MANUFACTURED HOUSING PROPERTIES INC. - Annual Report: 2014 (Form 10-K)

roko_10k.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

Annual Report Under Section 13 or 15(d) of the

Securities Exchange Act of 1934

For the Fiscal Year Ended December 31, 2014

Commission File No. 000-51229

CAPROCK OIL, INC.

(Exact Name of Registrant as specified in its charter)

Nevada		51-0482104
(State or other jurisdiction of incorporation)		(IRS Employer Identification Number)

11011 Richmond Avenue, Suite 525 Houston, Texas		77042
(Address of principal executive offices)		(zip code)

(713) 479-7050

(Registrant's telephone number, including area code)

Securities Registered Under Section 12(b) of the Exchange Act:

None

Securities Registered Under Section 12(g) of the Exchange Act:

Common Stock, $0.01 par value

Indicate by check mark if the Registrant is a well-known seasoned issuer (as defined in Rule 405 of the Securities Act): Yes:o No: þ

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act): Yes: o No: þ

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. Yes: þ No: o

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Date File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months. Yes: þ No: o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K. þ

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 þ

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Act): Yes: o No: þ

The aggregate market value of Common Stock held by non-affiliates of the Registrant (based upon the closing price of such shares as quoted on the OTC Bulletin Board) as of the last business day of the most recently completed second fiscal quarter was approximately $12,426,000.

The number of shares outstanding of the Registrant's Common Stock as of March 26, 2015 was 51,813,477 shares.

CAPROCK OIL, INC.

(formerly, Stratum Holdings, Inc.)

2014 FORM 10-K

INDEX

			Page

PART I
	Item 1 and 2.	Description of Business and Properties.	3

	Item 3.	Legal Proceedings.	5

PART II
	Item 5.	Market for Registrant’s Common Equity, Related StockholderMatters and Issuer Purchases of Equity Securities.	6

	Item 6.	Selected Financial Data.	6

	Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations.	7

	Item 8.	Financial Statements and Supplementary Data.	10

	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.	10

	Item 9A.	Controls and Procedures.	11

	Item 9B.	Other Information.	11

PART III
	Item 10.	Directors, Executive Officers and Corporate Governance.	12

	Item 11.	Executive Compensation.	13

	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	14

	Item 13.	Certain Relationships and Related Transactions, and Director Independence.	14

	Item 14.	Principal Accounting Fees and Services.	15
PART IV
	Item 15.	Exhibits, Financial Statement Schedules.	16

		Signatures.	34

PART I

Item 1 and 2. Description of Business and Properties.

Caprock Oil, Inc., formerly, Stratum Holdings, Inc. (“we”, “our” or the “Company”), is an energy company headquartered in Houston, Texas, which operates in the Exploration & Production business. With our wholly-owned subsidiaries, we maintain working interests in approximately 45 producing oil and gas wells in Texas and Louisiana, with average net production of approximately 100 barrels of oil equivalent per day. As of December 31, 2014, we had proved reserves of 279,000 barrels of oil and 467,000 Mcf of gas with a pre-tax discounted present value of $5,905,000. We seek to increase shareholder value through a balanced program of acquisitions, exploitation and exploration.

Historically, our legacy subsidiaries, CYMRI, L.L.C. (“CYMRI”) and Triumph Energy, Inc. (“Triumph”), were focused solely on long-lived production operations in Texas and Louisiana. In March 2014, we completed the acquisition of Cinco NRG, LLC (“Cinco”), a private oil and gas company, which was under common control by our majority shareholder, Pioneer Group, LLC (“Pioneer”). At the time of the acquisition, Cinco had a small working interest in a producing field in Texas as well as working interests in two exploratory prospects in Alabama. We acquired Cinco through a share exchange resulting in the former members of Cinco, including Pioneer, now owning approximately 96% of our total shares of Common Stock outstanding (which reflects additional share purchases made subsequent to March 2014). In conjunction with that transaction, we also changed our name to Caprock Oil, Inc.

Since completing the Cinco acquisition, we have undertaken a redefinition of our corporate strategy. We have increased our management team and expanded our portfolio of current and prospective projects. In these endeavors, we are building from a combination of acquisitions and low risk drilling prospects. We are continuously developing and refining our portfolio of new opportunities, primarily along the Texas Gulf Coast, with the objective of enhancing growth while mitigating risk.

The following sections provide additional background information on our activities in the Exploration & Production business.

Exploration & Production

Our Exploration & Production operations commenced with the acquisition of CYMRI’s predecessor company in May 2006 for a combination of cash, notes payable and Common Stock totaling $12.7 million. CYMRI was originally formed in July 2001 by shareholders of the predecessor company to acquire long-lived oil and gas reserves. CYMRI completed several oil and gas property acquisitions in South Texas, primarily known as the Burnell and Kibbe Fields, in 2001-2003.

CYMRI had previously acquired a Louisiana energy consulting company, Petroleum Engineers, Inc. (“PEI”), in June 2004 for total consideration of $5.1 million and that acquisition included working interests in various non-operated oil and gas properties in South Louisiana owned by Triumph, which was a PEI affiliate at that time. The Company’s subsequent sale of PEI to another company in March 2008 did not include the oil and gas properties of Triumph.

Shown below are certain SEC required disclosures regarding our currently owned oil and gas properties in the Exploration & Production business.

Oil and Gas Reserves

The following table sets forth summary information with respect to the estimates of our proved oil and gas reserves, as of December 31, 2014, prepared by Prator Bett, L.L.C., our independent reservoir engineering firm:



	Oil		Gas		Total		PV10 Value
	(MBbl)		(MMcf)		(MBoe)		(000's)

Proved developed reserves		271		467		349	$	5,574
Proved undeveloped reserves		8		-		8		331
Total proved reserves		279		467		357		5,905
Discounted future income taxes								(1,346	)
Standardized measure of discounted
future net cash flows							$	4,559

Proved reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. The technical persons responsible for preparing our reserve estimates are independent petroleum engineers that meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We employ adequate internal controls over the data provided to our independent reservoir engineers to insure that our reserve estimates are in compliance with the Securities and Exchange Commission (“SEC”) definitions and guidance.

In accordance with the guidelines of the SEC, the reservoir engineers’ estimates of future net revenues from our properties and the pre-tax PV 10 Value amounts thereof are made using oil and gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. The average beginning of the month prices for the year ended December 31, 2014 used in such estimates were $88.26 per barrel of oil and $3.92 per Mcf of gas.

Productive Oil and Gas Wells and Acreage

As of December 31, 2014, we maintained ownership interests in a total of 32.0 gross (21.3 net) productive wells in the State of Texas and 14.0 gross (1.7 net) productive wells in the State of Louisiana for a grand total of 46.0 gross (23.0 net) productive oil and gas wells.

