RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2013			2012
	2014			2013
Revenues:
Oil and gas	$	1,~~628~~704,~~806~~757		$	1,~~359~~628,~~525~~806
Condensate and skim oil		4127,~~782~~807			4241,~~643~~782
Transportation and gathering		~~206~~267,~~041~~391			~~144~~206,~~693~~041
Total revenues		1,~~876~~999,~~629~~955			1,~~546~~876,~~861~~629
Operating expenses:
Lease operating expenses		1887,~~074,466~~041			~~647~~1,~~749~~074,466
Pipeline operating expenses		~~186~~255,~~475~~905			~~129~~186,~~449~~475
Depletion and depreciation		~~470~~601,~~739~~865			~~427~~470,~~701~~739
General and administrative		35,~~074~~880,~~590~~900			63,~~196~~074,~~172~~590
Total operating expenses		47,~~806~~625,~~270~~711			74,~~401~~806,~~071~~270
Loss from operations		(25,~~929~~625,~~641~~756	)		(52,~~854~~929,~~210~~641	)
Other income (expenses):
Interest income		~~110~~370			~~166~~110
Interest expense		(~~637~~635,~~379~~133	)		(~~636~~637,~~832~~379	)
Changes in fair value of warrant derivative liability		-			88,868
Warrant settlement/modification expense		(2,642,266	)		(134,102	)
Warrant settlement/modification expense		(134,102	)		(294,534	)
Other expense, net		(7,822	)		(3,521	)
Other income (expense), net		(3,521	)		176,765
Total other expense, net		(3,284,851	)		(774,892	)
Total other income (expense), net		(774,892	)		(665,567	)
Loss before income tax expense		(8,910,607	)		(3,704,533	)
Loss from operations before income tax expense		(3,704,533	)		(6,519,777	)
Income tax expense		-			-
Income tax expense		-			(3,515	)
Net loss	$	(8,910,607	)	$	(3,704,533	)
Net loss	$	(3,704,533	)	$	(6,523,292	)
Basic and diluted loss per share:
Basic and diluted loss per share	$	(0.0613	)	$	(0.1206	)
Weighted average shares outstanding – basic and diluted		6370,~~658~~029,~~587~~590			5663,~~082~~658,~~199~~587

The accompanying notes are an integral part of these consolidated financial statements.

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PEGASI ENERGY RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

Years Ended December 31, ~~2013~~2014 and ~~2012~~2013

					Additional
	Common Stock				Additional Paid-in			Accumulated
	Common Stock				Paid-in			Accumulated
	Shares		Amount		Capital			Deficit			Total
Balance at December 31, 2011		48,953,679	$	48,954	$	31,164,705		$	(17,876,719	)	$	13,336,940
Balance at December 31, 2012		62,602,377	$	62,603	$	42,776,416		$	(24,400,011	)	$	18,439,008
Common stock issued for:
Services		1,300,000		1,300		894,200			-			895,500
Cash, net of offering costs		11,154,891		11,155		5,843,931			-			5,855,086
Cashless exercise of warrants classified as a derivative		1,193,807		1,194		1,127,634			-			1,128,828
Stock based compensation						2,719,888						2,719,888
Warrant price and extension modification		-		-		294,534			-			294,534
Warrant liability reclassified to equity due to modification		-		-		731,524			-			731,524
Net loss		-		-		-			(6,523,292	)		(6,523,292	)
Balance at December 31, 2012		62,602,377		62,603		42,776,416			(24,400,011	)		18,439,008
Common stock issued for:
Services		50,000		50		35,450			-			35,500
Cash, net of offering costs		4,499,348		4,499		1,994,732			-			1,999,231
Cash exercise of warrants		8,000		8		4,792			-			4,800
Cashless exercise of warrants		1,010,198		1,010		(1,010	)		-			-
Stock based compensation		-		-		655,181			-			655,181
Warrant settlement agreement		-		-		134,102			-			134,102
Net loss		-		-		-			(3,704,533	)		(3,704,533	)
Balance at December 31, 2013		68,169,923	$	68,170	$	45,599,663		$	(28,104,544	)	$	17,563,289
Common stock issued for:
Services		265,000		265		197,985			-			198,250
Cash, net of offering costs		1,562,000		1,562		693,338			-			694,900
Cash exercise of warrants		7,970		8		4,774			-			4,782
Cashless exercise of warrants		29,606		30		(30	)		-			-
Purchase of working interest		505,000		505		403,495			-			404,000
Stock based compensation		-		-		3,353,344			-			3,353,344
Warrant modification agreement		-		-		2,642,266			-			2,642,266
Net loss		-		-		-			(8,910,607	)		(8,910,607	)
Balance at December 31, 2014		70,539,499	$	70,540	$	52,894,835		$	(37,015,151	)	$	15,950,224

The accompanying notes are an integral part of these consolidated financial statements.

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PEGASI ENERGY RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2013			2012
	2014			2013
Operating Activities
Net loss	$	(38,~~704~~910,~~533~~607	)	$	(63,~~523~~704,~~292~~533	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion and depreciation		~~470~~601,~~739~~865			~~427~~470,~~701~~739
Accretion of discount on asset retirement obligations		3334,~~509~~588			2633,~~373~~509
Stock based compensation		~~655~~3,~~181~~353,344			2655,~~719,888~~181
Common stock issued for consulting services		35198,~~500~~250			~~895~~35,500
Loss on obsolete equipment		254			-
(Gain) loss on obsolete equipment		(508	)		254
Gain on sale of equipment		-			(276	)
Warrant settlement/modification expense		2,642,266			134,102
Change in fair value of warrant derivative liability		-			(88,868	)
Warrant settlement/modification expense		134,102			294,534
Changes in operating assets and liabilities:
Accounts receivable, trade		~~103~~(85,~~988~~202	)		~~(99~~103,~~180~~988	)
Account receivable, related parties		(13,~~582~~418	)		(113,~~500~~582	)
Joint interest billing receivable, related parties, net		1(8,~~269,781~~655	)		(1,~~203~~269,~~008~~781	)
Joint interest billing receivable, net		~~233~~28,~~421~~091			~~(187~~233,~~911~~421	)
Other current assets		128,~~960~~755			2712,~~567~~960
Accounts payable		45(19,~~592~~194	)		~~(392~~45,~~833~~592	)
Accounts payable, related parties		~~524~~526,~~565~~086			~~480~~504,~~805~~702
Revenue payable		~~160~~(391,~~877~~461	)		~~374~~160,~~556~~877
Interest payable, related parties		632,316			632,316
Interest payable, related party		632,328			632,316
Liquidated damages payable		67,~~632~~916			~~(173~~6,~~486~~632	)
Other payables		(18,~~330~~847	)		441,~~802~~533
Net cash provided by (used in) operating activities		~~582~~(1,~~972~~414,403	)		(2582,~~746,312~~972	)
Investing Activities
Additions to certificates of deposit		(~~110~~105	)		(~~165~~110	)
Purchases of property and equipment		(1140,~~892~~383	)		(~~245~~11,~~485~~892	)
Purchase of oil and gas properties		(1,~~758~~070,~~160~~431	)		(81,~~037~~758,~~047~~160	)
Net cash used in investing activities		(1,~~770~~110,~~162~~919	)		(81,~~282~~770,~~697~~162	)
Financing Activities
Payments on notes payable and capital leases		(8,~~111~~660	)		(78,~~682~~111	)
Cash overdraft		~~237~~(249,~~833~~955	)		~~(146~~237,~~565~~833	)
Proceeds from exercise of warrants		4,800			-
Deferred financing fees		(10,000	)		-
Proceeds from sale of common stock, net of offering costs		1,999,231			5,855,086
Proceeds from exercise of warrants		4,782			4,800
Net cash provided by financing activities		2,233,753			5,700,839
Proceeds from sale of common stock, net of offering costs		694,900			1,999,231
Net increase (decrease) in cash and cash equivalents		1,046,563			(5,328,170	)
Net cash provided by financing activities		431,067			2,233,753
Cash and cash equivalents at beginning of year		1,421,198			6,749,368
Net increase (decrease) in cash and cash equivalents		(2,094,255	)		1,046,563
Cash and cash equivalents at end of year	$	2,467,761		$	1,421,198
Cash and cash equivalents at beginning of year		2,467,761			1,421,198
Cash and cash equivalents at end of year	$	373,506		$	2,467,761

See Note 4 for supplemental cash flow and non-cash information.

The accompanying notes are an integral part of these consolidated financial statements.

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Table of Contents

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, ~~2013~~2014 AND ~~2012~~2013

1. NATURE OF OPERATIONS

Pegasi Energy Resources Corporation (“PERC” or the “Company”) is an independent energy company engaged in the exploration for, and production of, crude oil and natural gas. The Company’s focus is on the development of a repeatable, low-geological risk, high-potential project in the active East Texas oil and gas region. The Company’s business strategy ~~in what it has designated the “Cornerstone Project”,~~ is to identify and exploit resources in and adjacent to existing or indicated producing areas within the mature Rodessa oil field. The Company believes that it is uniquely familiar with the history and geology of the ~~Cornerstone~~project ~~Project~~ area based on its collective experience in the region as well as through its development and ownership of a large proprietary database, which details the drilling history of the ~~Cornerstone~~project ~~Project~~ area since 1980. In 2012, the Company 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 the Company believes that implementing the latest proven drilling and completion techniques to exploit its geological insight in the Cornerstone Project area will enable it to find significant oil and gas reserves.

PERC conducts its main exploration and production operations through its wholly-owned subsidiary, Pegasi Operating, Inc. ("POI"). It conducts additional operations through another wholly-owned subsidiary, TR Rodessa, Inc. ("TR Rodessa").

TR Rodessa owns an 80% undivided interest in and operates a 40-mile natural gas pipeline and gathering system which is currently being used by PERC to transport its hydrocarbons to market. Excess capacity on this system is used to transport third-party hydrocarbons.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

a) Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted (“GAAP”) in the United States of America and include the accounts of PERC and its wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated. In preparing the accompanying consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the consolidated financial statements and disclosures. Actual results may differ from these estimates.

Estimates made in preparing these consolidated financial statements include, among other things, estimates of the proved oil and natural gas reserve volumes used in calculating depletion expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment write-down; operating costs accrued; volumes and prices for revenues accrued; estimates of the fair value of stock-based compensation awards; and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Future changes in the assumptions used could have a significant impact on reported results in future periods.

b) ~~Cash~~ ~~and~~Going ~~Cash Equivalents~~Concern

The Company has incurred operating losses for seven years and has negative cash flows from operations. It also has an accumulated deficit of $37,015,151 as of December 31, 2014. As a result, the Company’s continuation as a going concern is dependent on its ability to obtain additional financing until it can generate sufficient cash flows from operations to meet its debt and working capital obligations.

These financial statements have been prepared on a going concern basis, which implies the Company will continue to meet its obligations and continue its operations for the next fiscal year. The continuation of the Company as a going concern is dependent upon its ability to obtain necessary debt or equity financing to continue operations until it begins generating positive cash flow. There is no assurance that financing will be available to the Company when needed or, if available, or that it can be obtained on commercially reasonable terms. Considering its financial condition, the Company may be forced to issue debt or equity at less favorable terms than would otherwise be available.

Although the Company raised an additional $1.9 million in the first quarter of 2015, if the Company is not able to obtain additional or alternative financing on a timely basis and is unable to generate sufficient revenues and cash flows, it will be unable to meet its capital requirements and will be unable to continue as a going concern. The financial statements do not include any adjustments to reflect that may be necessary if the Company is unable to continue as a going concern.

c) Cash and Cash Equivalents

We consider all highly-liquid investments with an original maturity of three months or less, when purchased, to be cash equivalents. We include our overnight sweep accounts that are invested in federal obligations in our cash balances.

c) Accounts Receivable

The Company’s accounts receivable consists primarily of oil and natural gas sales and joint interest billings, which are recorded at the invoiced amount. Collateral is not required for such receivables, nor is interest charged on past due balances. The Company extends credit based on management’s assessment of the customers’ financial condition and evaluates the allowance for doubtful accounts based on a receivable aging, customer disputes and general business and economic conditions. No allowance was indicated at December 31, 2013 or 2012. As of December 31, 2013, two customers totaled approximately 42% and 54% of the Company’s total accounts receivable. Accounts receivables from the same two customers in 2012, approximated 63% and 35% of total trade receivables at December 31, 2012. As of December 31, 2013, there were two customers that accounted for 14% and 62% of the Company’s total joint interest billing receivables. Joint interest billing receivables from two customers in 2012 approximated 73% and 11%.

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Table of Contents

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, ~~2013~~2014 AND ~~2012~~2013

d) ~~Property~~Accounts ~~and Equipment~~Receivable

~~Property~~The ~~and~~Company’s ~~equipment~~accounts ~~are~~receivable ~~recorded~~consists atprimarily ~~cost~~of oil and ~~depreciation~~ isnatural ~~calculated~~gas ~~using~~sales ~~the~~and ~~straight-line~~joint ~~method~~interest ~~over~~billings, which are recorded at the ~~estimated~~invoiced ~~useful~~amount. Collateral ~~lives~~is ofnot required ~~the~~for ~~assets~~such receivables, ~~which~~nor ~~range~~is ~~from~~interest ~~five~~charged toon ~~thirty-nine~~past ~~years~~due balances. ~~Expenditures~~The ~~for~~Company ~~major~~extends ~~renewals~~credit ~~and~~based ~~betterments~~on ~~that~~management’s ~~extend~~assessment of the ~~useful~~customers’ ~~lives~~financial ~~are~~condition ~~capitalized. Expenditures~~and evaluates the allowance for ~~normal~~doubtful ~~maintenance~~accounts based on a receivable aging, customer disputes and ~~repairs~~general ~~are~~business ~~expensed~~and aseconomic ~~incurred~~conditions. ~~Upon~~ No ~~sale~~allowance orwas ~~abandonment~~indicated at December 31, ~~the~~2014 ~~cost~~or 2013. As of ~~the~~December ~~equipment~~31, ~~and~~2014, ~~related~~two ~~accumulated~~customers ~~depreciation~~totaled ~~are~~approximately ~~removed~~22% ~~from~~and 69% of the Company’s total accounts ~~and~~receivable. ~~any~~Accounts ~~gains~~receivables orfrom ~~losses~~the ~~thereon~~same ~~are~~two ~~recognized~~customers in ~~the~~2013, ~~operating~~approximated ~~results~~42% and 54% of ~~the~~total ~~respective~~trade ~~period~~receivables at December 31, 2013. ~~Depreciation~~As ~~expense~~of December 31, 2014, there was ~~$85~~one customer,~~112~~ ~~and~~which ~~$81~~is a related party,~~168~~ who accounted for 77% of the ~~years~~Company’s ~~ended~~total ~~December~~joint ~~31,~~interest billing receivables. Joint interest billing receivables from two customers in 2013 ~~and~~approximated ~~2012,~~14% ~~respectively~~and 62%.

e) ~~Oil~~Property and ~~Gas Properties~~Equipment

~~The~~Property ~~Company~~and ~~uses~~equipment are recorded at cost and depreciation is calculated using the ~~full~~straight-~~cost~~line method over the estimated useful lives of ~~accounting~~the assets, which range from five to thirty-nine years. Expenditures for ~~its~~major ~~oil~~renewals and ~~gas~~betterments ~~producing~~that ~~activities,~~extend ~~which~~the useful lives are ~~all located~~capitalized. Expenditures infor ~~Texas~~normal maintenance and repairs are expensed as incurred. Upon ~~Accordingly,~~sale ~~all~~or ~~costs~~abandonment, ~~associated~~the ~~with~~cost of the ~~acquisition,~~equipment ~~exploration,~~and related accumulated depreciation are removed from the accounts and ~~development~~any gains or losses thereon are recognized in the operating results of ~~oil~~the ~~and~~respective ~~gas~~period. Depreciation ~~reserves~~expense was $84,505 ~~including~~and ~~directly~~$85,112 ~~related~~for ~~overhead~~the ~~costs~~years ended December 31, ~~are~~2014 ~~capitalized~~and 2013, respectively.

All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the units-of-production method using estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment shall be added to the capitalized costs to be amortized.f) ~~Depletion~~Oil ~~expense for the years ended December 31, 2013~~ and ~~2012~~Gas ~~was $385,627 and $346,533 ($10.24 and $11.66 per equivalent barrel), respectively.~~Properties

~~All~~The ~~items~~Company ~~classified~~uses asthe ~~unproved~~full-cost ~~property~~method ~~are~~of ~~assessed~~accounting ~~on an annual basis~~ for ~~possible~~its ~~impairment~~oil orand ~~reduction~~gas inproducing ~~value~~activities. ~~Properties~~Costs ~~are~~to ~~assessed~~acquire onmineral aninterests ~~individual~~in ~~basis~~oil orand asgas ~~a group if~~ properties ~~are individually insignificant. The assessment includes consideration of various factors~~, ~~including, but not limited~~ to, ~~the following: intent to~~ drill; ~~remaining lease term; geological~~ and ~~geophysical~~equip ~~evaluations;~~exploratory ~~drilling~~wells ~~results~~used ~~and~~to ~~activity;~~find ~~assignment of~~ proved reserves;, and ~~economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred~~ to ~~date~~drill ~~for such property~~ and ~~all~~equip ordevelopment awells ~~portion~~including ofdirectly ~~the~~related ~~associated~~overhead ~~leasehold~~ costs ~~are transferred to the full cost pool~~ and ~~become~~related ~~subject~~asset toretirement ~~amortization. As of December 31, 2013 and 2012, our net capitalized~~ costs ofare ~~oil and gas properties did not exceed the present value of our estimated proved reserves therefore the accompanying consolidated financial statements do not include a provision for impairment~~capitalized.

Under this method, all costs, including internal costs directly related to acquisition, exploration and development activities are capitalized as oil and gas property costs. Properties not subject to amortization consist of exploration and development costs, which are evaluated on a property-by-property basis. Amortization of these unproved property costs begins when the properties become proved or their values become impaired. The Company assesses the realizability of unproved properties, if any, on at least an annual basis or when there has been an indication that impairment in value may have occurred. Impairment of unproved properties is assessed based on management's intention with regard to future exploration and development of individually significant properties and the ability to obtain funds to finance such exploration and development. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Due to abandoned leases and dry holes there was determined to be an impairment of $3,185,065 in the year ended December 31, 2014. There were no impairments in the year ended December 31, 2013.

All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the units-of-production method using estimates of proved reserves. Depletion expense for the years ended December 31, 2014 and 2013 was $517,360 and $385,627 ($11.30 and $10.24 per equivalent barrel), respectively.

The unamortized cost of oil and natural gas properties, net of related deferred income taxes, is limited to the sum of the estimated future after-tax net revenues from proved properties, after giving effect to cash flow hedge positions, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects. This limitation is known as the “ceiling test,” and is based on SEC rules for the full cost oil and gas accounting method. There was no ceiling test write down recorded for the years ended December 31, 2014 and 2013.