In the year ended December 31, 2014, we participated in the drilling of 1.0 gross (0.1 net) new development well, which was successful, and 1.0 gross (0.05 net) new exploratory well, which was unsuccessful. As of December 31, 2014, we had prepaid our share of the drilling costs for 2.0 gross (0.45 net) non-operated wells to be drilled in 2015. We did not participate in the drilling of any new oil and gas wells in the years ended December 31, 2013 and 2012.

As of December 31, 2014, we had ownership interests in approximately 8,503 gross (6,731 net) productive acres in the States of Texas and Louisiana. As of December 31, 2014, we had ownership interests in approximately 5,400 gross (1,200 net) undeveloped acres in the States of Texas and Alabama.

Production Prices and Costs

The average per barrel oil price received for our net oil production in the years ended December 31, 2014, 2013 and 2012 were $86.96, $96.80 and $97.42, respectively. The average per Mcf gas price received for our net gas production in the years ended December 31, 2014, 2013 and 2012 were $3.72, $3.26 and $2.75, respectively. In the same periods, our net production costs averaged $42.78, $36.38 and $38.70, respectively, per BOE.

Our oil and gas production is sold to various purchasers in the States of Texas and Louisiana at spot or market sensitive prices under short-term contracts. We had no delivery commitments in the three years ended December 31, 2014.

Competition

Competition in the Exploration & Production business is extremely intense. Competitors include major oil and gas companies, large and small independent producers, and individual producers and operators. Many competitors have financial resources substantially greater than ours, and staffs and facilities substantially larger than ours. In the Exploration & Production business, our success in operating our existing oil and gas properties as well as in acquiring and developing additional properties will depend on our ability to operate in this highly competitive environment.

Employees

As of December 31, 2014, the Company had a total of 5 full-time employees at its corporate headquarters located in Houston, Texas. All of these individuals are co-employed by CYMRI, L.L.C. and Insperity, Inc., a professional employer organization. Our field operations and certain administrative functions are performed substantially by independent contractors in Texas and Louisiana.

Regulation

The oil and gas industry is subject to extensive federal and state governmental regulations which affect our Exploration & Production business. These governmental mandates include federal and state regulations governing environmental quality and pollution control, state limits on allowable rates of production by individual well or proration unit, the amount of oil and gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels.

Oil and Gas Terminology

The following terms are used to describe quantities of oil and natural gas in this document.

●	Bbl—One stock tank barrel, or 42 US gallons liquid volume, of crude oil or other liquid hydrocarbons.

●	BOE—Barrel of oil equivalent, converting gas to oil at the ratio of 6 Mcf of gas to 1 Bbl of oil.

●	Mcf—One thousand cubic feet of natural gas.

●	MBbl—One thousand Bbls.

●	MMcf—One million cubic feet of natural gas.

Available Information

Our website address is www.caprockoil.com, however, the website information is not part of this report. We file annual, quarterly, and special reports, proxy statements, and other information periodically with the SEC. Such reports, proxy statements and other information filed with the SEC may be accessed electronically by means of the SEC's website at www.sec.gov. This material may also be inspected and copied at the public reference facilities of the SEC at 100 F Street N.E., Washington, DC 20549.

Item 3. Legal Proceedings.

See Note 11 to our Consolidated Financial Statements.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Since July 2005, our Common Stock has been quoted and traded on the OTCQB Marketplace and its processor, the OTC Bulletin Board. Beginning in March 2007, our trading symbol was changed to “STTH” and, in March 2014, it was changed to “ROKO.” Because we trade on this platform, a shareholder may find it difficult to dispose of or obtain accurate quotations as to price of our Common Stock. In addition, the Securities Enforcement and Penny Stock Reform Act of 1990 requires additional disclosure related to the market for penny stock and for trades in any stock defined as a penny stock.

In December 2009, we completed a 1-for-10 reverse stock split of our Common Stock, pursuant to a plan approved by our Board of Directors. Accordingly, all Common Stock share and per share amounts in this annual report have been retroactively adjusted to reflect the reverse stock split. As of March 26, 2015, we had a total of 51,813,477 shares of our Common Stock outstanding and the number of holders of record of our Common Stock at that date was approximately 130. The following table sets forth the high and low bid prices of our Common Stock for each quarter during the calendar years 2013 and 2014:

	Bid Price
	High		Low
2013
First Quarter	$	0.10	$	0.08
Second Quarter	$	0.13	$	0.08
Third Quarter	$	0.08	$	0.08
Fourth Quarter	$	0.51	$	0.08
2014
First Quarter	$	0.90	$	0.20
Second Quarter	$	1.07	$	0.65
Third Quarter	$	1.59	$	0.85
Fourth Quarter	$	1.04	$	0.65

We have never declared nor paid any cash dividends on our Common Stock and do not anticipate declaring any dividends in the foreseeable future. We expect to retain our cash for the operation and maintenance of our business. In addition, our senior bank credit facility contains restrictions on the payment of dividends to the holders of our Common Stock. We have made no repurchases of our Common Stock for the year ended December 31, 2014.

The Company has an equity-based compensation plan which was approved by the stockholders in October 2005 and amended in October 2006. Under the plan, as amended, a maximum of 240,000 shares may be awarded to directors and employees via the issuance of equity-based derivatives in the form of stock options, registered stock or stock appreciation rights. Pursuant to the terms of the plan, we made a grant of 240,000 registered shares of our Common Stock in March 2014 to a consultant who performed services for the Company resulting in no additional shares being available under that plan. A new stock-based compensation plan has not been formally approved, however, we have reserved 4,000,000 shares of Common Stock for future issuance under such a plan. Meanwhile, the Company’s only equity-based derivatives outstanding, are non-registered options to acquire 2,000,000 shares of our Common Stock at an exercise price of $0.65 per share, which were granted to our new Chief Executive Officer in May 2014 (see Note 8 to our Consolidated Financial Statements).

Item 6. Selected Financial Data.

Information for this Item is not required as the Registrant is a “smaller reporting company” as defined in Rule 12b-2 of the Exchange Act.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion of our financial condition and results of operations should be read in conjunction with, and is qualified in its entirety by, the Company’s consolidated financial statements and notes thereto included in Item 8 in this Annual Report on Form 10-K. This item contains forward-looking statements that involve risks and uncertainties. Actual results may differ materially from those indicated in such forward-looking statements.

Overview

We are an energy company operating in the Exploration & Production business. In that business, we maintain working interests in approximately 45 producing oil and gas wells in Texas and Louisiana, with average net production of approximately 100 barrels of oil equivalent per day. As of December 31, 2014, we had proved reserves of 279,000 barrels of oil and 467,000 Mcf of gas with a pre-tax discounted present value of $5,905,000. We seek to increase shareholder value through a balanced program of acquisitions, exploitation and exploration.

On March 17, 2014, we completed the acquisition of Cinco, a private oil and gas company, which was under common control by our majority shareholder. We acquired Cinco through the issuance of a total of 46,942,538 shares of our Common Stock. At the time of the acquisition, Cinco had a small working interest in a producing field in Texas as well as working interests in two exploratory prospects in Alabama. Under the accounting rules for entities under common control, we have reflected Cinco’s operations on a retroactive basis in our consolidated financial statements from the inception of Cinco in April 2013.