~~The~~g) Impairment ~~following table sets forth a summary~~ of ~~oil~~Long-Lived and gas property costs not being amortized at December 31, 2013, by the year in which such costs were incurred. There are no individually significant properties or significant development projects included in costs not being amortized. The 2010 through 2013 amounts are net of reimbursements received in those years for costs incurred in prior years under our leasing program. The majority of the evaluation activities are expected to be completed within five to ten years.Assets

									2010
	Total		2013		2012		2011		and Prior
Property acquisition costs	$	14,299,000	$	1,209,000	$	2,739,000	$	1,306,000	$	9,045,000

The carrying value of property and equipment is periodically evaluated under the provisions of Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic No. 360, Property, Plant, and Equipment. FASB ASC Topic No. 360 requires long-lived assets and certain identifiable intangibles to be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When it is determined that the estimated future net cash flows of an asset will not be sufficient to recover its carrying amount, an impairment loss must be recorded to reduce the carrying amount to its estimated fair value. The Company had no material impairments in 2014 and 2013.

f) Impairment of Long-Lived Assets

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PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, ~~2013~~2014 AND ~~2012~~2013

gh) Asset Retirement Obligations

FASB ASC Topic No. 410, Asset Retirement and Environmental Obligations, requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which an oil or natural gas property is acquired or a new well is drilled. An amount equal to and offsetting the liability is capitalized as part of the carrying amount of the Company’s oil and natural gas properties at its discounted fair value. The liability is then accreted up by recording expense each period until it is settled or the well is sold, at which time the liability is reversed. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining lives of those wells based on reserve estimates. The Company does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined. See Note 8 – Asset Retirement Obligations for additional information.

hi) Revenue Recognition

The Company utilizes the accrual method of accounting for crude oil and natural gas revenues, whereby revenues are recognized based on the Company’s net revenue interest in the wells. Crude oil inventories are immaterial and are not recorded. Gas imbalances are accounted for using the entitlement method. Under this method revenues are recognized only to the extent of the Company’s proportionate share of the gas sold. However, the Company has no history of significant gas imbalances.

ij) Stock-based Compensation

The Company has accounted for stock-based compensation under the provisions of FASB ASC Topic 718-10, Compensation-Stock Compensation. The Company recognizes stock-based compensation expense in the consolidated financial statements for equity-classified employee stock-based compensation awards based on the grant date fair value of the awards. Non-employee share-based awards are accounted for based upon FASB ASC Topic 505-50, Equity-Based Payments to Non-Employees. During the years ended December 31, ~~2013~~2014 and ~~2012~~2013, the Company recognized $~~655~~3,~~181~~353,344 and $2655,~~719~~181,~~888,~~ respectively, of stock-based compensation expense which has been recorded as a general and administrative expense in the consolidated statements of operations.

j) Derivative Instruments

For derivative instruments that are accounted for as liabilities, the derivative instrument is initially recorded at its fair value and is then re-valued at each reporting date, with changes in fair value recognized in earnings each reporting period. For warrant derivative instruments, the Company uses the Black-Scholes model to value the derivative instruments at inception and subsequent valuation dates. The classification of derivative instruments, including whether such instruments should be recorded as a liability or as equity, is re-assessed at the end of each reporting period, in accordance with FASB ASC Topic 815, Derivatives and Hedging. Derivative instrument liabilities are classified in the balance sheet as current or non-current based on whether or not the net-cash settlement of the derivative instrument could be required within 12 months of the balance sheet date.

k) Income Taxes

Deferred income taxes are determined using the “liability method” in accordance with FASB ASC Topic No. 740, Income Taxes. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the operating results of the period that includes the enactment date. In addition, a valuation allowance is established to reduce any deferred tax asset for which it is determined that it is more likely than not that some portion of the deferred tax asset will not be realized.

l) Net Loss per Common Share

Basic net loss per common share is calculated using the weighted average number of common shares outstanding during the period. The Company uses the treasury stock method of calculating fully diluted per share amounts whereby any proceeds from the exercise of stock options or other dilutive instruments are assumed to be used to purchase common shares at the average market price during the period. The dilutive effect of convertible securities is reflected in diluted loss per share by application of the if-converted method. Under this method, conversion shall not be assumed for the purposes of computing diluted loss per share if the effect would be anti-dilutive. For the years ended December 31, ~~2013~~2014 and ~~2012~~2013, the Company had potentially dilutive shares of 4246,~~499~~605,~~238~~732 and 4142,~~043~~499,~~486~~238, respectively, that were excluded from the earnings per share calculation because their impact would be antidilutive. For the years ended December 31, ~~2013~~2014 and ~~2012~~2013, the diluted loss per share is the same as basic loss per share, as the effect of common stock equivalents ~~are~~is anti-dilutive.

m) Fair Value of Financial Instruments

FASB ASC Topic 825, Financial Instruments, requires certain disclosures regarding the fair value of financial instruments. Fair value of financial instruments is made at a specific point in time, based on relevant information about financial markets and specific financial instruments. As these estimates are subjective in nature, involving uncertainties and matters of significant judgment, they cannot be determined with precision. Changes in assumptions can significantly affect estimated fair values.

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Table of Contents

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, ~~2013~~2014 AND ~~2012~~2013

FASB ASC Topic 820, Fair Value Measurement, defines fair value as the price that would be received from selling an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. When determining the fair value measurements for assets and liabilities required or permitted to be recorded at fair value, the Company considers the principal or most advantageous market in which it would transact and it considers assumptions that market participants would use when pricing the asset or liability.

FASB ASC Topic 820 establishes a fair value hierarchy that requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. A financial instrument’s categorization within the fair value hierarchy is based upon the lowest level of input that is significant to the fair value measurement. FASB ASC Topic 820 establishes three levels of inputs that may be used to measure fair value:

Level 1 - Level 1 applies to assets or liabilities for which there are quoted prices in active markets for identical assets or liabilities.

Level 2 - Level 2 applies to assets or liabilities for which there are inputs other than quoted prices included within Level 1 that are observable for the asset or liability such as quoted prices for similar assets or liabilities in active markets; quoted prices for identical assets or liabilities in markets with insufficient volume or infrequent transactions (less active markets); or model-derived valuations in which significant inputs are observable or can be derived principally from, or corroborated by, observable market data.

Level 3 - Level 3 applies to assets or liabilities for which there are unobservable inputs to the valuation methodology that are significant to the measurement of the fair value of the assets or liabilities.

The following table sets forth our estimate of fair value of our financial instruments that are liabilities as of December 31, 2014:

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Nonrecurring
Asset retirement obligation	$	-	$	-	$	891,092	$	891,092

The following table sets forth our estimate of fair value of our financial instruments that are liabilities as of December 31, 2013:

Quoted Prices in Active Markets for Identical Assets

Significant Other Observable Inputs

Significant Unobservable Inputs

Quoted Prices in Active Markets for Identical Assets (Level 1)

Significant Other Observable Inputs (Level 2)

Significant Unobservable Inputs (Level 3)

Total

(Level 1)

(Level 2)

(Level 3)

Total

Nonrecurring

Asset retirement obligation

674,092

~~The~~See ~~following~~Note 8, ~~table~~for ~~sets~~the ~~forth~~table ~~our~~summary ~~estimate~~ of changes in fair value of our ~~financial~~asset ~~instruments~~retirement ~~that~~obligations ~~are~~for ~~liabilities~~the asyears ofended December 31, ~~2012:~~2014 and 2013.

	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)		Total
Nonrecurring
Asset retirement obligation	$	-	$	-	$	628,668	$	628,668

In accordance with the reporting requirements of FASB ASC Topic No. 825, the Company calculates the fair value of its assets and liabilities which qualify as financial instruments under this statement and includes this additional information in the notes to consolidated financial statements when the fair value is different than the carrying value of these financial instruments. The estimated fair values of accounts receivable, accounts payable and other current assets and accrued liabilities approximate their carrying amounts due to the relatively short maturity of these instruments. The carrying value of long-term debt approximates market value due to the use of market interest rates.

The following table sets forth a summary of changes in fair value of our derivative liability for the years ended December 31, 2013 and 2012:

	2013		2012
Beginning Balance	$	-	$	1,949,220
Derivative warrants exercised		-		(1,128,828	)
Reclassification to equity due to modification		-		(731,524	)
Income included in net loss		-		(88,868	)
Balance at December 31	$	-	$	-

See Note 8, for the table summary of changes in fair value of our asset retirement obligations for the years ended December 31, 2013 and 2012.

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Table of Contents

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, ~~2013~~2014 AND ~~2012~~2013

n) New Accounting Pronouncements

InThe ~~February~~standard ~~2013,~~is ~~the~~effective ~~FASB~~for ~~issued~~annual ~~Accounting~~periods ~~Standards~~beginning ~~Update~~after ~~(“ASU”)~~December ~~2013-04~~15, ~~“Liabilities~~2016, –and ~~Obligations~~interim ~~Resulting~~periods ~~from~~therein, ~~Joint~~using ~~and~~either ~~Several~~of ~~Liability~~the ~~Arrangements~~following ~~for~~transition ~~Which~~methods: ~~the~~(i) ~~Total~~a ~~Amount~~full ofretrospective ~~the~~approach ~~Obligations~~reflecting Isthe ~~Fixed~~application atof the ~~Reporting~~standard ~~Date”.~~in ~~The~~each ~~amendments~~prior inreporting ~~this~~period ~~update~~with ~~cover~~the aoption ~~wide~~to ~~range~~elect ofcertain ~~topics~~practical inexpedients; ~~the~~or ~~ASC.~~(ii) ~~These~~a ~~amendments~~retrospective ~~provide~~approach ~~guidance~~with ~~for~~the ~~joint~~cumulative ~~and~~effect ~~several~~of ~~liability~~initially ~~arrangements~~adopting ~~for~~ASU ~~amounts~~2014-09 ~~fixed~~recognized at the ~~reporting~~ date. ~~The~~of ~~amendments~~adoption in(which ~~this~~includes ~~update~~additional ~~will~~footnote bedisclosures). ~~effective~~Management ~~for~~is ~~fiscal~~currently ~~periods~~evaluating ~~beginning~~the ~~after~~impact ~~December~~of ~~15,~~the ~~2013.~~pending ~~The~~ adoption of ASU ~~2013~~2014-0409 ison ~~not~~the ~~expected~~Company’s toconsolidated ~~have~~financial astatements ~~material~~and ~~impact~~has onnot yet determined the method the Company’s ~~consolidated~~will ~~financial~~adopt ~~position~~by orwhich ~~results~~it ofwill ~~operations~~implement the standard.

On August 27, 2014, the FASB issued Accounting Standards Update No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”), which requires management to assess a company’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. Under this new standard, disclosures are required when conditions give rise to substantial doubt about a company’s ability to continue as a going concern within one year from the financial statement issuance date. The new standard is effective for the annual period ending after December 15, 2016, and all annual and interim periods thereafter. The Company does not expect the adoption of these disclosures to have a significant impact on the Company’s consolidated financial statements.

o) Reclassifications

Certain reclassifications have been made to the comparative consolidated financial statements to conform to the current period’s presentation.

3. RESTRICTED CASH

Collateral

Certificates of deposit have been posted as collateral supporting a reclamation bond guaranteeing remediation of our oil and gas properties in Texas. As of December 31, ~~2013~~2014 and ~~2012~~2013, the balance of the certificates of deposit totaled $78,~~560~~665 and $78,~~450~~560 respectively.

2010 Drilling Program

During the last quarter of 2010, the Company executed participation and operating agreements with various independent oil and gas companies regarding the drilling of various wells. Funds received from these companies are restricted to the drilling programs and are considered released when they are spent in accordance with the agreements. Since inception, total funds of $2,462,492 were received on this program, $2,374,844 was spent on drilling activities, and $58,213 was reclassified to promote income leaving a balance of $29,435. During the quarter ended March 31, 2013, the remaining balance was either refunded to the original investors or applied against investor joint interest billing receivable balances, as applicable, to close out the 2010 restricted cash and drilling program leaving a zero balance as of December 31, 2013. There has been no additional activity in this program since that date.

2011 Drilling Program

During the last quarter of 2011, the Company executed joint operating agreements with various independent oil and gas companies regarding the drilling of various wells. Funds received from these companies are restricted to the drilling programs and are considered released when they are spent in accordance with the agreements. As of ~~December~~January 311, ~~2012~~2013, ~~funds~~the ~~of $3,427,936 were received on this~~ program ~~and~~had ~~$3,430,183 was spent on drilling activities, and $13,714 was reclassified to promote income leaving~~ a shortage of $15,961 ~~which was reclassified to operating cash and included in the joint interest billing receivable at December 31~~. However, ~~2012.~~during ~~During~~ 2013, additional funds of $2,257,314 were received on this program; $1,392,458 that the Company owed to these companies was applied to the programs during 2013, and $3,546,861 was spent on drilling activities. In addition, individual investor shortages at December 31, 2013 of $3,609 were reclassified to their joint interest billing receivables, leaving a balance of $90,559 in restricted cash and drilling prepayments at December 31, 2013. During 2014, additional funds of $317,533 were received on this program; $199,060 that the Company owed to these companies was applied to the program during 2014, and $523,666 was spent on drilling activities, leaving a balance of $83,486 in restricted cash and drilling prepayments at December 31, 2014.

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PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, ~~2013~~2014 AND ~~2012~~2013

Huntington #4 Drilling Program

In August 2014, the Company entered into a participation agreement with Pacific World Energy (“PWE”) for the drilling of up to ten wells on its leased acreage in Marion County. Under the terms of the agreement, PWE pays the full cost of the drilling and completing each well. Funds received from PWE are restricted to this drilling program and are considered released when they are spent in accordance with the agreements. As of December 31, 2014, funds of $2,045,400 were received on this program and $1,781,757 was spent on drilling activities, leaving a balance of $263,643 in restricted cash and drilling prepayments at December 31, 2014.

4. SUPPLEMENTAL CASH FLOW AND NON-CASH INFORMATION

The following non-cash transactions were recorded during the years ended December 31:

	2013		2012
	2014		2013
Trade in proceeds on equipment	$	-	$	2,640
Oil and gas assets financed through account payables	$	135,126	$	517,392
Asset retirement obligations incurred/revised	$	11,915	$	258,608
Additions to/revisions of estimates to asset retirement obligation	$	231,998	$	11,915
Cashless exercise of warrants classified as a derivative	$	-	$	1,128,828
Asset retirement obligation settled	$	49,586	$	-
Reclassification of derivative warrant liability to equity due to modification of warrants	$	-	$	731,524
Oil and gas properties purchased through issuances of common stock	$	404,000	$	-
Oil and gas assets financed through account payables	$	517,392	$	677,123
Oil and gas properties financed through assumptions of joint-interest billing receivable	$	69,116	$	-
Promote liabilities applied against oil and gas assets	$	-	$	121,379
Equipment/vehicle financed through notes payable	$	-	$	7,592

The following is supplemental cash flow information for the years ended December 31:

		2013		2012
	2014		2013
Cash paid during the year for interest	$	5,063	$	4,516
Cash paid during the period for interest	$	2,805	$	5,063
Cash paid during the year for taxes	$	-	$	3,515
Cash paid during the period for taxes	$	-	$	-

5. PROPERTY AND EQUIPMENT

Property and equipment consists of the following:

	Depreciation Methods	Depreciation Period
Equipment	Straight-line	7 Years
Pipelines	Straight-line	15 Years
Leasehold improvements	Straight-line	Lesser of the Estimated Useful Life or the Lease Term
Vehicles	Straight-line	5 Years
Office furniture	Straight-line	5 Years
Website	Straight-line	5 Years

6. NOTES PAYABLE AND CAPITAL LEASES

Notes payable and capital leases consisted of the following at December 31:

	2013		2012
Capital lease of $7,592 to Xerox Corporation, with monthly installments of $198, including interest at 19.7%, maturing February 20, 2017.	$	5,582	$	6,740
Note payable of $28,059 to Ford Motor Credit, with monthly installments of $640, including interest at 4.54%, collateralized by a truck, maturing August 8, 2015.		12,311		19,264
Total notes payable and capital leases		17,893		26,004
Less current portion		8,703		8,111
Total long term (notes payable and capital leases)	$	9,190	$	17,893

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PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, ~~2013~~2014 AND ~~2012~~2013

~~Future~~6. NOTES ~~annual~~PAYABLE ~~maturities~~AND ofCAPITAL ~~notes payable and capital leases at December 31, 2013 are as follows:~~LEASES

Year Ended
2014	$	8,703
2015		6,745
2016		2,078
2017		367
Total	$	17,893

Notes payable and capital leases consisted of the following at December 31:

7. NOTES PAYABLE, RELATED PARTIES

	2014		2013
Capital lease of $7,592 to Xerox Corporation, with monthly installments of $198, including interest at 19.7%, maturing February 20, 2017.	$	4,198	$	5,582

Note payable of $28,059 to Ford Motor Credit, with monthly installments of $640, including interest at 4.54%, collateralized by a truck, maturing August 8, 2015.		5,035		12,311

Total notes payable and capital leases		9,233		17,893
Less current portion		6,740		8,703

Total long term (notes payable and capital leases)	$	2,493	$	9,190

~~Notes~~Future ~~payable,~~annual ~~related~~maturities ~~parties~~of ~~consisted~~notes ofpayable ~~the~~and ~~following~~capital leases at December 31, 2014 are as follows:

	2013		2012
Year Ended
Note payable to Teton, Ltd., “Teton” (the “Teton Renewal Note”) in the amount of $6,987,646 dated June 23, 2011, including interest at 8%, with all principal due on the maturity date of June 1, 2015. Renewed prior amended note which matured June 1, 2011. Secured by a stock pledge and security agreement.	$	6,987,646	$	6,987,646
2015		6,740
Original unsecured promissory note payable in the amount of $1 million dated October 14, 2009 to Teton (the “Teton Promissory”). Additional funds added by amendment two in 2010 resulted in funds available of $1.5 million, including interest of 6.25%, with all interest and principal due on the maturity date of June 1, 2015.		1,173,000		1,173,000
2016		2,078
Total notes payable, related parties		8,160,646		8,160,646
2017		415
Less current portion		-		-
2018		-
Total long-term notes payable, related parties	$	8,160,646	$	8,160,646
Total	$	9,233

7. NOTES PAYABLE, RELATED PARTY

Notes payable, related party consisted of the following at December 31:

	2014		2013
Note payable to Teton, Ltd., "Teton" (the "Teton Renewal Note") in the amount of $6,987,646 dated June 23, 2011, including interest at 8%, with all principal due on the maturity date of December 31, 2015. Secured by a stock pledge and security agreement.	$	6,987,646	$	6,987,646

Original unsecured promissory note payable in the amount of $1 million dated October 14, 2009 to Teton (the "Teton Promissory"). Additional funds added by amendment two in 2010 resulted in funds available of $1.5 million, including interest of 6.25%, with all interest and principal due on the maturity date of December 31, 2015.		1,173,000		1,173,000

Total notes payable, related party		8,160,646		8,160,646
Less current portion		8,160,646		-

Total long term notes payable, related party	$	-	$	8,160,646

Teton Renewal Note

On June 1, 2010, a Promissory (Teton Renewal Note) note was executed to renew and extend the original note payable (Teton Note) due May 21, 2010 to a maturity date of June 1, 2011. The renewal note’s principal balance of $6,987,646 is the total of the outstanding principal of $5,952,303 and accrued and unpaid interest of $1,035,343 on the original note that was added to the note. Under the original note payable, Teton was granted the right to convert the $5,792,957 of the outstanding note payable balance plus accrued interest into shares of the Company’s common stock at a fixed conversion price of $1.20 per share. A fixed conversion price of $1.60 was agreed upon for conversion of the additional funds, totaling $1,194,689 plus accrued interest, of the outstanding note payable balance. Teton has the right, but not the obligation to convert all or a portion of the indebtedness at any time after May 1, 2008, unless the debt is repaid before such date. This option will continue in existence as long as any balance remains outstanding on the note. Substantially all of the Company’s assets are pledged to secure the repayment of the Teton Renewal Note.

On April 1, 2011, an amendment was executed which extended the maturity date of the note from June 1, 2011 to June 1, 2013 at which time all outstanding principal and accrued and unpaid interest of the note will be due. The amendment also added an event of default whereby Teton may declare default on the note if the Company does not raise funds during or as a result of their engagement with a placement agent whom they initially engaged on March 25, 2011. No default was declared on this note prior to its subsequent amendment below.

On June 23, 2011, another amendment was executed which extended the maturity date of the note from June 1, 2013 to June 1, 2015, at which time all outstanding principal and accrued and unpaid interest of the note will be due. The event of default section remained the same as in the third amendment.

Teton Promissory Note

The Teton Promissory note was amended effective January 1, 2010 to eliminate the requirement of interest payments. A second amendment was executed which increased the available balance to $1,500,000 effective March 2, 2010. Effective July 1, 2010, a third amendment to the Teton Promissory was executed to continue the elimination of the interest payments and to extend the maturity date of the note to January 2, 2011. Effective January 2, 2011, a fourth amendment was executed to extend the maturity date of the note to April 2, 2011 at which time all outstanding principal and accrued and unpaid interest would be due.

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PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, ~~2013~~2014 AND ~~2012~~2013

On April 21, 2011, aan ~~fifth~~ amendment was executed which ~~eliminated the current interest payment and~~ extended the maturity date of the note from June 1, 2011 to June 1, 2013 at which time all outstanding principal and accrued and unpaid interest of the note will be due. The amendment also added an event of default whereby Teton may declare default on the note if the Company does not raise funds during or as a result of their engagement with a placement agent whom they initially engaged on March 25, 2011. No Indefault ~~addition,~~was ~~the~~declared ~~amendment granted Teton the right, to convert the outstanding balance~~ on ~~the~~this ~~Promissory~~ note ~~into~~prior ~~shares~~to ofits ~~PERC’s~~subsequent ~~common~~amendment ~~stock at a fixed conversion price of $0~~below.~~60 per share.~~

On June 23, 2011, an amendment was executed, which extended the maturity date of the note from June 1, 2013 to June 1, 2015, at which time all outstanding principal and accrued and unpaid interest of the note will be due. No default was declared on this note prior to its subsequent amendment below.

On June 24, 2014, another amendment was executed, which extended the maturity date of the note from June 1, 2015 to December 31, 2015, at which time all outstanding principal and accrued and unpaid interest of the note will be due. The event of default section remained the same as in the third amendment.

Teton Promissory Note

On April 2, 2011, a fifth amendment was executed which eliminated the current interest payment and extended the maturity of the note from to June 1, 2013 at which time all outstanding principal and accrued and unpaid interest of the note will be due. The amendment also added an event of default whereby Teton may declare default on the note if the Company does not raise funds during or as a result of their engagement with a placement agent whom they initially engaged on March 25, 2011. In addition, the amendment granted Teton the right to convert the outstanding balance on the Promissory note into shares of PERC’s common stock at a fixed conversion price of $0.60 per share.

On June 23, 2011, a sixth amendment was executed which extended the maturity date of the note to June 1, 2015, at which time all outstanding principal and accrued and unpaid interest of the note will be due. The event of default section and conversion of debt to equity section remained the same as in the fifth amendment.

On June 24, 2014, a seventh amendment was executed, which extended the maturity date of the note from June 1, 2015 to December 31, 2015, at which time all outstanding principal and accrued and unpaid interest of the note will be due. The event of default section and conversion of debt to equity section remained the same as in the fifth amendment.

The Company signed an Omnibus Waiver and Modification Agreement on December 31, 2014. This agreement subordinated the right of Teton to convert the Teton Renewal and Teton Promissory notes to the right of future investors to convert new convertible debt expected to be issued in 2015. See Note 17 – Subsequent Events.

8. ASSET RETIREMENT OBLIGATIONS

Pursuant to FASB ASC Topic No. 410, ~~Asset Retirement and Environmental Obligations,~~ the Company has recognized the fair value of its asset retirement obligations related to the plugging, abandonment, and remediation of oil and gas producing properties. The present value of the estimated asset retirement costs has been capitalized as part of the carrying amount of the related long-lived assets, which approximated $~~503~~688,~~253~~567 and $~~491~~503,~~338~~253 at December 31, ~~2013~~2014 and ~~2012~~2013, respectively.

The liability has been accreted to its present value as of the end of each year. The Company evaluated 22 wells, and has determined a range of abandonment dates through ~~June~~January ~~2027~~2044.

The following represents a reconciliation of the asset retirement obligations for the years ended December 31:

	2013			2012
	2014			2013
Asset retirement obligations at beginning of year	$	~~628~~674,~~668~~092		$	~~343~~628,~~687~~668
Asset retirement obligations incurred in the current year		13,757			-
Accretion expense		34,588			33,509
Revisions to estimates		(1,842	)		258,608
Liabilities settled		(49,586	)		-
Accretion of discount		33,509			26,373
Revisions to estimates		231,998			11,915
Asset retirement obligations at end of year	$	~~674~~891,092		$	~~628~~674,~~668~~092

In order to ensure current costs are reflected in the estimation of retirement costs, the Company obtained assurance from its independent petroleum engineer in 2013 that the plugging costs used in the estimation are appropriate. The Company uses the expected present value technique to measure the fair value of the asset retirement obligations which is classified as a Level 3 measurement under FASB ASC Topic No. 820.

9. STOCK-BASED COMPENSATION

Stock Plans

The Company adopted the 2007 Stock Option Plan (the “2007 Plan”) and 2010 Incentive Stock Option Plan (the “2010 Plan”) for directors, executives, selected employees, and consultants to reward them for making major contributions to the success of the Company by issuing long-term incentive awards under these Plans thereby providing them with an interest and incentive in the growth and performance of the Company. The 2007 Plan reserves 1,750,000 shares of common stock for issuance by the Company as stock options. The 2010 Plan reserves 5,000,000 shares of common stock for issuance by the Company as stock options, stock awards or restricted stock purchase offers.

On February 23, 2012, the Company adopted the 2012 Incentive Stock Option Plan (the “2012 Plan”) for directors, executives, and selected employees and consultants to reward them for making major contributions to the success of the Company by issuing long-term incentive awards under the 2012 Plan thereby providing them with an interest in the growth and performance of the Company. The 2012 Plan reserves 10,000,000 shares of common stock for issuance by the Company as stock options, stock awards or restricted stock purchase offers.

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Table of Contents

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, ~~2013~~2014 AND ~~2012~~2013

~~Stock~~In ~~Options~~order ~~Modified~~to ensure current costs are reflected in the estimation of retirement costs, the Company obtained assurance from its independent petroleum engineer in 2014 that the plugging costs used in the estimation are appropriate. The Company uses the expected present value technique to measure the fair value of the asset retirement obligations which is classified as a Level 3 measurement under FASB ASC Topic No. 820.

On January 5, 2012, pursuant to Board resolution, the Company changed the terms of all options granted under the 2007 Plan to extend the exercise term for two years from December 31, 2012 to December 31, 20149. The modification resulted in incremental stock compensation cost of $136,072, which was calculated as the difference in the fair value of the options immediately before and immediately after the modification using the BlackSTOCK-~~Scholes~~BASED option pricing model. The Company used the simplified method to determine the expected term on the options modified due to the lack of historical exercise data. The following table details the significant assumptions used to compute the fair value of the option modifications:COMPENSATION

	Before			After
Risk free rates		0.06	%		0.19	%
Dividend yield		0	%		0	%
Expected volatility		108.47	%		127.91	%
Remaining term (years)	0.5 years			1.5 years

Stock Plans

OnThe ~~April~~Company ~~20,~~adopted ~~2012,~~the ~~pursuant~~2007 toStock ~~Board~~Option ~~resolution,~~Plan (the ~~Company~~“2007 ~~changed~~Plan”), ~~the~~2010 ~~terms~~Incentive ofStock Option Plan (the ~~remaining~~“2010 ~~900,000~~Plan”) ~~options~~and ~~previously~~the ~~granted~~2012 ~~under~~Incentive Stock Option Plan (the ~~2007~~“2012 Plan”) tofor ~~decrease~~directors, ~~the~~executives, ~~exercise~~selected ~~price~~employees, ~~from~~and ~~$1.20~~consultants ~~per~~to ~~share~~reward them for making major contributions to ~~$0.65~~the ~~per~~success ~~share. The~~of ~~modification~~the ~~resulted~~Company inby ~~incremental~~issuing ~~stock~~long-term ~~compensation~~incentive ~~cost~~awards ofunder ~~$93,092,~~these ~~which~~plans ~~was~~thereby ~~calculated~~providing asthem ~~the~~with ~~difference~~an interest and incentive in the ~~fair~~growth ~~value~~and performance of the ~~options~~Company. The ~~immediately~~2007 ~~before~~Plan ~~and~~reserves ~~immediately~~1,750,000 ~~after~~shares ~~the~~of ~~modification~~common ~~using~~stock for issuance by the ~~Black-Scholes~~Company ~~option~~as ~~pricing~~stock ~~model~~options. The ~~Company~~2010 ~~used~~Plan ~~the~~reserves ~~simplified~~5,000,000 ~~method~~shares toof ~~determine~~common ~~the~~stock ~~expected~~for ~~term~~issuance onby the ~~options~~Company ~~modified~~as ~~due~~stock tooptions, ~~the~~stock ~~lack~~awards ofor ~~historical~~restricted ~~exercise~~stock ~~data~~purchase offers. The ~~following~~2012 ~~table~~Plan ~~details~~reserves ~~the~~10,000,000 ~~significant~~shares ~~assumptions~~of ~~used~~common tostock ~~compute~~for issuance by the ~~fair~~Company ~~value~~as ofstock ~~the~~options, ~~option~~stock ~~modifications:~~awards or restricted stock purchase offers

	Before			After
Risk free rates		0.23	%		0.23	%
Dividend yield		0	%		0	%
Expected volatility		101.77	%		101.77	%
Remaining term (years)	1.5 years			1.5 years

On May 19, 2014, the Company adopted the 2014 Incentive Stock Option Plan (the “2014 Plan”) for directors, executives, selected employees, and consultants to reward them for individual performance that contributes to the success of the Company by issuing options to purchase stock under the 2014 Plan thereby providing them with an interest in the growth and performance of the Company. Initially 10 million shares of common stock were reserved for issue under the 2014 Plan. As of December 31, 2014, these shares had been unreserved to accommodate a planned financing.

The Company has granted stock options to key employees, directors, and consultants as discussed below:

Stock Options Issued

On ~~October~~January 530, ~~2013~~2014, anpursuant ~~additional~~to 1the 2010 Plan and 2012 Plan, the Company issued stock options for 49,940 and 7,000,000 shares of ~~the~~common stock, ~~options~~respectively, ~~vested~~at inan ~~accordance~~exercise ~~with~~price ~~the~~of ~~October~~$0.79 5,per ~~2012~~share ~~award~~to ~~agreement~~selected ~~described~~employees ~~below~~and consultants for their contributions to the success of the Company. AsAll of ~~December~~the 31options vested immediately upon issuance at January 30, ~~2013~~2014, ~~the~~and ~~Company~~are ~~recognized~~exercisable ~~$655~~at any time,~~181,~~ ~~the~~in ~~fair~~whole ~~value~~or ofpart, ~~the~~until ~~vested~~January ~~options~~30, as2019. ~~stock~~This ~~based~~issuance ~~compensation~~resulted ~~expense.~~in ~~The~~stock-based ~~Company~~compensation ~~had~~of $~~393~~2,~~110~~381,979, inwhich ~~unamortized~~was ~~compensation~~calculated ~~expense~~using ~~associated~~the ~~with~~fair ~~options~~value ~~granted,~~of ~~which~~the ~~will~~options beat ~~recognized~~grant ~~during 2014~~date.

OnThe ~~October~~following 5,table ~~2012,~~details ~~pursuant to~~ the ~~2012~~significant ~~Plan,~~assumptions ~~the~~used ~~Company~~to ~~issued~~compute ~~stock~~the ~~options~~fair tomarket ~~purchase~~values ~~3,000,000 shares~~ of ~~common~~ stock ~~with an exercise price of $0.66 per share and a term of ten years to the new CFO. The~~ options ~~vest~~granted in ~~tranches~~a ofprior ~~1,000,000 each~~ year ~~over~~which ~~two years following the award issuance and 1,000,000~~ vested ~~immediately~~during ~~upon issuance. Accordingly, they are measured at fair value on~~ the ~~grant~~year ~~date~~ended ~~and the compensation expense associated with the grant will be amortized over the vesting period. As of~~ December 31, ~~2012, the Company recognized $524,145, the fair value of the vested options, as stock based compensation expense and had $1,048,291 in unamortized compensation expense associated with options granted.~~2014:

On April 30, 2012, pursuant to the 2010 Plan, the Company issued stock options for 3,000,000 shares of common stock at an exercise price of $0.55 per share to selected executives for their contributions to the success of the Company. All of the options vested immediately upon issuance at April 30, 2012, and are exercisable at any time, in whole or part, until April 30, 2017. This issuance resulted in stock based compensation expense of $1,371,766, which was calculated using the fair value of the options at grant date.

Risk free rates		0.45	%
Dividend yield		0	%
Expected volatility		70.82	%
Expected term (years)	2.5 years

On ~~January~~October 5, 2012, pursuant to the ~~2007~~2012 Plan, the Company issued stock options ~~for~~to ~~486~~purchase 3,~~364~~000,000 shares of common stock atwith an exercise price of $0.5066 per share and ~~363,636~~a ~~shares~~term of ~~common~~ten ~~stock~~years ~~at an exercise price of $0.55 per share~~ to ~~various executives, selected employees and consultants for their contributions to~~ the ~~success of the Company~~CFO. ~~All~~The ~~of the~~ options vested ~~immediately~~in ~~upon~~tranches ~~issuance~~of ~~at January 5~~1, ~~2012~~000,000 ~~and~~each ~~are~~year ~~exercisable~~over attwo ~~any~~years ~~time,~~following inthe ~~whole~~award ~~or part, until January 5, 2017. This~~ issuance ~~resulted~~and ~~in stock based compensation of $290~~1,~~735~~000,000 ~~which~~vested ~~was~~immediately ~~calculated~~upon ~~using the fair value of the options at grant date~~issuance.

On October 5, 2013, the second tranche of 1,000,000 of the stock options vested in accordance with the October 5, 2012 award agreement described above. During 2013, the Company recognized $655,181, the fair value of the vested options, as stock-based compensation expense and had $393,110 in unamortized compensation expense associated with options granted.

On October 5, 2014, the final tranche of 1,000,000 of the stock options vested in accordance with the October 5, 2012 award agreement described above. During 2014, the Company recognized $393,110, the fair value of the vested options, as stock-based compensation expense. As of December 31, 2014, the Company had no unamortized compensation expense associated with options granted.

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Table of Contents

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, ~~2013~~2014 AND ~~2012~~2013

InStock ~~addition,~~Options on January 5, 2012, pursuant to the 2010 Plan, the Company issued stock options for 880,775 shares of common stock at an exercise price of $0.50 per share to selected employees and consultants for their contributions to the success of the Company. All of the options vested immediately upon issuance at January 5, 2012, and are exercisable at any time, in whole or part, until January 5, 2017. This issuance resulted in stock based compensation of $304,078, which was calculated using the fair value of the options at grant date. Modified

~~There~~On ~~were~~January no30, ~~options~~2014, ~~granted~~pursuant ~~and~~to 1Board resolution,~~000,000~~ ~~options~~the ~~vested~~Company ~~during~~changed the ~~year~~terms ~~ended~~of ~~December~~certain ~~31,~~options ~~2013. There~~under ~~were~~the ~~7,730,775~~2007 ~~options~~Plan ~~granted~~ and 52010 Plan,~~730,775~~ ~~options~~as ~~vested~~shown ~~during~~in the ~~year~~table ~~ended~~below, ~~December~~to ~~31,~~extend ~~2012~~the exercise term for two years from their current expiration date.

A summary of option activity during the years ended December 31, 2013 and 2012 is as follows:

	Previous Expiration Date	Modified Expiration Date
Option Issue Date
2007 Plan Granted 2007	12/31/2014	12/31/2016
2007 Plan Granted 2012	1/5/2017	1/5/2019
2010 Plan Granted 2010	12/24/2015	12/24/2017
2010 Plan Granted 2012	1/5/2017	1/5/2019
2010 Plan Granted 2012	4/30/2017	4/30/2019

	Options		Weighted Average Exercise Price		Weighted Average Grant Date Fair Value
Outstanding at January 1, 2012		1,969,285	$	0.78	$	-
Options granted - January		1,730,775		0.51		0.34
Options granted - April		3,000,000		0.55		0.46
Options granted - October		3,000,000		0.66		0.52
Options exercised		-		-		-
Outstanding at December 31, 2012		9,700,060		0.57		-
Options granted		-		-		-
Options exercised		-		-		-
Outstanding at December 31, 2013		9,700,060	$	0.57	$	-

The modification resulted in incremental stock-based compensation cost of $578,255, which was calculated as the difference in the fair value of the options immediately before and immediately after the modification using the Black-Scholes option pricing model. The Company used the simplified method to determine the expected term on the options modified due to the lack of historical exercise data. The following table details the significant assumptions used to compute the fair value of the option modifications:

The following is a summary of stock options outstanding at December 31, 2013:

	Before		After
Risk free rates	0.07% to 0.24	%	0.24% to 0.48	%
Dividend yield	0	%	0	%
Expected volatility	54.65% to 58.06	%	55.10% to 73.49	%
Remaining term (years)	0.5 years to 1.63 years		1.5 years to 2.63 years

Exercise		Options		Remaining Contractual		Options
Price		Outstanding		Lives (Years)		Exercisable
$	0.65		900,000		1		900,000
$	0.42		1,059,285		2		1,059,285
$	0.50		10,000		2		10,000
$	0.50		486,364		3		486,364
$	0.55		363,636		3		363,636
$	0.50		880,775		3		880,775
$	0.55		3,000,000		3.50		3,000,000
$	0.66		3,000,000		8.75		2,000,000

The weighted average grant date fair value price per share of options granted during the year ended December 31, 2014 was $0.34. There were 7,049,940 options granted and 8,049,940 options vested during the year ended December 31, 2014. There were no options granted and 1,000,000 options vested during the year ended December 31, 2013.