Through June 3, 2011, we also operated in the Canadian Energy Services business. On that date, we sold the outstanding capital stock of our Canadian Energy Services subsidiary to a private company for a total sales price of $4,600,000 (plus a working capital adjustment). Included in the consideration for this sale was interest bearing notes issued by the purchaser in the amount of $1,850,000, payable in 48 monthly installments of principal and interest. Following a dispute with the purchaser on the payment of such notes, we reached an agreement with the purchaser on a settlement of the outstanding balance in December 2013 (see Note 4).

Results of Operations

The following discussion reflects the revenues and expenses for the years ended December 31, 2014 and 2013, as reported in our consolidated financial statements and notes thereto included in Item 8.

Year ended December 31, 2014 versus year ended December 31, 2013 — Total revenues, not including interest income, were $2,362,000 for the year ended December 31, 2014 compared to $2,728,000 for the year ended December 31, 2013.

Revenues from oil and gas sales for the year ended December 31, 2014 were $2,362,000 compared to $2,728,000 for the year ended December 31, 2013. In the year ended December 31, 2014, revenues from oil production were $2,114,000, reflecting volumes of 24,310 barrels at an average price of $86.96 per barrel, while gas revenues were $248,000, reflecting volumes of 66,563 Mcf at an average price of $3.72 per Mcf. On an overall basis, these amounts reflect a decrease in production volumes of approximately 4%, resulting primarily from a major workover of our largest producing oil and gas well in the first quarter of 2014, further exacerbated by a decrease in average oil and gas prices of approximately 10%. We anticipate that our existing oil and gas production volumes will slowly decline in future periods while we expect continued volatility in oil and gas commodity prices in the future.

Lease operating expenses (“LOE”), including production taxes, were $1,514,000 for the year ended December 31, 2014 versus $1,337,000 for the year ended December 31, 2013. This increase was largely due to certain non-recurring expenses and structural changes in our field operations.

Depreciation, depletion and amortization (“DD&A”) expense for the year ended December 31, 2014 was $573,000 versus $443,000 for the year ended December 31, 2013. This increase resulted from the higher depletion rates in 2014.

Accretion expense on asset abandonment obligations for the year ended December 31, 2014 was $40,000 versus $37,000 for the year ended December 31, 2013, essentially equivalent amounts in both periods.

Workover expenses for the year ended December 31, 2014 were $942,000 versus $293,000 for the year ended December 31, 2013. This increase was due to the unanticipated workover of our largest producing oil and gas well in the first quarter of 2014 and the unexpectedly high workover costs of our largest water injection well in the second quarter of 2014; both of these wells were located in our Burnell Field.

Selling, general and administrative (“SG&A”) expenses for the year ended December 31, 2014 were $1,619,000 compared to $1,027,000 for the year ended December 31, 2013. This increase was largely due to non-cash stock compensation expense of $694,000 in 2014 (see Note 8).

Interest income for the year ended December 31, 2014 was less than $1,000 versus $50,000 for the year ended December 31, 2013. This reduction resulted from the absence of interest income on long-term notes receivable which were settled in late 2013 (see Note 4).

Interest expense for the year ended December 31, 2014 was $162,000 versus $131,000 for the year ended December 31, 2013. This increase was mostly due to the higher outstanding borrowings in 2014.

Loss on settlement of notes receivable for the year ended December 31, 2014 was zero versus $286,000 for the year ended December 31, 2013. The prior year amount reflects the loss on a settlement of the notes receivable issued in the 2011 sale of a former subsidiary (see Note 4).

Gain on oil and gas derivatives for the year ended December 31, 2014 was zero versus $5,000 for the year ended December 31, 2013. This fluctuation was due to the change in fair value of CYMRI’s outstanding oil and gas derivative contracts which expired in late 2013 (see Note 5).

Income taxes were a benefit of $497,000 for the year ended December 31, 2014 compared to a provision of $792,000 for the year ended December 31, 2013. These annual amounts reflected consolidated income tax rates of 20% and (103%), respectively. As further described in Note 9, we recognized an adjustment in the year ended December 31, 2013 to substantially reduce the carrying value of the deferred tax asset associated with our tax operating loss carryforwards as a result of a “change of control” transaction occurring in September 2013. Due to this adjustment, we reported a tax provision in the year ended December 31, 2013, notwithstanding the fact that we had a pre-tax net loss for that period.

Liquidity and Capital Resources

Operating activities. Net cash used in operating activities was $553,000 for the year ended December 31, 2014 compared to $44,000 for the year ended December 31, 2013. This difference was primarily due to the comparatively higher cash operating loss in the year ended December 31, 2014.

Investing activities. Net cash used in investing activities was $912,000 for the year ended December 31, 2014 compared to net cash provided by investing activities of $242,000 for the year ended December 31, 2013. This fluctuation largely resulted from the settlement of the notes receivable from the purchaser of our Canadian Energy Services subsidiary in December 2013 in the amount of $950,000.

Financing activities. Net cash provided by financing activities was $668,000 for the year ended December 31, 2014 compared to $167,000 for the year ended December 31, 2013. Proceeds of new debt and equity financings totaling $1,300,000 in the 2014 period and new debt financing of $1,029,000 in the 2013 period, were partially offset by essentially equivalent debt payments in both periods.

As disclosed in Note 6, a substantial portion of our existing long term debt is in the form of a bank credit facility secured by CYMRI/Triumph’s producing oil and gas properties. Borrowings under the bank credit agreement are subject to a borrowing base, which is periodically redetermined, based on oil and gas reserves. Pursuant to the latest borrowing base determination, we were required to make principal payments of $50,000 per month during 2014. Such principal payments were made in the first eleven months of the year, however, we did not make the required monthly principal payment in December 2014 and are, therefore, in default of the credit agreement. Under its terms, the credit agreement expired on January 1, 2015, and we are continuing to negotiate with the bank on a resolution of the outstanding borrowings of $1,286,000 under the expired credit agreement. Additionally, we are actively seeking new sources of debt and equity capital.

We also have other debt amounts outstanding as more fully described in Note 6 and reflected in the table below (however, we have no off Balance Sheet arrangements). The following table sets forth the contractual obligations under our long-term debt and operating lease agreements as of December 31, 2014 (in thousands):

			Payments Due By Period
	Total		2015			2016-2017		2018-2019	After 2019

Long-term debt	$	2,052	$	2,052	$	-	$	-	$	-
Interest on long-term debt		213		213		-		-		-
Operating leases for office space		162		60		102		-		-

Total	$	2,427	$	2,325	$	102	$	-	$	-

Capital expenditures in the Exploration & Production business can be highly intensive. Expenditures for drilling and equipping of oil and gas wells are typically required to maintain or increase production levels. We normally attempt to finance such capital expenditure requirements through a combination of cash flow from operations and secured bank borrowings. We presently have relatively low capital expenditure requirements relating to our legacy oil and gas properties, however, we expect that our capital expenditures will increase significantly in the future as a result of the new oil and gas properties that we have acquired in the Cinco acquisition as well as other new potential opportunities that we may pursue.