~~Based~~A onsummary ~~the Company's stock price~~ of ~~$0.60~~option atactivity ~~December~~during ~~31, 2013,~~ the ~~options~~years ~~outstanding~~ended ~~had an intrinsic value of $496,567. At~~ December 31, ~~2012~~2013 ~~the Company’s stock price was $0.57~~ and ~~the~~2014 ~~options~~is ~~outstanding~~as ~~had an intrinsic value of $322,565.~~follows:

Total options exercisable at December 31, 2013 amounted to 8,700,060 shares and had a weighted average exercise price of $0.56. Upon exercise, the Company issues the full amount of shares exercisable per the term of the options from new shares. The Company has no plans to repurchase those shares in the future. The following is a summary of options exercisable at December 31, 2013 and 2012:

			Weighted Average
	Options		Exercise Price

Outstanding at January 1, 2013		9,700,060		0.57
Options granted		-		-
Options exercised		-		-
Outstanding at December 31, 2013		9,700,060		0.57
Options granted		7,049,940		0.79
Options exercised		-		-
Outstanding at December 31, 2014		16,750,000		0.66

			Weighted Average
	Shares		Exercise Price
December 31, 2013		8,700,060	$	0.56
December 31, 2012		7,700,060	$	0.55

A summary of stock options outstanding as of December 31, 2014 is as follows:

The Company estimates the fair value of stock options using the Black-Scholes option pricing valuation model, consistent with the provisions of FASB ASC Topic 505 and FASB ASC Topic 718. Key inputs and assumptions used to estimate the fair value of stock options include the grant price of the award, the expected option term, volatility of the Company’s stock, the risk-free rate and the Company’s dividend yield. Estimates of fair value are not intended to predict actual future events or the value ultimately realized by grantees, and subsequent events are not indicative of the reasonableness of the original estimates of fair value made by the Company. The Company uses the simplified method to determine the expected term on options issued.

Exercise Price		Options Outstanding		Remaining Contractual Lives (Years)		Options Exercisable
$	0.65		900,000		2.00		900,000
$	0.42		1,059,285		3.00		1,059,285
$	0.50		10,000		3.00		10,000
$	0.50		486,364		4.00		486,364
$	0.55		363,636		4.00		363,636
$	0.50		616,600		4.00		616,600
$	0.79		7,049,940		4.00		7,049,940
$	0.55		3,000,000		4.50		3,000,000
$	0.50		264,175		7.00		264,175
$	0.66		3,000,000		7.75		3,000,000
			16,750,000				16,750,000

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PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, ~~2013~~2014 AND ~~2012~~2013

~~The~~Based ~~following~~on ~~table~~the ~~details~~Company's ~~the~~stock ~~significant~~price ~~assumptions~~of ~~used~~$0.16 toat ~~compute~~December 31, 2014, the ~~fair~~options ~~market~~outstanding ~~values~~had an intrinsic value of ~~stock~~$0. At ~~options~~December ~~granted~~31, or2013, ~~revalued~~the ~~during~~Company’s stock price was $0.60 and the ~~years~~options ~~ended~~outstanding ~~December~~had ~~31:~~an intrinsic value of $496,567.

	2013							2012
Risk free rates		0.71	%	to		0.79	%		0.33	%	to		0.63	%
Dividend yield						0	%						0	%
Expected volatility		106.86	%	to		102.70	%		111.85	%	to		128.20	%
Remaining term (years)	5.5 years			to	6 years			2.5 years			to	5.0 years

Total options exercisable at December 31, 2014 amounted to 16,750,000 shares and had a weighted average exercise price of $0.66. Total options exercisable at December 31, 2013 amounted to 8,700,060 and had a weighted average exercise price of $0.56. Upon exercise, the Company issues the full amount of shares exercisable per the term of the options from new shares. The Company has no plans to repurchase those shares in the future.

10. WARRANTS OUTSTANDING

In December 2007, the Company issued 8,375,784 warrants to purchase 4,187,901 shares of common stock exercisable until December 31, 2012 in connection with a securities placement agreement. Also in December 2007 and January 2008, the Company issued warrants to placement agents to purchase 847,465 shares of common stock as part of a securities purchase offering. The warrants had an exercise price of $1.60 per share and could also be exercised on a cashless basis for a reduced number of shares.

The 2007 Warrant Agreement contained anti-dilution protection rights (“ratchet provision”) which required an adjustment to the exercise price of the warrants and a proportional adjustment to the number of shares of common stock issuable upon exercise of the warrants in the event the Company issues common stock, stock options, or securities convertible into or exercisable for common stock, at a price per share lower than such exercise price.

During 2011, the Company issued common shares at a price per share lower than the current exercise price, which triggered the ratchet provision of the 2007 Warrants. The effect of the anti-dilution provision resulted in an adjustment to the number of shares of common stock issuable upon exercise of the warrants.

Warrants Modified

During 2011, the Company offered holders of its 2007 Warrants an option to consider modification of the warrant agreements. The terms of the modification offer would: (1) waive all prior registration rights penalties, (2) remove the cashless exercise feature, (3) change the exercise price from $0.40 to $0.50, (4) extend the exercise term of the warrants by two years, and (5) delete the full-ratchet provisions. The removal of the cashless exercise feature effectively made the Company liable for a potential registration rights penalty effective sixty days after the agreements were signed. In March 2012, the Company offered the holders who had signed the 2011 modification agreement two rescission options which would correct the registration rights penalty liability. Rescission Option A reverted the warrant back to its original 2007 terms with the original expiration date of December 31, 2012. Rescission Option B corrected the cashless exercise feature but retained all other modifications as noted above. See Note 17, Commitments and Contingencies, for further explanation of the registration rights penalty. The deletion of the full-ratchet provision resulted in a reclassification of the derivative liability on the signed agreements to additional paid-in capital. See Note 12, Derivative Warrant Liability, for further explanation.

After the trigger of the ratchet provision, the modification of the 2007 warrants described above and subsequent cashless exercises of the 2007 warrants during 2011 there were 24,397,812 shares of common stock issuable upon exercise of the warrants with an exercise price of $0.40 remaining as of January 1, 2012.

During the first quarter of 2012, additional 2007 Warrant agreements representing 1,760,000 shares were modified under the terms above and resulted in warrant modification expense of $260,554, which was calculated as the difference in the fair value of the warrants immediately before and immediately after the modification using the Black-Scholes option pricing model. The following table details the significant assumptions used to compute the fair market value of the warrant modifications:

	Before							After
Risk free rates		0.11	%	to		0.14	%		0.34	%			0.34	%
Dividend yield		0	%						0	%
Expected volatility		110.28	%	to		110.68	%		129.35	%	to		131.00	%
Remaining term (years)	0.83 years			to	0.96 years			2.83 years			to	2.95 years

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PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

During the third quarter of 2012, additional 2007 Warrants representing 200,000 shares were also modified under the terms above and resulted in a warrant modification expense of $33,980 which was calculated as the difference in the fair value of the warrants immediately before and immediately after the modification using the Black-Scholes option pricing model. The following table details the significant assumptions used to compute the fair market value of the warrant modifications:

	Before			After
Risk free rates		0.02	%		0.81	%
Dividend yield		0	%		0	%
Expected volatility		39.32	%		112.29	%
Remaining term (years)	0.21 years			2.25 years

The total warrant modification expense of $294,534 for the year ended December 31, 2012, was reported in the Other Income (Expense) section of the consolidated statements of operations.

Warrants Issued

On February 27, 2014, the Company issued warrants to investors in a private placement to purchase an aggregate of 781,000 shares of common stock at an exercise price of $0.70 per share, exercisable until February 27, 2019. See Note 11 for additional information.

On December 20, 2013, the Company issued warrants to investors in a private placement to purchase an aggregate of 1,944,119 shares of common stock at an exercise price of $0.70 per share, exercisable until December 20, 2018. On December 30, 2013, during the same private placement, the Company issued warrants to investors to purchase an aggregate of 55,555 shares of common stock at an exercise price of $0.70 per share, exercisable until December 30, 2018. See Note 11 for additional information.

On September 17, 2013, the Company issued warrants to investors in a private placement to purchase an aggregate of 250,000 shares of common stock at an exercise price of $1.00 per share, exercisable until September 17, 2016. See Note 11 for additional information.

During September 2013, the Company issued warrants to three investors who had held original 2007 warrants which expired in December 2012. These investors claimed they had not received the 2011 modification agreement and in connection with the execution of a settlement agreement to resolve any disputes between the Company and such investors, the Company issued an aggregate of 645,968 warrants to these investors to purchase 645,968 shares of common stock at an exercise price of $0.50 per share, exercisable until December 22, 2014. The terms of the warrants issued were the same as the 2007 warrants, as modified by the 2011 modification agreement. Warrant settlement expense of $134,102 due to this settlement was recognized for the year ended December 31, 2013, and was reported in the Other Income (Expense) section of the consolidated statements of operations.

In September 2012, the Company issued warrants to investors in a private placement transaction. See Note 11 for additional information. The Company issued warrants to investors to purchase 3,355,223 shares of common stock at an exercise price of $1.00 per share, exercisable until September 10, 2015. The Company also issued warrants to placement agents used in the offering to purchase 100,638 shares of common stock exercisable until September 10, 2017.

Warrants Exercised

On March 18, 2013, the Company issued 95,299 shares of common stock to an investor holding modified 2007 warrants who exercised 100,000 warrants of their 1,000,000 warrants on a cashless basis. On March 22, 2013, the Company issued 149,760 shares of common stock to the same investor holding modified 2007 warrants who exercised 150,000 warrants of their remaining 900,000 warrants on a cashless basis. On April 5, 2013, the Company issued 765,139 shares of common stock to the same investor upon a cashless exercise of the remaining warrants to purchase 1,500,000 shares.

On May 1, 2013, the Company issued 8,000 shares of common stock for $4,800 to an investor holding 2011 Warrants who exercised 8,000 warrants on a cash basis.

On ~~March~~February 1811, ~~2013~~2014, the Company issued 956,~~299~~380 shares of common stock to an investor holding modified 2007 ~~Warrants who exercised 100,000~~ warrants ~~of their 1,000,000 warrants on a cashless basis. On March 22, 2013, the Company issued 149,760 shares of common stock to the same investor holding modified 2007 Warrants~~ who exercised ~~150~~10,000 warrants ~~of their remaining 900,000 warrants~~ on a cashless basis. ~~On April 5, 2013, the Company issued 765,139 shares of common stock to the same investor upon a cashless exercise of the remaining warrants to purchase 1,500,000 shares.~~

InOn ~~March~~April ~~2012~~2, ~~a holder of the 2007 Warrants exercised their 407~~2014,~~592~~ ~~warrants to acquire 1,630,368 shares on a cashless basis and received 776,884 shares of~~ the Company’s ~~common~~issued ~~stock. In May 2012~~23,226 ~~a holder of the 2007 warrants exercised their 175,300 warrants to acquire 701,200~~ shares ~~on a cashless basis and received 365,617 shares~~ of ~~the Company’s~~ common stock. Into ~~July~~an ~~2012,~~investor aholding ~~holder~~modified ~~of the~~ 2007 ~~Warrants exercised their 20,833~~ warrants towho ~~acquire 41,668 shares on a cashless basis and received 24,133 shares of the Company’s common stock. In December 2012, holders of the 2007 Warrants~~ exercised ~~their 60~~30,000 warrants ~~to acquire 120,000 shares~~ on a cashless basis ~~and received 27,173 shares of the Company’s common stock~~.

On July 28, 2014, the Company issued 7,970 shares of common stock to an investor holding 2011 Warrants who exercised 7,970 warrants for proceeds of $4,782.

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PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2014 AND 2013

Warrants Expired

OnIn ~~December~~July 212014, ~~2012,~~ the remaining 123,~~263,856~~930 ~~2007~~July ~~Warrants~~2011 warrants, representing 323,~~056,864~~930 shares, ~~which~~that had not been exercised or modified, expired under the provisions of the original warrant agreement.

In September 2014, the remaining 50,000 September 2011 warrants, representing 50,000 shares that had not been exercised or modified, expired under the provisions of the original warrant agreement.

In December 2014, the remaining 226,000 September 2013 warrants, representing 226,000 shares that had not been exercised or modified, expired under the provisions of the original warrant agreement.

Also in December 2014, the remaining 1,952,333 2007 warrants modified in 2011, representing 3,904,666 shares, expired under the provisions of the 2011 amended warrant agreement, which had extended the exercise term of the warrants by two years to December 31, 2014.

Warrants Modified

During the first quarter of 2014, the Company offered holders of certain warrants an option to consider modification of the warrants. The terms of the offer would (1) extend the exercise term of the warrants by three years, and (2) increase the exercise price of the warrants, which would be exercisable on a cash-only basis. The deadline for accepting this offer was March 31, 2014.

Pursuant to the 2014 modification agreement, the Company changed the terms of warrants to purchase an aggregate of 14,880,762 shares to increase their exercise price and to extend the exercise term by three years. See the table below for a summary of the modifications for the various outstanding warrants.

	Current Exercise Price		Modified Exercise Price		Previous Expiration Date			Modified Expiration Date
Warrant Issue Date
Issued in 2007 and modified in 2012	$	0.50	$	0.70			12/22/14			12/22/2017
Issued in July 2011	$	0.60	$	0.85			7/28/2014			7/28/2017
Issued in Sept 2011	$	0.60	$	0.85			9/15/2014			9/15/2017
Issued in Sept 2012	$	1.00	$	1.15	9/10/15	and	9/28/15	9/10/18	and	9/28/18
Issued in Sept 2012 to placement agents	$	0.60	$	0.70			9/28/2017			9/28/2020
Issued in Sept 2013	$	0.50	$	0.70			12/22/2014			12/22/2017
Issued in Sept 2013	$	1.00	$	1.10			9/19/2016			9/19/2019

The modification resulted in warrant modification expense of $2,642,266, which was recorded in the quarter ended March 31, 2014. This modification was calculated as the difference in the fair value of the warrants immediately before and immediately after the modification using the Black-Scholes option pricing model.

The following table details the significant assumptions used to compute the fair market value of the warrant modifications:

	Before		After
Risk free rates	0.08% to 0.99	%	0.99% to 2.07	%
Dividend yield	0	%	0	%
Expected volatility	52.24 % to 83.24	%	78.94 % to 106.11	%
Remaining term (years)	0.35 years to 3.53 years		3.33 years to 6.53 years

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Table of Contents

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, ~~2013~~2014 AND ~~2012~~2013

A summary of warrant activity and shares issuable upon exercise of the warrants during the years ended December 31, ~~2013~~2014 and ~~2012~~2013 is as follows:

	Warrants			Shares Issuable Under Warrants			Weighted Average Exercise Price
Outstanding at January 1, 2012		14,562,930			24,397,812		$	0.52
Outstanding at January 1, 2013		16,091,210			22,303,573		$	0.65
Warrants cancelled under modification		(980,000	)		(1,960,000	)		0.40
Warrants issued under modification		980,000			1,960,000			0.50
Warrants issued		3,455,861			3,455,861			1.00
Warrants exercised		(663,725	)		(2,493,236	)		0.40
Warrants expired		(1,263,856	)		(3,056,864	)		0.40
Outstanding at December 31, 2012		16,091,210			22,303,573			0.65
Warrants issued		2,895,642			2,895,642			0.68
Warrants exercised		(1,008,000	)		(2,008,000	)		0.50
Outstanding at December 31, 2013		17,978,852			23,191,215		$	0.66
Warrants cancelled under modification		(11,660,762	)		(14,880,762	)		0.63
Warrants issued under modification		11,660,762			14,880,762			0.84
Warrants issued		781,000			781,000			0.70
Warrants exercised		(47,970	)		(87,970	)		0.52
Warrants expired		(2,252,263	)		(4,204,596	)		0.50
Outstanding at December 31, 2014		16,459,619			19,679,649		$	0.80

The outstanding warrants had an intrinsic value of $0 and $585,830 at December 31, 2014 and December 31, 2013, respectively. All of the 1716,~~978~~459,~~852~~619 warrants outstanding at December 31, ~~2013~~2014 are exercisable and expire at various dates between ~~July~~September ~~2014~~2015 and ~~December~~September ~~2018~~2020.

11. STOCKHOLDER’S EQUITY

~~Share~~Shares ~~Capital~~issued for cash, net of share issuance costs:

On ~~October~~February 1827, ~~2012~~2014, the Company’s ~~Board~~completed ofa ~~Directors~~private ~~and~~placement atransaction, ~~majority~~pursuant ofto ~~its~~which ~~shareholders~~it ~~approved~~sold an ~~amendment~~aggregate toof ~~the~~781,000 ~~Articles~~units at $0.90 per unit, raising gross proceeds of ~~Incorporation~~$702,900 before deducting issuance costs of ~~the~~$8,000, ~~Company~~resulting toin ~~increase~~net ~~the~~cash ~~number~~proceeds of ~~authorized~~$694,900. Each unit consisted of two shares of common stock, ~~par~~and ~~value~~a warrant to purchase one share of common stock with an exercise price of $0.~~001~~70 per share, toresulting ~~150~~in 1,~~000~~562,000 shares and 781,000 warrants issued. The ~~amendment~~warrants ~~retained~~are ~~the~~exercisable ~~authorized~~for ~~5,000,000~~a ~~shares~~period of ~~blank-check~~five ~~preferred~~years ~~stock,~~from ~~par~~the ~~value~~date $of issuance.~~001.~~

Common Stock Issuances

Stock issued for cash, net of share issuance costs:

On December 20, 2013, the Company completed a private placement transaction, pursuant to which it sold an aggregate of 1,944,119 units at $0.90 per unit to raise gross proceeds of $1,749,707 before deducting issuance costs of $45,475, resulting in net cash proceeds of $1,704,232. Each unit consisted of two shares of common stock and a warrant to purchase one share of common stock with an exercise price of $0.70 per share, exercisable for a period of five years from the date of issuance. On December 30, 2013, the Company sold an additional 55,555 of the same units, resulting in cash proceeds of $50,000.

On September 17, 2013, the Company completed a private placement transaction, pursuant to which it sold an aggregate of 250,000 units at $1.00 per unit to raise gross proceeds of $250,000 before deducting issuance costs of $5,000, resulting in net cash proceeds of $245,000. Each unit consisted of two shares of common stock and a warrant to purchase one share of common stock with an exercise price of $1.00 per share, exercisable for a period of three years from the date of issuance.

OnStock ~~September 10, 2012, the Company completed phase one of a private placement memorandum~~ issued on ~~July 27, 2012, in which it sold 3,342,390 units at $1.20 per unit to raise gross proceeds of $4,010,720, before deducting financing costs of $125,325 and legal fees of $30,000, resulting in net~~ cash/cashless proceeds of $3,855,395. Each unit consisted of two shares of common stock, $.001 par value per share, resulting in 6,684,780 shares, and a warrant to purchase one share of common stock totaling 3,342,390 warrants with an exercise price of $1.00 per share, exercisable for a period of three years from the date of issuance.basis:

On ~~September~~February 2811, ~~2012~~2014, the Company ~~completed~~issued ~~phase~~6,380 ~~two~~shares of ~~the~~common ~~previously~~stock ~~discussed~~to ~~private placement memorandum in which~~ an ~~additional~~investor ~~12,833~~holding ~~units~~modified ~~were~~2007 ~~sold~~Warrants atwho ~~$1.20~~exercised ~~per unit to raise gross proceeds of $15~~10,~~361,~~000 ~~before deducting financing fees of $115 and legal fees of $2,500, resulting in net cash proceeds of $12,746. Each unit contained the same ratio of~~ warrants ~~and~~on ~~shares~~a ascashless ~~in phase one resulting in the additional issuance of 25,666 shares, $~~basis.~~001~~ See ~~par~~Note ~~value~~10 ~~per share, and 12,833 warrants to purchase one share of common stock with an exercise price of $1.00 per share, exercisable~~ for aadditional ~~period of three years from the date of issuance~~details.

On ~~March~~April 92, ~~2012~~2014, the Company ~~completed~~issued ~~a stock purchase agreement in which it sold 4~~23,~~444,445~~226 shares of common stock, ~~$.001 par value per share, at a price of $0.45 per share~~ to ~~raise~~an ~~gross~~investor ~~proceeds~~holding ofmodified ~~$2,000,000,~~2007 ~~before~~Warrants ~~deducting~~who ~~offering~~exercised ~~expenses of $10~~30,000 ~~and~~warrants ~~related~~on ~~closing~~a ~~costs~~cashless ofbasis. See ~~$3,055,~~Note ~~resulting~~10 infor ~~net~~additional ~~cash proceeds of $1,986,945~~details.

On July 28, 2014, the Company issued 7,970 shares of common stock to an investor holding 2011 Warrants who exercised 7,970 warrants on a cash basis. See Note 10 for additional details.

During 2013, the Company issued 1,010,198 shares of common stock to an investor holding modified 2007 Warrants who exercised 1,000,000 warrants on a cashless basis. The Company also issued 8,000 shares of common stock for $4,800 to an investor holding 2011 Warrants who exercised 8,000 warrants on the cash basis. See Note 10 for additional details.

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Table of Contents

PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, ~~2013~~2014 AND ~~2012~~2013

Stock issued on cash/cashless basis:

During 2012, the Company issued 1,193,807 shares of common stock to investors and placement agencies holding 2007 Warrants who exercised their warrants on a cashless basis. See Note 10 for additional details.

Stock issued for services:

On ~~August~~March 2227, ~~2013~~2014, the Company issued 5090,000 shares of common stock to a consultant valued at $3572,~~500~~000. These shares were valued using the closing market price on the date of the ~~grant~~agreement. This expense has been recorded as general and administrative expense in the consolidated statements of operations.

On ~~February~~April 1611, ~~2012~~2014, ~~the~~a ~~Company~~consultant ~~issued~~voluntarily 50cancelled 25,000 shares of common stock toof ~~consultants~~the ~~valued~~total ~~at $26~~50,~~500. On~~000 ~~May~~shares ~~22,~~originally ~~2012, the Company~~ issued ~~600,000~~in ~~shares~~August of2013 ~~common~~due ~~stock~~ to ~~consultants~~their ~~valued~~inability atto ~~$408,000. On~~engage ~~October~~new ~~11,~~investors ~~2012,~~for the Company. ~~issued~~The ~~650,000~~cancelled shares ofwere ~~common~~originally ~~stock to consultants~~ valued at $~~461~~17,~~000.~~250 ~~These~~and ~~shares~~a ~~were~~credit ~~valued using the closing market price on the date~~ of ~~each~~this ~~grant. These~~amount ~~expenses~~has ~~have~~ been recorded aswithin general and administrative expense in the consolidated statements of operations.

12During 2014, the Company issued 200,000 shares of common stock to a consultant in payment of services under an agreement whereby shares were to be issued at the end of each month. These shares were valued using the closing market price on the date prior to issue. ~~DERIVATIVE~~The ~~WARRANT~~Company ~~LIABILITY~~issued 50,000 shares of common stock to the consultant on each of the following dates: on April 2 for a value of $45,000, on May 1 for a value of $38,500, on June 4 for a value of $35,000 and on July 1 for a value of $30,000. These expenses were recorded as general and administrative expenses in the consolidated statements of operations.

~~Under~~On ~~FASB~~August ~~ASC Topic 815~~22, ~~Derivatives and Hedging~~2013, the ~~fair~~Company ~~value~~issued of50,000 ~~certain~~shares of ~~our~~common ~~warrants~~stock isto ~~recorded~~another asconsultant avalued ~~derivative~~at ~~liability~~$35,500. ~~Each~~ ~~reporting~~These ~~period,~~shares ~~the~~were ~~derivative liability related to these warrants is fair~~ valued ~~with~~using the ~~non-cash~~closing ~~gain~~market orprice ~~loss~~on ~~recorded in~~ the ~~period~~date asof ~~Other~~the ~~Income/Expense~~grant. ~~Since~~This ~~the~~expense ~~exercise~~has ~~price~~been ofrecorded ~~the~~as ~~warrants~~general ~~can be potentially decreased~~ and ~~the~~administrative ~~number~~expense ~~of shares to settle the warrants increased each time a trigger event occurs that results~~ in ~~a new adjusted exercise price below~~ the ~~adjusted~~consolidated ~~exercise~~statements ~~price then in effect, there could be a potentially infinite number~~ of ~~shares required to settle the warrant agreement~~operations. ~~However, the Company has the capability of limiting the occurrence of such events.~~

~~During~~Other ~~2012,~~stock various investors and placement agents exercised 642,892 of the 2007 Warrants representing 2,451,568 shares on a cashless basis. This reduced the derivative liability by $1,128,828 and increased additional paid-in capital by the same amount.issuances:

~~During~~On ~~2012~~May 1, ~~pursuant~~2014, to the ~~warrant~~Company ~~modification~~and Energi Drilling 2010A L.P. (“Energi”) entered into an agreement ~~discussed~~with respect to working interests in ~~Note~~the ~~10,~~following wells operated by the Company: ~~modified~~(i) ~~additional~~Haggard ~~2007~~B; ~~Warrant~~and ~~agreements~~the ~~representing~~(ii) Morse #1~~,960,000~~-H ~~shares~~well. toThe ~~eliminate~~agreement ~~the~~also ~~ratchet~~covered ~~provision~~all ~~contained~~of inEnergi’s ~~the~~rights ~~original~~to ~~agreements. Since~~participate ~~these~~in ~~agreements~~future nowells ~~longer~~and ~~had~~work-overs ~~derivative~~of ~~features~~existing aswells. The aCompany ~~result~~purchased all of ~~the~~Energi’s ~~modification~~right, title and interest in the ~~amount~~wells and all of ~~derivative~~Energi’s ~~warrant~~participation ~~liabilities~~rights ~~associated~~in ~~with~~future ~~the~~wells ~~shares~~and ~~have~~work-overs ~~been~~and ~~reclassified~~released Energi from ~~derivative~~any ~~warrant~~receivables ~~liabilities~~owed to ~~additional~~the ~~paid~~Company. In consideration for the buy-inout ~~capital.~~and ~~The~~release ~~amount~~of ~~reclassified~~debt, ~~due~~the Company issued 505,000 fully-paid and non-assessable shares of common stock to ~~this~~Energi. ~~modification~~These ~~was~~shares were valued at $~~731~~404,~~524~~000, using the closing market price on the date of the agreement.

~~In December 2012, the remaining 1,263,856 of the 2007 Warrants representing 3,056,864 shares of common stock expired pursuant to the terms of the original agreement~~12. INCOME TAXES

As of December 31, 2013 and 2012, the Company had no derivate warrant liabilities. The Company recognized a non-cash gain of $-0- and a non-cash gain of $88,868 during the twelve months ended December 31, 2013 and 2012, respectively.

13. INCOME TAXES

The Company is a taxable corporation and the provision (benefit) for federal income taxes related to the Company’s operating results has been included in the accompanying consolidated statements of operations.

The income tax expense consists of the following:

	2013		2012
	2014		2013
Deferred income tax expense:
U.S. Federal	$	-	$	-
Current income tax expense:
State and local		-		~~3,515~~-
Income tax expense	$	-	$	~~3,515~~-

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PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, ~~2013~~2014 AND ~~2012~~2013

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities, at December 31, are presented below:

	2013			2012
	2014			2013
Deferred tax assets:
Net operating loss carry forwards	$	78,~~081~~556,~~252~~037		$	67,~~284~~081,~~933~~252
Deferred interest expense		1,~~131~~346,~~484~~475			~~916~~1,~~497~~131,484
Liquidated damages payable		1116,~~648~~595			11,648
Accretion expense		5868,~~085~~859			4858,~~880~~085
Contributions carry forward		~~323~~289			~~765~~323
Accrued salaries		~~797~~952,~~431~~178			~~645~~797,~~451~~431
Stock based compensation		~~848~~1,~~835~~892,128			~~659~~848,~~488~~835
Valuation allowance		(46,~~135~~165,~~602~~713	)		(24,~~962~~135,~~046~~602	)
Total deferred tax assets		56,~~793~~666,~~456~~848			5,~~605~~793,~~616~~456
Deferred tax liabilities:
Oil and gas properties		(56,~~646~~522,~~984~~699	)		(5,~~463~~646,~~819~~984	)
Fixed assets and organization costs		(~~146~~144,~~472~~149	)		(~~141~~146,~~797~~472	)
Total deferred tax liabilities		(56,~~793~~666,~~456~~848	)		(5,~~605~~793,~~616~~456	)
Net deferred tax liability	$	-		$	-

Based on the future reversal of existing taxable temporary differences and future earnings expectations, management believes it is more likely than not that the full amount of the net operating loss carry forwards will not be realized or settled, and accordingly, a valuation allowance has been recorded. The Company’s net operating loss carry forwards approximate $2025,~~800~~200,000 and will expire in various years commencing in 2023.

A reconciliation of the differences between the Company’s applicable statutory tax rate and its effective income tax rate for the years ended December 31, ~~2013~~2014 and ~~2012~~2013 follows:

	2013			2012
	2014			2013
Rate		35	%		35	%
Tax at statutory rate	$	(13,~~296~~118,~~587~~713	)	$	(21,~~217~~296,~~919~~587	)
State taxes		-			~~3,515~~-
Permanent and other		~~123~~1,~~030~~088,602			~~262~~123,~~186~~030
Change in valuation allowance		12,~~173~~030,~~557~~111			1,~~955~~173,~~733~~557
Income tax expense (benefit)	$	-		$	3,515
Income tax expense	$	-		$	-

In May 2006, the ~~State~~state of Texas enacted legislation for a Texas margin tax which restructured the state business tax by replacing the taxable capital and earned surplus components of the franchise tax with a new “taxable margin” component. The Company’s margin tax expense is derived by multiplying its taxable margin by approximately 1%. The taxable margin can be derived, at the Company’s discretion, in any one of three ways. The Company can choose gross receipts less its cost of goods sold, gross receipts less its salary and wages, or 70% of its gross receipts. The Company has determined the margin tax is an income tax and the effect on deferred tax assets and liabilities should be included in the deferred tax calculation. No material margin tax accrual was necessary at December 31, ~~2013~~2014 or ~~2012~~2013.

The Company files tax returns in the U.S. federal jurisdiction, and the state of Texas jurisdiction. The Company is currently subject to a three year statute of limitations by major tax jurisdictions. The Company follows the provisions of uncertain tax provisions as addressed in FASB ASC 740-10. The Company recognized no increase in the liability for unrecognized tax benefits. The Company had no tax positions at December 31, ~~2013~~2014 or December 31, ~~2012~~2013 for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. At December 31, ~~2013~~2014, the Company’s tax returns relating to fiscal years ended December 31, ~~2009~~2011 through December 31, ~~2012~~2013 remain open to possible examination by the tax authorities. The Company recognizes interest accrued related to unrecognized tax benefits in interest expense and penalties in operating expenses. No such interest or penalties were recognized during the periods presented. The Company had no accruals for interest and penalties at December 31, ~~2013~~2014 and ~~2012~~2013.

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PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, ~~2013~~2014 AND ~~2012~~2013

1413. SEGMENT INFORMATION

The following information is presented in accordance with FASB ASC Topic 280, Segment Reporting. The Company is engaged in exploration and production of crude oil and natural gas and pipeline transportation. POI, a wholly-owned subsidiary of PERC, conducts the exploration and production operations. TR Rodessa, operates a 40-mile gas pipeline and gathering system which is used to transport hydrocarbons to market to be sold. The Company identified such segments based on management responsibility and the nature of their products, services, and costs. There are no major distinctions in geographical areas served as all operations are in the United States. The Company measures segment profit (loss) as income (loss) from operations. Business segment assets are those assets controlled by each reportable segment. ~~The following table sets forth certain information about the financial information of each segment for the years ended December 31, 2013 and 2012:~~

	Year Ended December 31,
	2013			2012
Business segment revenue:
Oil and gas sales	$	1,628,806		$	1,359,525
Condensate and skim oil		41,782			42,643
Transportation and gathering		206,041			144,693
Total revenues	$	1,876,629		$	1,546,861
Business segment profit (loss):
Oil and gas sales	$	163,749		$	358,119
Condensate and skim oil		41,782			42,643
Transportation and gathering		(67,699	)		(58,632	)
General corporate		(3,067,473	)		(6,196,340	)
Loss from operations	$	(2,929,641	)	$	(5,854,210	)

The following tables set forth certain information about the financial information of each segment for the years ended December 31, 2014 and 2013:

	Year Ended December 31,
	2013			2012
	2014			2013
Depletion and depreciation:
Business segment revenue:
Oil and gas sales	$	~~390~~1,~~591~~704,757		$	~~353~~1,~~657~~628,806
Transportation and gathering		66,171			54,749
Condensate and skim oil		27,807			41,782
General corporate		13,977			19,295
Transportation and gathering		267,391			206,041
Total depletion and depreciation	$	470,739		$	427,701
Total revenues	$	1,999,955		$	1,876,629
Capital expenditures:
Business segment profit (loss):
Oil and gas sales	$	1296,~~598,429~~892		$	7163,~~864,643~~749
Transportation and gathering		11,660			244,937
Condensate and skim oil		27,807			41,782
General corporate		232			8,187
Transportation and gathering		(76,891	)		(67,699	)
Total capital expenditures	$	1,610,321		$	8,117,767
General corporate		(5,873,564	)		(3,067,473	)
Loss from operations	$	(5,625,756	)	$	(2,929,641	)
Depreciation and depletion:
Oil and gas sales	$	520,824		$	390,591
Transportation and gathering		69,427			66,171
General corporate		11,614			13,977
Total depletion and depreciation	$	601,865		$	470,739

	December 31,
	Year Ended December 31,
	2013		2012
	2014		2013
Business segment assets:
Capital expenditures:
Oil and gas sales	$	32688,~~194,260~~979	$	301,~~101~~598,~~703~~429
Transportation and gathering		~~717~~34,~~450~~669		~~770~~11,~~822~~660
General corporate		14,~~419,750~~901		~~2,806,463~~232
Total assets	$	34,331,460	$	33,678,988
Total capital expenditures	$	728,549	$	1,610,321

	December 31,
	2014		2013
Business segment assets:
Oil and gas sales	$	31,791,516	$	32,194,260
Transportation and gathering		697,075		717,450
General corporate		799,321		1,419,750
Total assets	$	33,287,912	$	34,331,460

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PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, ~~2013~~2014 AND ~~2012~~2013

1514. RELATED PARTY TRANSACTIONS

The Company entered into various transactions with related parties as follows. These amounts have been recorded at the exchange amount, being the amount agreed to by the parties:

Years ended December 31	2013		2012
Years ended December 31,	2014		2013
Lease bonus paid to an entity controlled by officers	$	~~1,149~~250	$	-1,149
Rent paid to an entity controlled by other entities which are owned by PERC officers (c)		72,000		5772,000
Interest expense to an entity controlled by officers		632,~~316~~328		632,316
Receivables due from entities that are owned by officers and/or other entities that are controlled by officers		2640,~~584~~002		1326,~~002~~584
JIB receivables due from an entity controlled by an officer or director		~~119~~58,~~188~~727		1119,~~388,969~~188
Payables due to officers or to entities controlled by officers (a) (b)		23,~~924~~450,~~089~~175		2,~~447~~924,~~387~~089
Interest payable on notes owed to an entity controlled by officers		2,~~291~~923,~~652~~980		12,~~659~~291,~~336~~652
Notes payable owed to an entity controlled by officers		8,160,646		8,160,646
Revenue distribution payable due to an entity controlled by a director		3520,~~306~~433		4435,~~621~~306
Restricted cash owed for drilling that is due from an entity controlled by a director		2,419		-
Restricted cash received for drilling from an entity controlled by an officer or director		54,916		83,249
Promote received from an entity controlled by a director		-		100,152
Management consulting fees paid to an officer prior to employment		-		116,719

(a) Includes $2,~~325~~800,523 and $12,~~898~~325,~~386~~523 of accrued salaries payable at December 31, ~~2013~~2014 and ~~2012~~2013, respectively. Also includes $240,000 of advances from officers at December 31, ~~2013~~2014 and ~~2012~~2013.

(b) Includes $~~122~~127,~~566~~652 and $~~112~~122,~~502~~566 owed to an entity controlled by an officer for a 20% undivided interest in pipeline operations as of December 31, ~~2013~~2014 and ~~2012~~2013, respectively.

(c) The Company ~~leases~~rents office space under a non-cancelable operating lease with related parties that expired on January 1, 2012. This lease has not been renewed and the space is being ~~leased~~rented on a month -to -month basis.

1615. RISK CONCENTRATIONS

WeThe ~~maintain~~Company ~~our~~maintains its deposits in one financial institution, which at times may exceed amounts covered by insurance provided by the U.S. Federal Deposit Insurance Corporation (“FDIC”). The Company also maintains a sweep investment account which covers all of ~~our~~its bank accounts in order to reduce fees and earn maximum interest. The balance in the sweep investment account is invested daily in federal obligations that are not covered by FDIC insurance. The balance available for investment in the sweep account was approximately $~~2.7~~870,000 ~~million~~ at December 31, ~~2013~~2014 and $12.67 million at December 31, ~~2012~~2013. The Company has not experienced any losses with respect to uninsured balances. During 2014 and 2013, all balances in U.S. non-interest bearing accounts were insured up to $250,000. ~~During 2012, all balances in U.S. non-interest bearing accounts were fully insured.~~

Two customers accounted for approximately 4933% and 4158%, respectively, of the Company’s total sales for the year ended December 31, ~~2013~~2014. Two customers accounted for approximately 6749% and 2741%, respectively, of the Company’s total sales for the year ended December 31, ~~2012~~2013. Revenues were reported from these customers in the oil and gas and transportation and gathering segments.

Lease operating payments primarily made to a principal operator on its oil and gas producing properties approximated $1852,~~041,~~000 and $~~621~~1,041,000 in ~~2013~~2014 and ~~2012~~2013, respectively.

1716. COMMITMENTS AND CONTINGENCIES

Other

Occasionally, the Company is involved in various lawsuits and certain governmental proceedings arising in the normal course of business. In the opinion of management, the outcome of such matters will not have a materially adverse effect on the consolidated results of operations or financial position of the Company. None of the Company’s directors, officers, or affiliates, owners of record or beneficially of more than five percent of any class of the Company’s voting securities, or security holder is involved in a proceeding adverse to the Company’s business or has a material interest adverse to the business.

Environmental

To date, the Company’s expenditures to comply with environmental or safety regulations have not been significant and are not expected to be significant in the future. Management monitors these laws and regulations and periodically assesses the propriety of its operational and accounting policies related to environmental issues. The Company is unable to predict whether its future operations will be materially affected by these laws and regulations. It is believed that legislation and regulations relating to environmental protection will not materially affect the consolidated results of operations of the Company.

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PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, ~~2013~~2014 AND ~~2012~~2013

Employment Contracts

In May 2007, the Company entered into employee agreements with its President/Chief Executive Officer and its Executive Vice President for three year terms through May 2012. The contracts provided for an automatic renewal for successive one-year terms unless either party shall, three months prior to last day of employment period, provide written notice that employment period will not be extended. Under the terms of these agreements, the minimum annual compensation for each officer is $250,000 for the President/CEO and $225,000 for the Executive Vice President. On October 5, 2012, the Company entered into an employee agreement with its Chief Financial Officer for a three year term with annual compensation of $200,000.