In order to address our increased capital expenditure needs, we reached a preliminary agreement with a major mezzanine lender in October 2014 for a three year credit facility to replace our expiring bank credit agreement. We originally expected to close the mezzanine credit facility in December 2014, however, we were unable to reach such a closing due to the dramatic decline in worldwide oil prices beginning in the third quarter of 2014. To the extent feasible in the current oil pricing environment, we are endeavoring to replicate the scope of that type of financing arrangement as we continue to seek new sources of debt and equity capital. Additionally, we are considering a possible sale of some of our producing properties as a potential source of liquidity.

Prior to pursuing the mezzanine credit facility, we commenced a private equity offering of our Unit securities in June 2014. Through December 31, 2014, we had sold a total of 300,000 Units to accredited investors, with each Unit comprised of two shares of Common Stock and a Warrant to purchase a third share of Common Stock, resulting in gross proceeds of $600,000. We are authorized to sell up to 4,000,000 Units in this private equity offering, however, we are no longer actively marketing the sale of any additional Unit securities.

Going Concern

The accompanying consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. The Company has reported net losses from continuing operations in the last two years and presently has a working capital deficit in the amount of $4,376,000. These factors, among others, indicate that the Company may be unable to continue as a going concern for a reasonable period of time. The consolidated financial statements do not contain any adjustments to reflect the possible future effects on the classification of assets or the amounts and classification of liabilities that may result should the Company be unable to continue as a going concern.

Critical Accounting Policies and Estimates

Our current business operations are in the Exploration & Production business. Shown below are the critical accounting policies pertaining to that industry.

In our Exploration & Production business, we have adopted the “full cost” method of accounting for oil and gas properties. Under full cost accounting, all costs associated with acquisition, exploration, and development of oil and gas reserves, including directly related overhead costs, are capitalized. Other significant features of full cost accounting are as follows:

●

All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the unit-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 is added to the capitalized costs to be amortized.

●

The capitalized costs are subject to a “ceiling test,” which basically limits such costs to the aggregate of the “estimated present value,” discounted at a 10-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.

●

Sales of 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 income. Abandonments of properties are accounted for as adjustments of capitalized costs with no loss recognized.

In our Exploration & Production business, there is also a significant degree of complexity in our accounting for income taxes due to substantial differences between the financial accounting and tax treatments for certain oil and gas property expenditures.

Item 8. Financial Statements and Supplementary Data.

The required financial statements are included in this report as set forth in the “Index to Consolidated Financial Statements” on page 17.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

(a) Disclosure Controls and Procedures

Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in reports that it files under the Securities Exchange Act of 1934 (the “Act”) is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, to allow for timely decisions regarding required disclosures. As of the end of the period covered by this Annual Report, we carried out an evaluation, under the supervision of our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures.

Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures as of the end of the period covered by this Annual Report were not effective because of a lack of segregation of duties, as described in item 9A. (b) below, which we view as an integral part of our disclosure controls and procedures.

(b) Management’s Annual Report on Internal Controls over Financial Reporting

Management is responsible for establishing and maintaining adequate internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act). Because of its inherent limitation, internal controls over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness of such controls to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management has performed an assessment of the effectiveness of our internal controls over financial reporting as of December 31, 2014. In making this assessment, management elected to use the criteria set forth in Internal Control – Integrated Framework (1992) created by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) as the chosen internal control framework. Based on our assessment using those criteria, management concluded that our internal controls over financial reporting were not effective at the reasonable assurance level, primarily due to a lack of segregation of duties in financial reporting. To the extent practical in light of its current financial condition, the Company will consider expanding financial reporting resources in the future.

This Annual Report does not include an attestation report of our independent registered public accounting firm regarding our internal controls over financial reporting. Management’s report was not subject to attestation by our independent registered public accounting firm pursuant to SEC rules that permit the Company to provide only management’s assessment in this Annual Report. Accordingly, management’s assessment has not been audited by MaloneBailey LLP or any other independent registered public accounting firm.

There was no change in our internal controls over financial reporting that occurred during the quarter ended December 31, 2014, that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

Item 9B. Other Information.

None.

PART III

Item 10. Directors, Executive Officers, Promoters, Control Persons and Corporate Governance.

Directors and Executive Officers

The following table sets forth our Directors and Executive Officers, their ages and positions held with us as of March 26, 2015:

Name	Age	Position
Steven H. Mikel	63	President and Chief Executive Officer
D. Hughes Watler, Jr.	66	Director and Chief Financial Officer
Robert G. Wonish	61	Director
Christopher T. George	43	Director

Steven H. Mikel was named as our President and Chief Executive Officer in May 2014 bringing over thirty years’ experience in both the financial and operating sides of the oil and gas business. He served as the President and Chief Executive Officer of various private equity funded Chroma companies from 2004 to 2011. He also served as President and Chief Executive Officer of Southern Mineral Corp. (a NASDAQ listed company) from January 1995 until its merger in 2001. He co-founded Resource Investors Management ... Company (RIMCO), an oil and gas investment management company, in 1984, and served as its Managing Director from October 1985 to April 1993. He began his career as a corporate finance attorney and then worked in finance with Aetna Life and Casualty, where he specialized in the natural resource industries.

D. Hughes Watler, Jr. has served as our Chief Financial Officer since February 2007 and also functioned as our senior executive officer from April 2013 to May 2014. He previously served as Senior Vice President & Chief Financial Officer of Goodrich Petroleum Corporation (NYSE: GDP) from 2003 to 2006 and as a financial officer of several other public and private energy companies from 1992 to 2003. Prior thereto, he was an audit partner with Price Waterhouse LLP from 1986 to 1992 and was on the firm’s audit staff from 1973 to 1986.

Robert G. Wonish was named as a director on March 17, 2014. Mr. Wonish has served as the President of Petrodome Operating, LLC, a private oil and gas company in Houston, since 2009. He has nearly 40 years of experience as an engineer in the oil and gas industry. He previously served the Company as an executive officer and member of the Board of Directors from May 2006 to March 2008. Mr. Wonish was also a member of the Board of Directors of Enerjex Resources, Inc. (OTC: ENRJ) from May 2007 to April 2010.

Christopher T. George was named as a director on March 17, 2014. Mr. George is currently Director, Oilfield Services Group, with PLS, Inc., a privately owned energy transaction advisory firm, based in Houston. Prior to his present position, Mr. George was Senior Advisor – Corporate Development of Southwestern Energy, Inc. (NYSE: SWN), from October 2008 to March 2013. Previously, he served as a financial analyst covering the energy industry with Capital One Southcoast from March 2004 to July 2007.

Corporate Governance

The Board and management strive to perform and fulfill their respective duties and obligations in a responsible and ethical manner. The Company has not formally adopted a code of ethics, however, it will consider the adoption of a code of ethics at a future date as growth and other circumstances should dictate. At the present time, we are a small company and our management is in close contact with the daily activities of all employees. Accordingly, we do not believe that it would represent a cost effective use of our limited financial resources to incur the legal fees and other expenses that would be required to implement a formal code of ethics.

Section 16(a) Beneficial Ownership Reporting Compliance

Under the Exchange Act, our directors, our executive officers, and any persons holding more than 10% of our Common Stock are required to report their ownership of the Common Stock and any changes in that ownership to the Commission. Specific due dates for these reports have been established and we are required to report any failure to file by these dates during the year fiscal ended December 31, 2014. The Company is not aware of any such persons who have not filed timely reports required by Section 16(a) of the Exchange Act for the year ended December 31, 2014.

Item 11. Executive Compensation

The following table summarizes certain information with respect to the compensation earned by the Company’s executive officers for services rendered in all capacities during the years indicated.

Summary Compensation Table

													Nonequity
	Fiscal	Annual Compensation					Stock			Option			Incentive		All Other			Total
Name & Principal Position	Year	Salary			Bonus		Awards			Awards			Comp.		Comp.			Comp.

Steven H. Mikel
Chief Executive Officer	2014	$	75,000	(1)	$	-	$	-		$	371,400	(2)	$	-	$	2,800	(5)	$	449,200

Larry M. Wright
Chief Executive Officer	2013	$	62,574	(3)	$	-	$	-		$	-		$	-	$	2,503	(5)	$	65,077

D. Hughes Watler, Jr.	2014	$	90,000		$	-		190,970	(4)	$	-		$	-	$	2,700	(5)	$	283,670
Chief Financial Officer	2013	$	93,750		$	-	$	-		$	-		$	-	$	2,813	(5)	$	96,563

(1)	Represents Mr. Mikel’s salary since he joined the Company as Chief Executive Officer in May 2014.

(2)	Reflects amortized grant date fair value of stock option awards to Mr. Mikel as further described in Note 8 to our Consolidated Financial Statements.

(3)	Represents Mr. Wright’s salary as Chief Executive Officer until the time of his death in April 2013.

(4)	Reflects amortized grant date fair value of restricted stock awards to Mr. Watler as further described in Note 8 to our Consolidated Financial Statements.

(5)	Represents the Company’s annual matching contribution to a company sponsored 401(k) Plan on behalf of each officer.

Outstanding Equity Awards at 2014 Fiscal Year-End

The following table sets forth all outstanding stock and option awards held by our named executive officers as of December 31, 2014.

	Stock and Option Awards
Name	Number of Securities Underlying Unexercised Options Exercisable (#)		Number of Securities Underlying Unexercised Options Unexercisable (#)		Option Exercise Price ($)		Option Expiration Date
Steven H. Mikel		200,000		1,800,000	$	0.65	5/19/2017

D. Hughes Watler, Jr.		-0-		-0-		-0-		N/A

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The following table sets forth information as to the shares of Common Stock beneficially owned as of March 26, 2015 by (i) each person known to us to be the beneficial owner of more than 5% of our Common Stock; (ii) each Director; (iii) each Executive Officer; and (iv) all of our Directors and Executive Officers as a group. Unless otherwise indicated in the footnotes following the table, the persons as to whom the information is given had sole voting and investment power over the shares of Common Stock shown as beneficially owned by them.

	Beneficial Ownership
Directors and Executive Officers	Amount		Percent
Steven H. Mikel (1)		200,000	*
D. Hughes Watler, Jr. (2)		1,252,000	2.4
Robert G. Wonish (3)		2,700,000	5.2
Directors and Executive Officers as a Group (4)		4,152,000	8.0

Other 5% Beneficial Owners
Pioneer Group, LLC (5)		36,023,140	69.8

*	Less than 1%

(1)	Includes the following securities: (a) No shares of Common Stock held by Mr. Mikel on his own behalf; and (b) 200,000 currently vested options to purchase shares of Common Stock.

(2)	Includes the following securities: (a) 1,252,000 shares of Common Stock held by Mr. Watler on his own behalf; and (b) no currently vested options or warrants to purchase shares of Common Stock.

(3)	Includes the following securities: (a) 2,700,000 shares of Common Stock held by Mr. Wonish on his own behalf; and (b) no currently vested options or warrants to purchase shares of Common Stock.

(4)	Includes the following securities: (a) 3,952,000 shares of Common Stock held by Directors and Officers on their own behalf; and (b) 200,000 currently vested options or warrants held by Directors and Officers to purchase shares of Common Stock.

(5)	Includes the following securities: (a) 36,023,140 shares of Common Stock held by Pioneer Group, LLC on its own behalf; and (b) no currently vested options or warrants to purchase shares of Common Stock. The address of Pioneer Group, LLC is 201 S. Phillips Avenue, Suite 200, Sioux Falls, SD 57104.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

Robert G. Wonish, who was elected as a director of the Company in March 2014, is the President of Petrodome Operating, LLC (“Petrodome”), a private oil and gas company, which has a substantial number of oil and gas properties along the Gulf Coast areas of Texas and Louisiana. Among the properties that Petrodome operates is a producing field in Texas in which Cinco has had a 10% working interest since August 2013. Additionally, Petrodome served as the operator of an unsuccessful well drilled in Louisiana in which Cinco participated for a 5% working interest in July 2014. In both of these instances, Petrodome billed Cinco for its share of the capital and operating costs of the properties, under a standard industry joint operating agreement (“JOA”).

Notwithstanding the relationship of Robert G. Wonish with a vendor of the Company, as indicated above, both Mr. Wonish and Christopher T. George, who was also elected as a director of the Company in March 2014, are considered to be “independent” directors as that term is defined by The Nasdaq Stock Market.

Item 14: Principal Accounting Fees and Services.

MaloneBailey LLP has served as our independent registered public accounting firm since the year ended December 31, 2008. The following table presents fees for professional audit services rendered by MaloneBailey LLP for the years ended December 31, 2014 and 2013 in their audits of our annual financial statements.

	2014		2013
Audit Fees	$	67,500	$	70,500
Audit-related Fees		-		22,500
Tax Fees		-		-
Other Fees		-		-
	$	67,500	$	93,000

Audit-related fees in the year ended December 31, 2013 pertain to the audit of the financial statements of Cinco NRG, LLC, which the Company acquired in March 2014.

PART IV

Item 15. Exhibits, Financial Statement Schedules.