Leases

The Company leased certain office space under a non-cancelable operating lease that expired in 2010. The lease was not renewed and the office space is now being leased on a month-to-month basis. In January 2012 the rent was reduced to $1,300 per month. Lease expense was approximately $15,600 ~~and~~for ~~$15,600~~each ~~for~~of the years ended December 31, ~~2013~~2014 and ~~2012, respectively~~2013.

Contingent Liabilities

In preparing financial statements at any point in time, management is periodically faced with uncertainties, the outcomes of which are not within its control and will not be known for prolonged periods of time. The Company is involved in actions from time to time, which if determined adversely, could have a material negative impact on the Company's consolidated financial position, results of operations and cash flows. Management, with the assistance of counsel makes estimates, if determinable, of the Company’s probable liabilities and records such amounts in the consolidated financial statements. Such estimates may be the minimum amount of a range of probable loss when no single best estimate is determinable. Disclosure is made, when determinable, of any additional possible amount of loss on these claims, or if such estimate cannot be made, that fact is disclosed.

Along with the Company's counsel, management monitors developments related to legal matters and, when appropriate, makes adjustments to record liabilities to reflect current facts and circumstances. Management has recorded a liability related to its registration rights agreement with investors that provides for the filing of a registration statement for the registration of the shares issued in the offering in December 2007, as well as the shares issuable upon exercise of related warrants. The Company failed to meet the deadline for the effectiveness of the registration statement and therefore was required to pay liquidated damages of approximately $100,000 on the first day of effectiveness failure, or July 18, 2008. An additional $100,000 penalty was required to be paid by the Company every thirty days thereafter, prorated for periods totaling less than thirty days, until the effectiveness failure was cured, up to a maximum of 18% of the aggregate purchase price, or approximately $1,800,000. The Company’s registration became effective on August 21, 2008.

~~Pursuant~~At toDecember ~~the 2011 warrant modification agreement discussed in Note 10~~31, ~~the Company modified certain 2007 Warrant Agreements representing 12~~2014,~~506,340~~ ~~shares~~management toreevaluated ~~waive all prior registration rights and remove~~ the ~~cashless~~status ~~exercise feature. The removal~~ of the ~~cashless exercise made the Company liable for a potential~~ registration ~~rights~~statement ~~penalty~~and ~~effective~~determined ~~sixty~~an ~~days~~accrual ~~after the agreements were signed. The removal~~ of the original penalty on the modified warrants and the addition of the penalty incurred due to the modification agreement were recorded in 2011 and did not result in a material change to the registration rights penalty payable at December 31$48,808 ~~2011.~~was Insufficient ~~March 2012, the Company offered two rescission options~~ to ~~the~~cover ~~holders~~any ~~who~~potential ~~had~~payments ~~signed~~for ~~the~~liquidated ~~2011 modification agreement~~damages. ~~Under~~The ~~Option~~damages Aare ~~the~~reflected ~~warrant~~as ~~reverted~~liquidated ~~back~~damages topayable ~~the original 2007 terms which would add back the original penalty. Under Option B the effectiveness date for the registration rights penalty was changed by setting a filing deadline. As~~ of ~~December 31~~$48,808 ~~2012,~~and ~~Option A rescission agreements representing~~ $40,~~000~~892 ~~shares~~in ~~had been received which reverted~~ the ~~warrant~~accompanying toconsolidated ~~the~~balance ~~original~~sheets ~~2007 terms. Also,~~ as of December 31, ~~2012,~~2014 ~~Option~~and B2013, ~~rescission~~respectively. The ~~agreements~~difference ~~representing~~of 12$7,~~466,340~~916 ~~shares~~was ~~had~~recorded ~~been~~as ~~received~~an ~~which~~expense ~~continued~~in the ~~waiver~~Other ofIncome ~~the~~(Expense) ~~original~~section ~~penalty~~of ~~and changed~~ the ~~effectiveness~~consolidated ~~date~~statement of ~~the modification~~operations.

As of March 31, 2012 there had been holders of the 2007 Warrant Agreements representing 10,261,672 shares that signed the 2011 warrant modification agreement and were subject to a registration rights penalty effective sixty days after the agreements were signed. At that date the penalty was determined to be $314,341. As of June 30, 2012 all of these warrant holders had signed the 2012 warrant modification agreement which changed the effectiveness date of the modification and reversed the penalty calculated in the prior quarter. The reversal of the penalty resulted in a decrease to the penalty payable during 2012 of $173,486 which was recorded as income in the Other Income (Expense) section of the consolidated statement of operations.

At December 31, 2013, management reevaluated the status of the registration statement and determined an accrual of $40,892 was sufficient to cover any potential payments for liquidated damages. The damages are reflected as liquidated damages payable of $40,892 and $34,260 in the accompanying consolidated balance sheets as of December 31, 2013 and 2012, respectively. The difference of $6,632 was recorded as an expense in the Other Income (Expense) section of the consolidated statement of operations.

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PEGASI ENERGY RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, ~~2013~~2014 AND ~~2012~~2013

1817. SUBSEQUENT EVENTS

OnIn ~~February~~January 272015, ~~2014,~~ the Company ~~completed~~entered ainto ~~private~~securities ~~placement~~purchase ~~transaction,~~agreements ~~pursuant~~(the to“Securities ~~which~~Purchase itAgreement”) ~~sold~~with acertain ~~total~~accredited ~~of 781,000~~investors at(“Investors”) ~~$0.90~~whereby ~~per~~the ~~unit~~Company issued and sold to ~~raise~~the ~~gross~~Investors ~~proceeds~~12% ofSenior ~~$702,900~~Secured ~~before~~Convertible ~~deducting~~Notes ~~issuance~~(“Notes”) ~~costs~~in the aggregate amount of $8875,000, ~~resulting~~and inwarrants ~~net~~(“Warrants”) ~~cash~~to ~~proceeds~~purchase ofup ~~$694~~2,~~900~~430,555 shares of the Company’s common stock. ~~Each~~Pursuant ~~unit~~to ~~consisted~~the ofSecurities ~~two~~Purchase ~~shares~~Agreement, ofthe ~~common~~Company ~~stock~~had ~~and~~the ~~a five-year~~right, ~~warrant~~until toFebruary ~~purchase~~23, ~~one~~2015 ~~share~~(the of“Additional ~~common~~Investment ~~stock~~Period”), atto sell up to an ~~exercise~~additional ~~price~~$625,000 of ~~$0.70~~Notes ~~per~~and ~~share~~Warrants, on the same terms and conditions (the “Additional Securities”).

OnTo ~~February~~secure ~~11,~~the ~~2014~~Company’s obligations under the Notes, the Company granted the Investors a ~~holder~~security interest in certain assets of Pegasi Energy Resources Corporation, as Texas corporation and one of the ~~modified~~Company’s ~~2007~~subsidiaries(“Pegasi ~~Warrants~~Texas”) ~~exercised~~pursuant 10to a Deed of Trust,~~000~~ ~~warrants~~Mortgage, toSecurity ~~acquire~~Agreement, 20Financing Statement and Assignment of Production,~~000~~ ~~shares~~as onamended (the “Security Agreement”). In addition, pursuant to a ~~cashless~~guarantee ~~basis~~(the “Guarantee”), Pegasi Texas agreed to guarantee the punctual payment, as and ~~received~~when 6due and payable,~~380~~ ~~shares~~of all amounts owed by the Company in respect of the Securities Purchase Agreement, the Notes and the other transaction documents executed in connection with the Securities Purchase Agreement. As well, the Company’s granted the Investors certain registration rights pursuant to a registration rights agreement, pursuant to which the Company is obligated to file a registration statement registering for resale the common stock issuable upon conversion of the Notes and exercise of the Warrants no later than May 9, 2015 (the “Registration Rights Agreement”).

On ~~January~~March 3027, ~~2014~~2015, ~~pursuant to~~ the ~~2012 Plan, the~~ Company ~~issued~~ ~~stock~~entered ~~options~~into ~~for 7,000,000 shares of common stock at~~ an ~~exercise~~omnibus ~~price~~amendment ofagreement ~~$0.79 per share to various executives, selected employees and directors for their contributions to~~ (the ~~success~~“Amendment”) ofwith the ~~Company. All~~Investors ofpursuant ~~the~~to ~~options vested immediately upon issuance at January 30~~which, ~~2014,~~among ~~and~~other are exercisable at any time, in whole or part, until January 30, 2019. This issuance resulted in stock based compensation of $2,365,106, which was calculated using the fair value of the options at grant date. things:

In· ~~addition,~~The onCompany ~~January~~and ~~30,~~the ~~2014,~~Investors ~~pursuant~~amended to the ~~2010~~Securities ~~Plan, the~~Purchase ~~Company issued~~Agreement ~~stock options for 49,940 shares of common stock at an exercise price of $0.79 per share~~ to ~~selected~~extend ~~employees for their contributions to~~ the ~~success~~Additional ofInvestment ~~the~~Period ~~Company. All~~until ofMarch ~~the options vested immediately upon issuance at January 30~~31, ~~2014~~2015, ~~and~~to ~~are~~increase ~~exercisable~~the atWarrant ~~any~~ratio ~~time,~~from in33% ~~whole~~to or100% ~~part,~~and ~~until~~allowed ~~January~~for ~~30,~~up ~~2019. This~~to ~~issuance resulted in stock based compensation of~~ $~~16,873,~~1 ~~which~~million ~~was calculated using the fair value~~ of ~~the~~Additional ~~options~~Securities atto ~~grant~~be ~~date.~~ sold;

~~During~~· ~~January~~The ~~2014~~Company and the Investors amended the Notes to increase the minimum conversion price from $0.05 to $0.09, ~~two~~to ofrequire payments (including prepayments) to principal and interest to be on a pro rata basis, to provide for additional consideration to the Investors upon the Company’s ~~directors~~failure ~~resigned~~to timely process conversion requests, and ato ~~new~~increase ~~director~~the ~~was~~maximum ~~elected~~beneficial ownership limitation from 9.99% to 19.99%;

·	The Company and the Investors amended the Warrants to provide for cashless exercise at any time, to increase the maximum beneficial ownership limitation from 9.99% to 19.99%, and to provide for additional consideration to the Investors upon the Company’s failure to timely process exercise notices;

·	The Company and the Investors amended the Registration Rights Agreement to clarify the liquidated damages due upon a default by the Company; and

·	The Company issued all the Investors additional Warrants (the “Consideration Warrants”) to purchase 4,861,116 shares of common stock, so that the Warrants, together with the Consideration Warrants, equaled the new Warrant ratio of 100%.

On March 27, 2015, the Company entered into a securities purchase agreement with an accredited investor, pursuant to which the Company issued and sold to the investor a $1,000,000 Note and Warrants to purchase 8,333,334 shares of common stock (the “Subsequent Investment”). In connection therewith, the Guarantee was amended and restated to include the Subsequent Investment and the Company covenanted to file an amendment to the Security Agreement to include the Subsequent Investment. To date, in connection with the offering, the Company sold Notes in the aggregate principal amount of $1,875,000 and Warrants (including Consideration Warrants) to purchase 15,625,005 shares of common stock, resulting in net proceeds of approximately $1.78 million.

The Notes are convertible, in whole or in part, into shares of the Company’s common stock at the option of the investor, at the lower of (i) $0.12 or (ii) the higher of (x) $0.09 or (y) the volume weighted average price of our common stock for the 10 trading days immediately preceding the date of conversion, subject to adjustment upon certain events, as set forth in the Note.

The Company has the right, at any time after the date that the Registration Statement is declared effective, to redeem some or all of the outstanding Notes, upon 30 days prior written notice. If the Notes are redeemed prior to the first anniversary of issuance, the redemption price shall equal 110% of the amount of principal and interest being redeemed.

The Warrants are exercisable, at the option of the investor, for seven (7) years after issuance, in whole or in part, at an exercise price equal to the lower of (i) $0.132 or (ii) the higher of (x) $0.06 or (y) 110% of the volume weighted average price of the Company’s common stock for the 10 trading days immediately preceding the date of exercise, subject to adjustment upon certain events, as set forth in the Warrant.

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PEGASI ENERGY RESOURCES CORPORATION

SUPPLEMENTAL OIL AND GAS DISCLOSURES - UNAUDITED

DECEMBER 31, 2014 AND 2013

DECEMBER 31, 2013 AND 2012

The following tables set forth supplementary disclosures for oil and gas producing activities in accordance with FASB ASC Topic No. 932, Extractive Activities—Oil and Gas.

Capitalized Costs Relating to Oil and Gas Producing Activities

	2013			2012
	December 31,			December 31,
Unproved oil and gas properties	$	14,298,503		$	13,090,037
	2014			2013
Proved oil and gas properties (including asset retirement costs)		18,086,443			17,684,565
Unproved oil and gas properties	$	12,337,167		$	14,298,503
Less accumulated depreciation, depletion, amortization, and valuation allowance		(1,951,186	)		(1,565,559	)
Proved oil and gas properties (including asset retirement costs)		21,391,472			18,086,443
Net capitalized costs	$	30,433,760		$	29,209,043
Less accumulated depreciation and depletion		(2,468,546	)		(1,951,186	)
Net capitalized costs	$	31,260,093		$	30,433,760

Capitalized costs include leasehold costs, lease and well equipment, capitalized intangible drilling costs, and capitalized intangible completion costs.

Costs Incurred

A summary of costs incurred in oil and gas property acquisition, development, and exploration activities (both capitalized and charged to expense) for the years ended December 31, ~~2013~~2014 and ~~2012~~2013, as follows:

	2013		2012
	2014		2013
Acquisition of proved properties	$	-44	$	~~3,612~~-
Acquisition of unproved properties	$	1760,~~198,467~~554	$	21,~~612~~198,~~309~~467
Development costs	$	~~618~~537,~~721~~851	$	5618,~~248,~~721

The following is a summary of the Company’s oil and gas properties not subject to amortization as of December 31, 2014.

	2014		2013		2012		Prior to 2012		Total
Acquisition costs	$	760,554	$	1,198,467	$	2,612,309	$	7,320,023	$	11,891,353
Development costs		31,138		9,998		282,592		122,086		445,814
Total oil and gas properties not subject to amortization	$	791,692	$	1,208,465	$	2,894,901	$	7,442,109	$	12,337,167

The total of $12.3 million in capitalized oil and gas property costs not currently subject to amortization primarily relate to investments in the Cornerstone Project in East Texas. Based on Pegasi’s plan, costs will begin to be included in the amortization computation when these properties are developed and begin production. The development of these properties is contingent on the Company obtaining the necessary financing for this project.

Results of Operations for Producing Activities

The following table presents the consolidated results of operations for the Company’s oil and gas producing activities for the years ended December 31, ~~2013~~2014 and ~~2012~~2013:

		2013			2012
	2014			2013
Revenues	$	1,~~628~~704,~~806~~757		$	1,~~359~~628,~~525~~806
Production costs		(1887,~~074,466~~041	)		(~~647~~1,~~749~~074,466	)
Depletion, depreciation, and valuation provisions		(385,626	)		(346,533	)
Depletion and depreciation		(517,360	)		(385,626	)
Exploration costs		-			-
Income before income tax expense		~~168~~300,~~714~~356			~~365~~168,~~243~~714
Income tax expense		(59105,~~050~~125	)		(~~127~~59,~~835~~050	)
Results of operations for producing activities (excluding corporate overhead and interest costs)	$	~~109~~195,~~664~~231		$	~~237~~109,~~408~~664

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PEGASI ENERGY RESOURCES CORPORATION

SUPPLEMENTAL OIL AND GAS DISCLOSURES - UNAUDITED

DECEMBER 31, 2014 AND 2013

DECEMBER 31, 2013 AND 2012

Reserve Quantity Information

The following table presents the Company’s estimate of its proved oil and gas reserves all of which are located in the United States. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of reserves related to new discoveries are more imprecise than those for producing oil and gas properties. Accordingly, the estimates are expected to change as future information becomes available. The estimates have been prepared with the assistance of an independent petroleum reservoir engineering firm. The petroleum engineer that determined our reserves also planned and supervised the drilling of wells that the Company drilled in the East Texas project. His ~~2013~~2014 and ~~2012~~2013 compensation, from the Company, for the planning and supervision of drilling wells was $~~295~~366,~~406~~315 and $~~994~~295,~~993~~406, respectively. The petroleum engineer’s compensation for reserve estimation for that same time period was $1917,~~301~~783 and $2319,~~992~~301, respectively. Oil reserves, which include condensate and natural gas liquids, are stated in barrels and gas reserves are stated in thousands of cubic feet.

	Oil			Gas
	(Bbls.)			(MCF)
Changes in proved developed and undeveloped reserves:
Balance at January 1, 2011		458,286			13,814,440
Balance at January 1, 2012		448,154			14,866,014
Extensions and discoveries		722			859
Production		(4,063	)		(117,461	)
Revisions of previous estimates		(6,791	)		1,168,176
Balance at December 31, 2011		448,154			14,866,014
Purchase of minerals in place		539			-
Extensions and discoveries		75,953			114,060
Production		(11,516	)		(109,277	)
Revisions of previous estimates		215,524			(635,919	)
Balance at December 31, 2012		728,654			14,234,878
Purchase of minerals in place		381			-
Extensions and discoveries		13,128			1,248,000
Improved recoveries		40,248			-
Production		(10,170	)		(164,842	)
Revisions of previous estimates		(14,579	)		1,400,624
Balance at December 31, 2013		757,662			16,718,660
Purchase of minerals in place		-			-
Extensions and discoveries		31,144			552,130
Improved recoveries		36			1,529
Production		(8,423	)		(224,205	)
Revisions of previous estimates		(106,937	)		(4,886,973	)
Balance at December 31, 2014		673,482			12,161,141

Proved developed reserves:
December 31, 2011
Beginning of year	52,866	799,696
End of year	52,085	764,010
December 31, 2012
Beginning of year	52,085	764,010
End of year	130,584	759,307
December 31, 2013
Beginning of year	130,584	759,307
End of year	137,480	1,131,178
December 31, 2014
Beginning of year	137,480	1,131,178
End of year	151,500	1,259,775

Proved Undeveloped reserves:
Proved undeveloped reserves:
December 31, 2011
Beginning of year	405,420	13,014,744
End of year	396,069	14,102,004
December 31, 2012
Beginning of year	396,069	14,102,004
End of year	598,069	13,475,572
December 31, 2013
Beginning of year	598,069	13,475,572
End of year	620,182	15,587,482
December 31, 2014
Beginning of year	620,182	15,587,482
End of year	521,982	10,901,366

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PEGASI ENERGY RESOURCES CORPORATION

SUPPLEMENTAL OIL AND GAS DISCLOSURES - UNAUDITED

DECEMBER 31, 2014 AND 2013

DECEMBER 31, 2013 AND 2012

Standardized Measure of Discounted Future Net Cash Flow and Changes Therein Relating to Proved Oil and Gas Reserves

The following table, which presents a standardized measure of discounted future cash flows and changes therein relating to proved oil and gas reserves, is presented pursuant to FASB ASC Topic No. 932. In computing this data, assumptions other than those required by the FASB could produce different results. Accordingly, the data should not be construed as being representative of the fair market value of the Company’s proved oil and gas reserves.