The following Exhibits are required to be filed pursuant to Item 601 of Regulation S-K:

EXHIBIT NO.		DESCRIPTION
3.1		Articles of Incorporation of Tradestar Services, Inc. (incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement on Form SB-2 filed July 30, 2004)
3.2		Bylaws of the Company (incorporated by reference to Exhibit 3.2 of the Company’s Registration Statement on Form SB-2 filed July 30, 2004)
3.3		Certificate of Amendment to Articles of Incorporation of Tradestar Services, Inc. (incorporated by reference to Exhibit 3.3 of the Company’s Annual Report for the year ended December 31, 2005)
3.4		Certificate of Amendment to Articles of Incorporation of Tradestar Services, Inc. (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed March 8, 2007)
3.5		Certificate of Amendment to Articles of Incorporation of Stratum Holdings, Inc. (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed March 17, 2014)
10.1		Second Amended and Restated Credit Agreement, dated August 5, 2008, among CYMRI, L.L.C. and Triumph Energy, Inc. (as Borrowers) and Texas Capital Bank, N.A. (as Lender) for a Reducing Revolving Line of Credit of up to $25,000,000 (a)
10.2		Guaranty Agreement, dated August 5, 2008, executed by Stratum Holdings, Inc. (Guarantor) for benefit of Texas Capital Bank, N.A (as Lender) (a)
10.3		Promissory Note, dated August 5, 2008, issued by CYMRI, L.L.C. and Triumph Energy, Inc. (as Makers) to Texas Capital Bank, N.A. (as Payee) in amount of $25,000,000 (a)
10.4		Security Agreement, dated August 5, 2008, among CYMRI, L.L.C. and Triumph Energy, Inc.
		(as Debtors) and Texas Capital Bank, N.A. (as Secured Party) (a)
10.5		First Amendment to Second Amended and Restated Credit Agreement, dated May 28, 2009, among CYMRI, L.L.C. and Triumph Energy, Inc. (as Borrowers) and Texas Capital Bank, N.A. (as Lender) for a Reducing Revolving Line of Credit of up to $25,000,000 (b)
10.6		Second Amendment to Second Amended and Restated Credit Agreement, dated November 16, 2009, among CYMRI, L.L.C. and Triumph Energy, Inc. (as Borrowers) and Texas Capital Bank, N.A. (as Lender) for a Reducing Revolving Line of Credit of up to $25,000,000 (c)
10.7		Exhibits I through VI to Second Amended and Restated Credit Agreement, dated August 5, 2008, among CYMRI, L.L.C. and Triumph Energy, Inc. (as Borrowers) and Texas Capital Bank, N.A. (as Lender) for a Reducing Revolving Line of Credit of up to $25,000,000 (d)
10.8		Share Exchange Agreement by and among Stratum Holdings, Inc. and the members of Cinco NRG, LLC, dated as of January 17, 2014 (e)
21.1		Subsidiaries of the Registrant CYMRI, L.L.C. (Nevada) Triumph Energy, Inc. (Louisiana) Deployed Energy, Inc. (Nevada) Stratum Construction Services, Inc. (New Mexico) Cinco NRG, LLC (Wyoming)
31.1		Certification of Chief Executive Officer pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002*

31.2		Certification of Chief Financial Officer pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002*

32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*

101.INS 101.SCH 101.CAL 101.LAB 101.PRE 101.DEF		XBRL Instance Document (f) XBRL Taxonomy Extension Schema Document (f) XBRL Taxonomy Extension Calculation Linkbase Document (f) XBRL Taxonomy Extension Label Linkbase Document (f) XBRL Taxonomy Extension Presentation Linkbase Document (f) XBRL Taxonomy Extension Definition Linkbase Document (f)

(a) Incorporated by reference to the Exhibits to the Company’s Quarterly Report on Form 10-Q filed August 13, 2008.

(b) Incorporated by reference to the Exhibits to the Company’s Quarterly Report on Form 10-Q filed August 11, 2009.

(d) Incorporated by reference to the Exhibits to the Company’s Quarterly Report on Form 10-Q filed August 11, 2010.

(e) Incorporated by reference to the Exhibits to the Company’s Current Report on Form 8-K filed March 17, 2014.

(f)	Submitted electronically herewith.

* Filed or furnished herewith.

CAPROCK OIL, INC.

(formerly, Stratum Holdings, Inc.)

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page (s)

Report of Independent Registered Public Accounting Firm	18

Consolidated Balance Sheets as of December 31, 2014 and 2013	19

Consolidated Statements of Operations for the years ended December 31, 2014 and 2013	20

Consolidated Statements of Stockholders' Equity for the years ended December 31, 2014 and 2013	21

Consolidated Statements of Cash Flows for the years ended December 31, 2014 and 2013	22

Notes to Consolidated Financial Statements	23-33

Report of Independent Registered Public Accounting Firm

To the Board of Directors

Caprock Oil, Inc.

(formerly, Stratum Holdings, Inc.)

Houston, Texas

We have audited the accompanying consolidated balance sheets of Caprock Oil, Inc. (formerly, Stratum Holdings, Inc.) and its subsidiaries (collectively, the “Company”) as of December 31, 2014 and 2013 and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 consolidated financial position of Caprock Oil, Inc. (formerly, Stratum Holdings, Inc.) and its subsidiaries at December 31, 2014 and 2013 and the consolidated 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 financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 3, the Company has losses from continuing operations and has a working capital deficit. These factors raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 3. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/S/ MaloneBailey LLP

Houston, Texas

March 26, 2015

CAPROCK OIL, INC.

(formerly, Stratum Holdings, Inc.)

Consolidated Balance Sheets

	December 31,
	2014			2013
				(As Restated)
Assets
Current assets:
Cash and cash equivalents	$	80,025		$	877,525
Accounts receivable (less allowance for doubtful accounts of
$228,574 at December 31, 2014 and 2013)		270,132			342,676
Prepaid expenses and other		49,586			74,650
Total current assets		399,743			1,294,851

Property and equipment:
Oil and gas properties, evaluated (full cost method)		16,046,178			15,474,723
Oil and gas properties, unevaluated (full cost method)		1,005,603			360,859
Other property and equipment		40,978			40,978
Total property and equipment		17,092,759			15,876,560
Less: Accumulated depreciation, depletion and amortization		(10,536,660	)		(9,963,444	)
Net property and equipment		6,556,099			5,913,116

Other assets:
Other noncurrent assets		5,238			20,738
Total other assets		5,238			20,738

Total assets	$	6,961,080		$	7,228,705

Liabilities and Stockholders’ Equity
Current liabilities:
Current portion of long-term debt	$	2,052,040		$	1,875,032
Accounts payable - related party		217,724			-
Accounts payable - others		931,088			551,895
Accrued liabilities		1,575,144			1,488,981
Total current liabilities		4,775,996			3,915,908

Long-term debt, net of current portion		-			60,000
Deferred income taxes		803,800			1,300,500
Asset retirement obligations		479,165			438,575
Total liabilities		6,058,961			5,714,983

Stockholders’ equity:
Preferred stock, $.01 par value per share, 1,000,000 shares authorized,
None issued		-			-
Common stock, $.01 par value per share, 200,000,000 shares authorized,
51,808,276 and 49,598,276 shares issued and outstanding		518,082			495,982
Additional paid in capital		15,018,429			13,660,160
Accumulated deficit		(14,634,392	)		(12,642,420	)
Total stockholders’ equity		902,119			1,513,722

Total liabilities and stockholders’ equity	$	6,961,080		$	7,228,705

See Accompanying Notes to Consolidated Financial Statements.