Future cash inflows were computed by applying existing contract and 12-month average prices of oil and gas relating to the Company’s proved reserves to the estimated year-end quantities of those reserves. Future price changes were considered only to the extent provided by contractual arrangements in existence at year end. Future development and production costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs. Future income tax expenses were computed by applying the year-end statutory tax rate, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company’s proved oil and gas reserves. The standardized measure of discounted future cash flows at December 31, ~~2013~~2014 and ~~2012~~2013, which represents the present value of estimated future cash flows using a discount rate of 10% a year, follows:

	2013			2012
	2014			2013
Future cash inflows	$	~~123~~102,~~009~~591,~~953~~047		$	~~108~~123,~~771~~009,~~742~~953
Future production costs		(3633,~~248~~808,~~724~~589	)		(3036,~~733~~248,~~575~~724	)
Future development costs		(2010,~~070~~451,~~665~~570	)		(20,~~019~~070,~~150~~665	)
Future income tax expenses		(1915,~~350~~573,~~500~~012	)		(1719,~~390~~350,~~340~~500	)
Future net cash flows		4742,~~340~~757,~~064~~876			4047,~~628~~340,~~677~~064
10% annual discount for estimated timing of cash flows		(18,~~155~~935,~~672~~933	)		(1718,~~823~~155,~~432~~672	)
Standardized measure of discounted future net cash flows	$	2923,~~184~~821,~~392~~943		$	2229,~~805~~184,~~245~~392

		2013			2012
	2014			2013
Beginning of year	$	2229,~~805~~184,~~245~~392		$	2322,~~763~~805,~~506~~245
Sales of oil and gas, net of production costs		(~~554~~817,~~340~~716	)		(~~711~~554,~~776~~340	)
Extensions, discoveries, and improved recoveries, less related costs		31,~~466~~017,~~809~~923			13,~~154~~466,~~555~~809
Accretion of discount		3,~~092~~876,~~190~~848			3,~~079~~092,~~556~~190
Net change in sales and transfer prices, net of production costs		(1,~~624~~376,~~560~~624	)		(1,~~993~~624,~~665~~560	)
Actual development costs incurred		~~399~~537,~~962~~851			5399,~~248,721~~962
Changes in estimated future development costs		(~~746~~14,~~308~~973,109	)		10(746,~~995,864~~308	)
Net change in income taxes		(12,~~467~~915,~~361~~224	)		(1,~~084~~467,~~726~~361	)
Changes in production rates (timing and other)		111,~~214~~120,~~634~~620			~~(22~~1,~~712~~214,~~742~~634	)
Purchases and sales of mineral interests		~~5,053~~-			65,~~553~~053
Revisions of previous quantities		2(10,~~593~~416,~~068~~714	)		12,~~072~~593,~~069~~068
End of year	$	2923,~~184~~821,~~392~~943		$	2229,~~805~~184,~~245~~392

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

ITEM 9A. CONTROLS AND PROCEDURES

~~(a)~~ Evaluation of disclosure controls and procedures.

Our management, with the participation of our chief executive officer and chief financial officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Exchange Act. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs.

Based on management’s evaluation, our chief executive officer and chief financial officer concluded that, as a result of the material weakness described below, as of December 31, ~~2013~~2014, our disclosure controls and procedures are not designed at a reasonable assurance level and are ineffective to provide reasonable assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure. The material weakness, which relates to internal control over financial reporting, that was identified is:

Due to our small size, we do not have a proper segregation of duties in certain areas of our financial reporting process. The areas where we have a lack of segregation of duties include cash receipts and disbursements, approval of purchases and approval of accounts payable invoices for payment. This control deficiency, which is pervasive in nature, results in a reasonable possibility that material misstatements of the consolidated financial statements will not be prevented or detected on a timely basis.

We are committed to improving our financial organization. We will look to increase our personnel resources and technical accounting expertise within the accounting function to resolve non-routine or complex accounting matters. In addition, when funds are available, we will take the following action to enhance our internal controls: Hiring additional knowledgeable personnel with technical accounting expertise to further support our current accounting personnel, which management estimates will cost approximately $100,000 per annum. As our operations are relatively small and we continue to have net cash losses each quarter, we do not anticipate being able to hire additional internal personnel until such time as our operations are profitable on a cash basis or until our operations are large enough to justify the hiring of additional accounting personnel. We currently engage an outside accounting firm to assist us in the preparation of our consolidated financial statements and anticipate doing so until we have a sufficient number of internal accounting personnel to achieve compliance. As necessary, we will engage consultants in the future in order to ensure proper accounting for our consolidated financial statements.

Due to the fact that our internal accounting staff consists solely of a Chief Financial Officer, additional personnel will also ensure the proper segregation of duties and provide more checks and balances within the department. Additional personnel will also provide the cross training needed to support us if personnel turn over issues within the department occur. We believe this will greatly decrease any control and procedure issues we may encounter in the future.

~~(b)~~Management’s ~~Changes~~report inon internal control over financial reporting.

~~There~~Our ~~were~~management nois ~~changes~~responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). Management conducted an evaluation of the effectiveness of our internal control over financial reporting ~~that~~based ~~occurred~~on ~~during~~ the ~~year~~framework ~~ended~~in ~~December~~Internal ~~31,~~Control—Integrated Framework (2013) ~~that~~issued ~~have~~by ~~materially~~the ~~affected,~~Committee orof ~~are~~Sponsoring ~~reasonably~~Organizations ~~likely~~of tothe ~~materially~~Treadway ~~affect~~Commission. Based on this evaluation, management concluded that our internal control over financial reporting was not effective as of December 31, 2014 for the reason discussed above.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that our internal control over financial reporting was not effective as of December 31, 2013 for the reason discussed above.

This annual report does not include an attestation report by Whitley Penn LLP, our independent registered public accounting firm regarding internal control over financial reporting. As a smaller reporting company, our management's report was not subject to attestation by our registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit us to provide only management's report in this annual report.

Changes in internal control over financial reporting.

There were no changes in our internal control over financial reporting that occurred during the year ended December 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION

None.

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PART III.

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

The names of our executive officers and directors and their age, title, and biography as of ~~March~~April 121, ~~2014~~2015 are set forth below:

Names:	Ages	Titles:	Position Held Since	Director Since
Michael H. Neufeld	6465	President, Chief Executive Officer, and Director	November 22, 2006	November 22, 2006
Jonathan Waldron	4546	Chief Financial Officer	October 5, 2012	n/a
William L. Sudderth	7273	Executive Vice President, Land	November 22, 2006	n/a
Oliver Waldron	7071	Director	~~August 3, 2011~~n/a	August 3, 2011
Jay Moorin	6263	Director	n/a	January 31, 2014

Directors are elected to serve until the next annual meeting of stockholders and until their successors are elected and qualified. Currently there are three seats on our board of directors.

Officers are elected by the Board of Directors and serve until their successors are appointed by the Board of Directors. Biographical resumes of each officer and director are set forth below.

Michael H. Neufeld - President, Chief Executive Officer, and Director

Mr. Neufeld has been President and Chief Executive Officer of PERC and its predecessors since 2000. He worked for Pennzoil Company from 1972 to 1976 as a Development Geologist, Exploration Geologist and Senior Geologist working in Pennzoil’s Gulf Coast Division. He then joined American Resources Company from 1976 to 1977 as Senior Geologist. In 1977 he joined Hunt Oil Company as Sr. Geologist working in the Texas and Gulf Coast regions. From 1978 to 1981, Mr. Neufeld worked for Croftwood Corporation as Senior Exploration Geologist and Vice-President of Exploration working in the Gulf Coast of Louisiana and Texas. In 1983 Mr. Neufeld co-founded SMK Energy Corporation ("SMK Energy"), where exploration efforts were concentrated in East Texas, Gulf Coast Louisiana and the Rocky Mountains. He graduated from Louisiana State University in 1971 with a B.S. Degree in Geology. Mr. Neufeld was selected to serve as a director due to his deep familiarity with our business and his extensive entrepreneurial background.

Jonathan Waldron - – Chief Financial Officer

Mr. Waldron has been our Chief Financial Officer since October 5, 2012. He began his career at BP in 1989 and over a period of five years held roles in BP’s petroleum refining & oil trading businesses in London and New York. Following business school, Mr. Waldron joined Mercer Management Consulting London (now Oliver Wyman) in 1996 where he worked as a strategy consultant for international clients in the telecommunication and transportation industries. In 1998, he joined DIAGEO where he held senior roles in strategic planning and international marketing over a period of eight years. In March 2007 Mr. Waldron joined First Europa, an online insurance start-up as Sales & Marketing Director. Following the sale of First Europa in April 2008, Mr. Waldron worked as a management consultant with clients in the Aviation, Financial Services and Oil & Gas businesses before joining Pegasi in 2012. He holds a B.A. in Natural Sciences (Geology) from the University of Oxford, UK and a M.B.A. from INSEAD business school, Fontainebleau, France.

William L. Sudderth - Executive Vice President

Mr. Sudderth has been an Executive Vice President of PERC and its predecessors since 2000. He began his career at Lone Star Producing Company in 1970 where he worked through 1971. In late 1971 he joined Midwest Oil Corporation and worked there until 1974, at which point he became an independent landman working the entire continental United States. In 1981 Mr. Sudderth became a Certified Professional Landman. In 1983 Mr. Sudderth co-founded SMK Energy, along with Mr. Neufeld, which later merged with Windsor Energy in 1997. Mr. Sudderth received his B.B.A. Degree from Sam Houston State University in 1970.

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Oliver Waldron - Director

Oliver Waldron has been a director since August 2011. Mr. Waldron began his career at Anglo American Corporation of South Africa in 1968 where he undertook a wide range of project studies as team leader on natural resource development opportunities, developed new business in North and South America and managed both mining and oil and gas development projects in Canada, US and Mexico. In 1972, Mr. Waldron joined Tara Exploration and Development Co Ltd as Managing Director. In 1976, he worked as Management Consultant and Private Investor in natural resource projects. In 1978, he worked as Chairman and Founder of Dragon Oil PLC where he brought the company listed on the London Stock Exchange in 1992. In 1998, he joined Celtic Resources PLC as co-founder. In 2000, he formed Hibernian Oil Company Limited. From 2001 to 2008, he worked as Management Consultant in oil and gas projects in the Caspian Region assisting with technical, commercial, financial evaluations of new projects. In 2009, Mr. Waldron joined Caspian Oil Resources Limited in Gibraltar as Chairman. He is a science graduate of the university College Cork and holds a Doctorate in Physics from the University of Oxford. Mr. Waldron was selected to serve as a director due to his vast experience with oil and gas companies and his extensive entrepreneurial background.

~~Jay Moorin - Director~~39

~~Jay~~Table ~~Moorin became a director in January 2014. Since 1998, Mr. Moorin has served as a founding general partner~~ of ProQuest Investments, a healthcare venture capital firm. From 1991 to 1998, Mr. Moorin served as president and chief executive officer of Margainin Pharmaceuticals Inc., a publicly-traded biopharmaceutical company and also served as chairman of its board of directors from 1996 to 1998. Prior to Margainin, Mr. Moorin held the position of Managing Director of Healthcare Banking at Bear Stearns & Co. Inc. and Vice President of Marketing and Business Development at a division of the ER Squibb Pharmaceutical Company. Currently, Mr. Moorin serves on the board of directors of Eagle Pharmaceuticals (Chairman) and Mevion Medical Systems and is an advisor to DPT Capital Management, LLC, an investment firm and serves as a Trustee of the Equinox Funds Trust. Previously, Mr. Moorin served on the board of directors of numerous public and private healthcare companies. In addition, Mr. Moorin held the position of adjunct senior fellow of the Leonard Davis Institute of Health Economics at the University of Pennsylvania from 1997 to 2012. Mr. Moorin holds a B.A. in economics with distinction from the University of Michigan. Mr. Moorin was selected to serve as a director due to his significant executive leadership experience, including his experience leading several public companies, as well as his membership on public company boards. He also has extensive experience in financial and operations management, risk oversight, and quality and business strategy.Contents

Jay Moorin – Director

Jay Moorin became a director in January 2014. Since 1998, Mr. Moorin has served as a founding general partner of ProQuest Investments, a healthcare venture capital firm. From 1991 to 1998, Mr. Moorin served as president and chief executive officer of Margainin Pharmaceuticals Inc., a publicly-traded biopharmaceutical company and also served as chairman of its board of directors from 1996 to 1998. Prior to Margainin, Mr. Moorin held the position of Managing Director of Healthcare Banking at Bear Stearns & Co. Inc. and Vice President of Marketing and Business Development at a division of the ER Squibb Pharmaceutical Company. Currently, Mr. Moorin serves on the board of directors of Eagle Pharmaceuticals (Chairman) and Mevion Medical Systems, and serves as a Trustee of the Equinox Funds Trust. Previously, Mr. Moorin served on the board of directors of numerous public and private healthcare companies. In addition, Mr. Moorin held the position of adjunct senior fellow of the Leonard Davis Institute of Health Economics at the University of Pennsylvania from 1997 to 2012. Mr. Moorin holds a B.A. in economics with distinction from the University of Michigan. Mr. Moorin was selected to serve as a director due to his significant executive leadership experience, including his experience leading several public companies, as well as his membership on public company boards. He also has extensive experience in financial and operations management, risk oversight, and quality and business strategy.

Family Relationships

Oliver Waldron is the father of Jonathan Waldron.

Board Committees and Independence

We are not required to have any independent members of the Board of Directors. The board of directors has determined that (i) Mr. Neufeld has a relationship which, in the opinion of the board of directors, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director and each is not an “independent director” as defined in the Marketplace Rules of The NASDAQ Stock Market and (ii) Messrs. Waldron, ~~Gelfand~~ and ~~Moss~~Moorin are independent directors as defined in the Marketplace Rules of The NASDAQ Stock Market. As we do not have any board committees, the board as a whole carries out the functions of audit, nominating and compensation committees, and such “independent director” determination has been made pursuant to the committee independence standards.

Involvement in Certain Legal Proceedings

Our Directors and Executive Officers have not been involved in any of the following events during the past ten years:

1.	any bankruptcy petition filed by or against such person or any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time;

2.	any conviction in a criminal proceeding or being subject to a pending criminal proceeding (excluding traffic violations and other minor offenses);

being subject to any order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining him from or otherwise limiting his involvement in any type of business, securities or banking activities or to be associated with any person practicing in banking or securities activities;

4.	being found by a court of competent jurisdiction in a civil action, the Securities and Exchange Commission or the Commodity Futures Trading Commission to have violated a federal or state securities or commodities law, and the judgment has not been reversed, suspended, or vacated;

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being subject of, or a party to, any federal or state judicial or administrative order, judgment decree, or finding, not subsequently reversed, suspended or vacated, relating to an alleged violation of any federal or state securities or commodities law or regulation, any law or regulation respecting financial institutions or insurance companies, or any law or regulation prohibiting mail or wire fraud or fraud in connection with any business entity; or

being subject of or party to any sanction or order, not subsequently reversed, suspended, or vacated, of any self-regulatory organization, any registered entity or any equivalent exchange, association, entity or organization that has disciplinary authority over its members or persons associated with a member.

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Section 16(a) Beneficial Owner Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934, as amended, requires our directors, executive officers and holders of more than 10% of our common stock to file with the SEC reports regarding their ownership and changes in ownership of our securities. We believe that, during fiscal ~~2013~~2014, our directors, executive officers and 10% stockholders complied with all Section 16(a) filing requirements except for Form 4s relating to options granted on January 30, 2014, which forms were filed in March 2015.

Code of Ethics

The Board of Directors has adopted a Code of Ethics that applies to all directors, officers and employees. A copy of the code of ethics is incorporated by reference as an exhibit.

ITEM 11. EXECUTIVE COMPENSATION.

Summary Compensation Table

The following table provides certain summary information concerning compensation awarded to, earned by or paid to our Chief Executive Officer and the two highest paid executive officers whose total annual salary and bonus exceeded $100,000 for fiscal years ~~2013~~2014 and ~~2012~~2013. In accordance with the rules of the SEC, this table omits columns that are not relevant.

Name and Principal Position	Year	Salary ($)		~~Stock Awards (4) ($)~~	Stock Awards (4) ($)	~~All Other Compensation ($)~~		~~Total~~All Other Compensation ($)		Total ($)
Michael Neufeld (1)	~~2013~~2014		250,000	-		-	-	~~250,000~~	96		250,096
Chief Executive Officer	~~2012~~2013		250,000	~~754,628~~		-	-	~~1,004,628~~	120		250,120
Bill L. Sudderth (2)	~~2013~~2014		225,000	-		-	-	~~225,000~~	82		225082
Executive Vice President	~~2012~~2013		225,000	~~754,628~~		-	-	~~979,628~~	112		225112
Jonathan Waldron (3)	~~2013~~2014		200,000	~~655,181~~		393,110	-	~~855,181~~	96		593,206
Chief Financial Officer	~~2012~~2013		50200,000	~~631,859~~		655,181	~~116,719~~	~~798,578~~	120		855,301

1. Mr. Neufeld’s salary ~~consists~~was ~~of $250,000~~ accrued during ~~2013~~2014 and $250,000 accrued during 2012. On January 5, 2012, we granted him options to purchase 21,241 shares of our common stock at a price of $0.50 per share and 181,818 shares of our common stock at a price of $0.55 per share, exercisable until January 5, 2017. On April 30, 2012, we granted him options to purchase 1,500,000 shares of our common stock at a price of $0.55 per share, exercisable until April 30, 2017. These options were fully vested on the grant date. No options were granted in 2013.

2. Mr. Sudderth’s salary ~~consists~~was ~~of $225,000~~ accrued during ~~2013~~2014 and $225,000 accrued during 2012. On January 5, 2012, we granted him options to purchase 21,240 shares of our common stock at a price of $0.50 per share and 181,818 shares of our common stock at a price of $0.55 per share, exercisable until January 5, 2017. On April 30, 2012, we granted him options to purchase 1,500,000 shares of our common stock at a price of $0.55 per share, exercisable until April 30, 2017. These options were fully vested on the grant date. No options were granted in 2013.

3. Mr. Waldron began serving as the Chief Financial Officer on October 5, 2012. Mr. Waldron’s salary consists of $200,000 being paid during 2013, and $16,667 paid and $33,333 accrued during 2012. Prior to his employment he was paid consulting fees of $116,719 in 2012. On January 5, 2012, we granted him options to purchase 312,000 shares of our common stock at a price of $0.50 per share, exercisable until January 5, 2017. During 2012, as part of his employment agreement, we granted ~~him~~Mr. Waldron options to purchase 3,000,000 shares of our common stock at a price of $0.66 per share, exercisable until October 5, 2022. These options ~~vest~~vested in tranches of 1,000,000 shares over a two year period beginning on the grant date.

4. For details regarding the assumptions made in the valuation of stock awards, please see ”Note 9 –~~Stock~~ Stock-Based Compensation” of the Notes to the Consolidated Financial Statements included in this report.

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The employment agreements with each of our executive officers were not tied to specific performance goals or company targets because we were a relatively new operating company at the time each executive officer’s agreement was negotiated. Our negotiation of the employment agreements was highly dependent on our cash flow projections and, in fact, both Michael Neufeld and Bill L. Sudderth are currently not receiving any of their agreed-upon salary. The full salary is being accrued and will be paid at a later date when our cash flow increases.