CAPROCK OIL, INC.

(formerly, Stratum Holdings, Inc.)

Consolidated Statements of Operations

	Year Ended December 31,
	2014			2013
				(As Restated)
Revenues:
Oil and gas sales	$	2,361,828		$	2,727,806
Total revenues		2,361,828			2,727,806

Operating expenses:
Lease operating expense		1,514,507			1,336,941
Depreciation, depletion and amortization		573,216			442,805
Accretion expense		40,590			37,130
Workover expense		941,606			292,876
Selling, general and administrative		1,618,861			1,026,855
Total operating expenses		4,688,780			3,136,607

Operating loss		(2,326,952	)		(408,801	)

Other income (expense):
Interest income		525			50,129
Interest expense		(162,245	)		(130,709	)
Loss on settlement of notes receivable		-			(286,235	)
Gain on oil and gas derivatives		-			4,900

Loss before income taxes		(2,488,672	)		(770,716	)
(Provision) benefit for income taxes		496,700			(791,700	)
Net loss	$	(1,991,972	)	$	(1,562,416	)

Net loss per share, basic and diluted	$	(0.04	)	$	(0.03	)

Weighted average shares outstanding, basic and diluted		51,135,235			49,598,276

See Accompanying Notes to Consolidated Financial Statements.

CAPROCK OIL, INC.

(formerly, Stratum Holdings, Inc.)

Consolidated Statements of Stockholders' Equity

For the Years Ended December 31, 2014 and 2013


					Additional						Total
	Common Stock				Paid-in			Accumulated			Stockholders'
	Shares		Amount		Capital			Deficit			Equity

Balance at January 1, 2013		2,655,738	$	26,557	$	12,894,490		$	(11,080,004	)	$	1,841,043

Related party interest forgiveness		-		-		265,812			-			265,812

Cinco NRG, LLC original capital contributed		41,300,000		413,000		(402,949	)		-			10,051

Cinco NRG, LLC conversion of notes payable		5,642,538		56,425		902,807			-			959,232

Net loss (as restated)		-		-		-			(1,562,416	)		(1,562,416	)

Balance at December 31, 2013 (As Restated)		49,598,276		495,982		13,660,160			(12,642,420	)		1,513,722

Private offering of common stock		600,000		6,000		594,000			-			600,000

Common stock for oil & gas property		120,000		1,200		84,800			-			86,000

Stock based compensation		1,490,000		14,900		679,469			-			694,369

Net loss		-		-		-			(1,991,972	)		(1,991,972	)

Balance at December 31, 2014		51,808,276	$	518,082	$	15,018,429		$	(14,634,392	)	$	902,119

See Accompanying Notes to Consolidated Financial Statements.

CAPROCK OIL, INC.

(formerly, Stratum Holdings, Inc.)

Consolidated Statements of Cash Flows

	Year Ended December 31,
	2014			2013
				(As Restated)
Cash flows from operating activities:
Net loss	$	(1,991,972	)	$	(1,562,416	)
Adjustments to reconcile net loss to net
cash provided by (used in) operations
Depreciation, depletion and amortization		573,216			442,805
Provision (benefit) for income taxes		(496,700	)		791,700
Loss on settlement of notes receivable		-			286,235
Unrealized gain on oil and gas derivatives		-			(4,900	)
Accretion expense		40,590			37,130
Stock based compensation		694,369			-
Changes in current assets and liabilities		627,728			(36,869	)
Other changes, net		-			2,516
Net cash flows from operating activities		(552,769	)		(43,799	)

Cash flows from investing activities:
Collection of notes receivable from sale of subsidiary		-			950,000
Purchase of property and equipment		(912,475	)		(720,072	)
Sale of property and equipment		-			11,659
Net cash flows from investing activities		(912,475	)		241,587

Cash flows from financing activities:
Proceeds of long term debt - related parties		-			324,283
Proceeds of long term debt - others		700,000			705,000
Proceeds of private equity offering		600,000			-
Payments of long term debt - related parties		-			(204,853	)
Payments of long term debt - others		(632,256	)		(652,865	)
Cinco original capital contributed		-			10,051
Net payments of stockholder advances		-			(14,714	)
Net cash flows from financing activities		667,744			166,902

Net increase (decrease) in cash and cash equivalents		(797,500	)		364,690
Cash and cash equivalents at beginning of period		877,525			512,835

Cash and cash equivalents at end of period	$	80,025		$	877,525

Supplemental cash flow data:
Cash paid for interest	$	162,245		$	119,933

Supplemental non-cash financing/investing activity:
Accounts payable for oil and gas properties		217,724			184,085
Common stock for oil and gas properties		86,000			-
Non-cash additions to notes payable		49,264			51,096
Non-cash conversion of notes payable to equity		-			959,232
Forgiveness of related party interest expense		-			265,812
Notes payable assumed in settlement agreement		-			216,305
Notes payable assumed for sale of property and equipment		-			57,690

See Accompanying Notes to Consolidated Financial Statements.

CAPROCK OIL, INC.

(formerly, Stratum Holdings, Inc.)

Notes to Consolidated Financial Statements

December 31, 2014 and 2013

(1) Business and Summary of Significant Accounting Policies

Description of Business – Caprock Oil, Inc. (“we”, “our” or the "Company") is a Nevada corporation, which operates in the Exploration & Production business. With our wholly-owned subsidiaries, we maintain working interests in various producing oil and gas properties in Texas and Louisiana as well as in several nonproducing oil and gas properties in Texas and Alabama.

In March 2014, we completed an acquisition of another company under common control with the Company (see Note 2). Accordingly, our consolidated balance sheet as of December 31, 2013 as well as our consolidated statement of operations, consolidated statement of stockholder’s equity, and consolidated statement of cash flows for the year then ended have been retrospectively restated herein.

The Company underwent a “change of control” at the shareholder level in September 2013. As a result of that transaction, the U.S. tax operating loss carryforwards that the Company previously reported became subject to certain annual limitations on their availability to offset future taxable income (see Note 9).

Principles of Consolidation – The consolidated financial statements include the accounts of Caprock Oil, Inc. and its wholly-owned subsidiaries. All significant intercompany amounts are eliminated in consolidation. Certain reclassifications have been made to the prior year statements to conform to the current year presentation.

Cash Equivalents – For purposes of the statement of cash flows, the Company considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents.