Employment Contracts and Termination of Employment and Change-In-Control Arrangements

The material terms of each Executive Officer’s services agreement or arrangement is as follows:

Michael Neufeld and Bill Sudderth entered into substantially similar employment agreements with us commencing May 1, 2007. They had an initial term of three year and automatically renew for a one-year term and will continue to automatically renew for successive one year terms unless, at least 90 days before the last day of the employment period, a written notice is given stating that the employment period will not be extended. Mr. Neufeld will be paid an annual salary of $250,000 and Mr. Sudderth will be paid $225,000. On October 5, 2012, Jonathan Waldron entered into a three year employment agreement with us for an annual salary of $200,000. Each person may be entitled to a bonus at the discretion of the Board of Directors. Each person may be terminated for cause, which under the terms of the agreements is defined as:

·	The employee having, in our reasonable judgment, committed an act which if prosecuted and resulting in a conviction would constitute a fraud, embezzlement, or any felonious offense (specifically excepting simple misdemeanors not involving acts of dishonesty and all traffic violations);

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·	The employee’s theft, embezzlement, misappropriation of or intentional and malicious infliction of damage to our property or business opportunity;

·	the employee’s repeated abuse of alcohol, drugs or other substances as determined by an independent medical physician; or

the employee’s engagement in gross dereliction of duties, refusal to perform assigned duties consistent with his position, his knowing and willful breach of any material provision of their agreements continuing after written notice from us or repeated violation of our written policies after written notice.

Each of the agreements contains standard non-disclosure and prohibits the employee from competing with us in our territory for a period of two years following the termination of employment for any reason. For purposes of the employment agreement, the territory consists of all land at any time held under our leases (or our affiliates) for mineral exploration or development and all surrounding land within two miles from any leased land.

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Outstanding Equity Awards at Fiscal Year-End Table

The following table sets forth information concerning unexercised options, stock that has not vested, and equity incentive awards outstanding as of December 31, ~~2013~~2014 for each of our executive officers.

Outstanding Equity Awards at Fiscal Year End Option Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options (#) Unexercisable		Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)		Original Option Exercise Price ($)			Aggregate Market Value of Unvested stock ($)		Option Expiration Date
Name	Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options (#) Unexercisable		Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)		Original Option Exercise Price ($)		Aggregate Market Value of Unvested stock ($)		Option Expiration Date
Michael Neufeld, CEO		238,095		-		-		0.42		-		December 24, 2017
Michael Neufeld, CEO		238,095		-		-		0.42	-		December 24, 2015
		21,241		-		-		0.50		-		January 5, 2019
		21,241		-		-		0.50	-		January 5, 2017
		181,818		-		-		0.55		-		January 5, 2019
		181,818		-		-		0.55	-		January 5, 2017
		1,500,000		-		-		0.55		-		April 30, 2019
		1,500,000		-		-		0.55	-		April 30, 2017
		2,000,000		-		-		0.79		-		January 30, 2019
Bill L. Sudderth, Executive Vice President		238,095		-		-		0.42	-		December 24, 2015
Bill L. Sudderth, EVP		238,095		-		-		0.42		-		December 24, 2017
		21,240		-		-		0.50	-	-	~~January 5, 2017~~	January 5, 2019
		181,818		-		-		0.55	-	-	~~January 5, 2017~~	January 5, 2019
		1,500,000		-		-		0.55	-	-	~~April 30, 2017~~	April 30, 2019
Jonathan Waldron, CFO		312,000		-		-		0.50	-		January 5, 2017
		1,000,000		-		-		0.79		-		January 30, 2019
		2,000,000		1,000,000		-		0.66	393,110		October 5, 2022
Jonathan Waldron, CFO		312,000		-		-		0.50		-		January 5, 2017
		3,000,000		-		-		0.66		-		October 5, 2012
		1,500,000		-		-		0.79		-		January 30, 2019

Director Compensation

None.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

The following table sets forth certain information regarding beneficial ownership of our common stock as of April ~~March 12~~1, ~~2014~~2015.

	●	by each person who is known by us to beneficially own more than 5% of our common stock;
	●	by each of our officers and directors; and
	●	by all of our officers and directors as a group.

NAME AND ADDRESS OF OWNER (1)	TITLE OF CLASS	NUMBER OF SHARES OWNED (2)				~~PERCENTAGE OF CLASS (3)~~	PERCENTAGE OF CLASS (3)
Michael H. Neufeld (4)	Common Stock		2528,~~743~~418,~~647~~005	~~(5)~~	(5)		~~31.54~~	%33.39	%
William L. Sudderth (4)	Common Stock		2527,~~593~~268,~~646~~004	~~(6)~~	(6)		~~31.39~~	%32.46	%
Jonathan Waldron	Common Stock		14,~~312~~812,000	~~(7)~~	(7)		~~1.85~~	%6.39	%
Oliver Waldron	Common Stock		~~225~~1,725,000	~~(7)~~	(7)		*	2.39	%
Jay Moorin	Common Stock		75,~~859~~848,~~170~~058	~~(8)~~	(8)		~~10.95~~	%8.29	%
All Officers and Directors	Common Stock		4248,~~199~~862,~~720~~966	~~(9)~~	(9)		~~48.44~~	%51.66	%
As a Group (5 persons)
Teton Ltd. (4)	Common Stock		1415,~~333~~008,~~743~~101	~~(10)~~	(10)		~~18.01~~	%18.51	%
Centrum Bank AG (11)	Common Stock		5,830,000	(12)			8.02	%
Ballindine Limited (11)	Common Stock		6,130,780		(12)			8.39	%
Ballindine Limited (13)	Common Stock		6,130,780	(14)			8.49	%
MSFG Investments Inc. (13)	Common Stock		4,444,445					6.30	%
MSFG Investments Inc. (15)	Common Stock		4,444,445				6.37	%
TR Energy, Inc. (14)	Common Stock		4,200,000					5.95	%
TR Energy, Inc. (16)	Common Stock		4,200,000				6.02	%

* Less than 1%.

(1) The address is c/o Pegasi Energy Resources Corporation, 218 N. Broadway, Suite 204, Tyler, Texas 75702.

(2) Beneficial Ownership is determined in accordance with the rules of the SEC and generally includes voting or investment power with respect to securities. Shares of common stock subject to options or warrants currently exercisable or convertible, or exercisable or convertible within 60 days of ~~March~~April 121, ~~2014~~2015 are deemed outstanding for computing the percentage of the person holding such option or warrant but are not deemed outstanding for computing the percentage of any other person.

(3) Based upon 6970,~~738~~539,~~303~~499 shares issued and outstanding on ~~March~~April 121, ~~2014~~2015.

(4) Messrs. Neufeld and Sudderth are co-owners, executive officers and directors of Teton Ltd.

(5) Includes 100,000 shares of common stock underlying warrants and 13,941,154 shares of common stock underlying options that are currently exercisable or exercisable within 60 days. Also includes 4,200,000 shares of common stock held by TR Energy, Inc., 4,480,000 shares of common stock held by Teton Ltd., 210,000 shares of common stock underlying warrants held by Teton Ltd. and 910,~~643~~318,~~743~~101 shares of common stock issuable upon conversion of debt held by Teton Ltd. Mr. Neufeld disclaims 50% of the shares held by Teton Ltd., which corresponds to his 50% ownership interest in the entity. Does not include shares of common stock issuable upon conversion of a secured convertible note and certain warrants due to exercise limitations contained therein.

(6) Includes 12,941,153 shares of common stock underlying options that are currently exercisable or exercisable within 60 days. Also includes 4,200,000 shares of common stock held by TR Energy, Inc., 4,480,000 shares of common stock held by Teton Ltd., 210,000 shares of common stock underlying warrants held by Teton Ltd. and 910,~~643~~318,~~743~~101 shares of common stock issuable upon conversion of debt held by Teton Ltd. Mr. Sudderth disclaims 50% of the shares held by Teton Ltd., which corresponds to his 50% ownership interest in the entity. Does not include shares of common stock issuable upon conversion of a secured convertible note and certain warrants due to exercise limitations contained therein.

(7) Represents shares of common stock underlying options that are currently exercisable or exercisable within 60 days.

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(8) Includes 2268,~~011,112~~692 shares of common stock ~~underlying warrants and 303,168 shares of common stock~~ owned by the 2011 Grantor Retained Annuity Trust of Jay Moorin, of which Mr. Moorin is Trustee. Does not include shares of common stock issuable upon conversion of a secured convertible note or upon exercise of warrants due to exercise limitations contained therein.

(9) Includes 2100,~~111,112~~000 shares of common stock issuable upon conversion of warrants and 513,419,307 shares of common stock underlying options that are currently exercisable or exercisable within 60 days. Also includes 4,200,000 shares of common stock held by TR Energy, Inc., 4,480,000 shares of common stock held by Teton Ltd., ~~303~~268,~~168~~692 shares of common stock owned by the 2011 Grantor Retained Annuity Trust of Jay Moorin, 210,000 shares of common stock underlying warrants held by Teton Ltd. and 910,~~643~~318,~~743~~101 shares of common stock issuable upon conversion of debt held by Teton Ltd. Does not include shares of common stock issuable upon conversion of a secured convertible note or upon exercise of warrants due to exercise limitations contained therein.

(10) Includes 210,000 shares of ~~Common~~common ~~Stock~~stock underlying warrants and 910,~~643~~318,~~743~~101 shares of ~~Common~~common ~~Stock~~stock issuable upon conversion of debt held by Teton Ltd. As of ~~March~~April 121, ~~2014~~2015, Teton Ltd. had $5,792,957 of outstanding principal and $12,~~660~~239,~~274~~960 of accrued interest that is convertible into shares of ~~Common~~common ~~Stock~~stock at a conversion price of $1.20 per share, $1,194,689 of outstanding principal and $~~361~~461,~~324~~912 of accrued interest that is convertible into shares of ~~Common~~common ~~Stock~~stock at a conversion price of $1.60 per share and $1,173,000 of outstanding principal and $~~303~~380,~~126~~176 of accrued interest that is convertible into shares of ~~Common~~common ~~Stock~~stock at a conversion price of $0.60 per share.

(11) ~~Gerhard~~John ~~Roeoesli~~Wright, ~~and~~director ~~Alessandra~~of ~~Waibel~~the ~~have~~Aile Limited, the corporate director of the investor, has voting and investment control over shares owned by this entity. The address of this shareholder is ~~Kirchstrasse~~Heritage 3Hall, ~~9490~~Me ~~Vaduz~~Marchant St., ~~Principality~~St. ofPeter ~~Liechtenstein~~Port, Guernsey G41 6H7.

(12) Includes 2,~~960~~502,~~000~~780 shares of common stock issuable upon conversion of warrants.

(13) ~~John~~Mehdi ~~Wright,~~Shams ~~director of the Aile Limited, the corporate director of the investor,~~ has voting and investment control over shares owned by this entity. The address of this shareholder is ~~Heritage~~Unicapital ~~Hall~~(London) Ltd., Me6th ~~Marchant St.~~Floor, ~~St.~~23 ~~Peter~~Buckingham ~~Port~~Gate, ~~Guernsey~~London ~~G41~~SWIE ~~6H7~~6LB, United Kingdom.

(14) ~~Includes~~Mike ~~2,502,780~~Neufeld and William Sudderth have voting and investment control over shares owned by this shareholder. The address of ~~common~~this ~~stock~~entity ~~issuable~~is ~~upon~~PO ~~conversion~~Box of479, ~~warrants~~Tyler, Texas 75710.

(15) Mehdi Shams has voting and investment control over shares owned by this entity. The address of this shareholder is Unicapital (London) Ltd., 6th Floor, 23 Buckingham Gate, London SWIE 6LB, United Kingdom.

(16) Mike Neufeld and William Sudderth have voting and investment control over shares owned by this shareholder. The address of this entity is PO Box 479, Tyler, Texas 75710.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

Other than as disclosed below, during the last two fiscal years, there have been no transactions, or proposed transactions, which have materially affected or will materially affect us in which any director, executive officer or beneficial holder of more than 5% of the outstanding common, or any of their respective relatives, spouses, associates or affiliates, has had or will have any direct or material indirect interest. We have no policy regarding entering into transactions with affiliated parties.

Effective January 1, 2007, PERC, entered into a five-year lease agreement with Marion Swamp Fox L.P. providing for the use of office space. On July 1, 2008 the lease for office space was amended to include additional office space and the lease payments were increased from $750 per month to $4,500 per month for the remaining term. This lease expired January 1, 2012 and is now on a month -to -month basis. The total lease payments over the entire term of the lease equal $~~310~~364,500. Marion Swamp Fox LP is owned by Messrs. Neufeld, Sudderth.

POI, PERC, TR Rodessa, and 59 Disposal, had each executed a promissory note dated May 21, 2007, payable to Teton, an entity owned by Messrs. Neufeld and Sudderth, each an executive officer of the Company, in the original principal amount of $5,579,847. The note evidences the combined total of prior working capital loans Teton made to PERC and its subsidiaries over the previous two years. The note accrued interest at eight percent (8%) per annum. Additional funds totaling $1,095,000 were added to the note during 2009. On June 1, 2010 a Promissory (Teton Renewable Note) note was executed to renew and extend the original promissory note dated May 21, 2007. The renewal note’s principal balance of $6,987,646 is the total of the outstanding principal of $5,952,303 and accrued and unpaid interest of $1,035,343 on the original note. Accrued interest and principal is due on the notes maturity date of ~~June~~December 131, 2015. Under the terms of a memorandum of understanding dated May 21, 2007, between the Company and Teton, Teton has the right to convert that original amount into shares of common stock at any time after May 21, 2008 at $1.20 per share. An amendment to the promissory note was executed on March 3, 2009 that gave Teton the right to convert the additional funds into shares of common stock at $1.60 per share. Upon the closing of 59 Disposal in 2012 its share of the note payable was transferred to PERC. The largest aggregate amount of principal outstanding during ~~2013~~2014 was $6,987,646 (See Note 7). Interest expense on the note during ~~2013~~2014 was $559,~~008~~016.

43On October 14, 2009, PERC executed a promissory note payable to Teton that would allow the Company to receive up to $1,000,000. On March 2, 2010 an amendment to the promissory note was executed that provided additional funds available of $1.5 million. The note was amended on April 2, 2011, granting Teton the right to convert the outstanding balance on the note including accrued interest into shares of common stock at a fixed conversion price of $0.60 per share. As of December 31, 2014, PERC had received $1,173,000 related to this note. The accrued interest and outstanding principal are due on the maturity date of December 31, 2015. Interest expense on this note during 2014 was $73,312.

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OnIn ~~October 14~~addition, ~~2009,~~at ~~PERC~~December ~~executed~~31, a2014 ~~promissory~~and ~~note~~2013, ~~payable~~PERC toowed ~~Teton~~TR ~~that~~Energy ~~would~~an ~~allow~~amount ~~the~~of ~~Company~~$127,652 toand ~~receive up to~~ $1122,~~000~~566,~~000. On~~ ~~March 2~~respectively, ~~2010~~in anconnection ~~amendment~~with toour ~~the~~purchase ~~promissory note was executed that provided additional funds available~~ of ~~$1.5~~a ~~million. The~~20% ~~note~~undivided ~~was amended on April 2, 2011, granting Teton the right to convert the outstanding balance on the note including accrued~~ interest ~~into~~in ~~shares~~their ofpipelines ~~common~~and ~~stock~~disposal ~~at a fixed conversion price of $0~~well.~~60 per share.~~ AsTR ofEnergy ~~December~~is ~~31,~~owned ~~2013,~~by ~~PERC had received $1,173,000 related to this note~~Messrs. ~~The~~ ~~accrued~~Neufeld ~~interest~~ and ~~outstanding principal are due on the maturity date of June 1, 2015~~Sudderth. ~~Interest expense on this note during 2013 was $73,308.~~

In addition, at December 31, 2013 and 2012, we owed TR Energy an amount of $122,566 and $112,502, respectively, in connection with our purchase of a 20% undivided interest in their pipelines and disposal well. TR Energy is owned by Messrs. Neufeld and Sudderth.

In July 2010, PERC entered into a participation agreement with Energi Drilling 2010A LP (“ED LP”) to raise funds for the drilling of the Norbord #1 and both the Swamp Fox #1 and Swamp Fox #2 wells. David Moss, a director of Pegasi until his resignation in January 2014, is a managing member and majority owner of Energi Management LLC (“EM”) and EM is the general partner of Energi Drilling 2010A LP. ED LP is a hedge fund that was established for the sole purpose of investing in oil and gas properties with PERC. All transactions under the participation agreement for these wells were finalized during 2011 when the drilling was completed on them.

In November 2011, PERC amended the participation agreement with ED LP to include the Haggard B well. PERC received $290,340 for a 15% working interest through completion on this well. In February 2012, the participation agreement with ED LP was further amended to include the Morse well. PERC received $195,397 for a 2.5% working interest on this well. In October 2012, ED LP signed an agreement with PERC holding ED LP responsible for their liability for all costs in relation to the abandonment of the Swamp Fox wells and giving ED LP a $40,000 credit on their drilling expenses for the Morse well. In March 2013, PERC issued a $10,000 credit to ED LP in final settlement of their liability on the abandonment costs of the Swamp Fox wells.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.

Audit Fees

The aggregate fees billed by our auditors, for professional services rendered for the audit of our annual consolidated financial statements during the years ended December 31, ~~2013~~2014 and ~~2012~~2013, and for the reviews of the consolidated financial statements included in our Quarterly Reports on Form 10-Q during the fiscal years, were approximately $9299,000 and $8692,000, respectively.

Audit-Related Fees

Our independent registered public accounting firm did not bill us during the years ended December 31, ~~2013~~2014 and ~~2012~~2013 for audit related services.

Tax Fees

Our independent registered public accounting firm did not bill us during fiscal years ended December 31, ~~2013~~2014 and ~~2012~~2013 for tax related services.

All Other Fees

Our independent registered public accounting firm did not bill us during the years ended December 31, ~~2013~~2014 and ~~2012~~2013 for other services. During the years ended December 31, ~~2013~~2014 and ~~2012~~2013, there were no amounts billed for other services.

The Board of Directors has considered whether the provision of non-audit services is compatible with maintaining the principal accountant's independence.

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PART IV.

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

Exhibit No.

Description

2.01	Share Exchange Agreement, filed as an exhibit to the current report on Form 8-K filed with the Securities and Exchange Commission on December 18, 2007 and incorporated herein by reference.

3.01	Articles of Incorporation, filed as an exhibit to the registration statement on Form SB-2 filed with the Securities and Exchange Commission on May 30, 2006 and incorporated herein by reference.

3.02	Amendment to Articles of Incorporation, filed as an exhibit to the current report on Form 8-K filed with the Securities and Exchange Commission on January 29, 2008 and incorporated herein by reference.

3.03	By-Laws, filed as an exhibit to the registration statement on Form SB-2 filed with the Securities and Exchange Commission on May 30, 2006 and incorporated herein by reference.

3.04	Amendment to Articles of Incorporation, filed as an exhibit to the current report on Form 8-K filed with the Securities and Exchange Commission on November 10, 2010 and incorporated herein by reference.

Filing Compare · Pegasi Energy Resources Corporation.