Oil and Gas Operations – For its oil and gas operations, the Company follows the sales method for recognizing its revenues and the full cost method in accounting for its costs. Costs associated with acquisition, exploration, and development of oil and gas reserves, including directly related overhead costs, are capitalized. (a) Capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the unit-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 is added to the capitalized costs to be amortized; (b) The capitalized costs are subject to a “ceiling test,” which basically limits such costs to the aggregate of the “estimated present value,” discounted at a 10-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 (c) 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 income.

Asset Retirement Obligations and Environmental Costs - The Company records the fair value of legal obligations to retire and remove long-lived assets in the period in which the obligation is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, the cost is capitalized by increasing the carrying amount of the related properties, plant and equipment. Over time the liability is increased for the change in its present value, and the capitalized cost in properties, plant and equipment is depreciated over the useful life of the related asset. Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and do not have a future economic benefit, are expensed.

Other Property and Equipment – Other property and equipment, primarily office furniture and fixtures, is depreciated on a straight-line basis over their useful lives ranging from three to five years.

Allowance for Doubtful Accounts – The Company has provided an allowance for uncollectible accounts receivable based on management's evaluation of collectability of outstanding balances. The allowance is based on estimates and actual losses may vary from current estimates.

Income Taxes – Income taxes are accounted for under the asset and liability method (see Note 9). 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 and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using statutory 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 from a change in tax rates is recognized in income in the period that includes the effective date of the change.

We follow ASC 740, “Income Taxes.” ASC 740 creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the financial statements. We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. The actual outcome of these future tax consequences could differ significantly from these estimates, which could impact our financial position, results of operations and cash flows. The evaluation of a tax position in accordance with ASC 740 is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement. No liability for unrecognized tax benefits was recorded as of December 31, 2014 or 2013.

Net Income (Loss) Per Share – Basic income (loss) per common share is computed by dividing the net income or loss by the weighted average number of shares of Common Stock outstanding during the period. Diluted income per common share is computed by considering dilutive common share equivalents under the Treasury Stock method. For the years ended December 31, 2014 and 2013, the basic and diluted average outstanding shares are the same because inclusion of common share equivalents would be anti-dilutive.

Use of Estimates – Management has made a number of estimates and assumptions in preparing these financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates.

Recently Issued Accounting Pronouncements – In the year ended December 31, 2014, the Financial Accounting Standards Board issued several new Accounting Standards Updates which the Company believes will have little or no applicability to the Company.

(2) Acquisition of Cinco NRG, LLC

On March 17, 2014, the Company completed the acquisition of Cinco NRG, LLC (“Cinco”), a private oil and gas company, which was under common control by its majority shareholder. The Company acquired Cinco through the issuance of a total of 46,942,538 shares of its Common Stock. Prior to the acquisition, a group of Cinco lenders had invested a total of $1,009,032 in convertible notes payable of Cinco and such investors elected to convert notes payable in the amount of $959,032 into equity of Cinco in October 2013. As a result of this transaction, the members of Cinco owned approximately 95% of the Company’s total shares of Common Stock outstanding at the date of the acquisition. In conjunction with this transaction, the Company also issued 1,250,000 shares of its Common Stock to an officer of the Company (see Note 8). Cinco was formed in April 2013 to acquire working interests in several new oil and gas properties in the States of Texas and Alabama. Cinco is now a wholly-owned subsidiary of the Company.

As noted above, the Company and Cinco were both under common control by a majority shareholder prior to this transaction. Under the accounting rules for entities under common control, the Company has accounted for Cinco’s operations on a retrospective basis in the Company’s consolidated financial statements from the inception of Cinco in April 2013. Accordingly, the consolidated balance sheet as of December 31, 2013, the consolidated statement of operations for the year ended December 31, 2013, and the consolidated statement of cash flows for the year ended December 31, 2013 have been retrospectively restated in this report to reflect Cinco’s accounts at their historical amounts as of those dates. The following table presents the revenues and net loss for the year ended December 31, 2013 of the previously separate companies and the combined amounts presented in these financial statements:

Revenues
Caprock	$	2,623,071
Cinco		104,735
Combined	$	2,727,806

Net Loss
Caprock	$	(1,488,740	)
Cinco		(73,676	)
Combined	$	(1,562,416	)

Cinco presently has working interests in several exploratory projects that are reflected in unevaluated properties at December 31, 2014. As the capitalized costs of these projects had not been evaluated as of December 31, 2014, no related depreciation, depletion and amortization expense has been recorded. An evaluation of such projects is largely expected to occur in the year ended December 31, 2015.

(3) Going Concern

The accompanying consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. The Company has reported net losses from continuing operations in the last two years and has a substantial working capital deficit as of December 31, 2014. These factors, among others, indicate that the Company may be unable to continue as a going concern for a reasonable period of time. The consolidated financial statements do not contain any adjustments to reflect the possible future effects on the classification of assets or the amounts and classification of liabilities that may result should the Company be unable to continue as a going concern.

(4) Sale of Canadian Energy Services Business

In June 2011, the Company entered into a Stock Purchase Agreement with a private company to sell the capital stock of its Canadian Energy Services subsidiaries, Decca Consulting, Ltd. and Decca Consulting, Inc. (collectively referred to as “Decca”), for a total sales price of $4,600,000 (plus a working capital adjustment). Included in the consideration for this sale were interest bearing notes (the “Installment Notes”) issued by the purchaser in the amount of $1,850,000, payable in 48 monthly installments of principal and interest, at 8% per annum, commencing on October 1, 2011.

In June 2013, the Company and the purchaser reached a preliminary agreement to settle a dispute regarding the outstanding balance of the Installment Notes. The preliminary settlement agreement provided for the purchaser to make a one-time cash payment to the Company and to assume all of the Company’s remaining obligations, including any continent liabilities, related to its prior ownership of Decca. The Company’s acceptance of the preliminary settlement on the Installment Notes also involved the assumption of a note payable of $216,305 and resulted in a total pre-tax net loss to the Company in the amount of $536,235. The Company had previously recognized an estimated loss provision in the year ended December 31, 2012 in the amount of $250,000, therefore, an additional loss provision was recognized in the year ended December 31, 2013 in the amount of $286,235. The closing and funding of the definitive settlement occurred in December 2013.

(5) Commodity Derivatives

Through December 31, 2013, the Company had a commodity derivative contract with a major energy company covering a portion of a subsidiary’s domestic oil production. This contract consisted of a two year “costless collar,” with floor and ceiling prices of $80.00 and $108.00 per barrel, and expired on December 31, 2013.

For the periods of any open derivative contracts, the Company applies “mark to market” accounting in accordance with ASC 815-20, “Accounting for Derivative Instruments and Hedging Activities,” and accounts for such contracts as non-hedging transactions, as defined in ASC 815-20. Accordingly, we reflect changes in fair value of open derivative contracts in current period earnings, based on “Level 3” inputs. In the year ended December 31, 2013, we reported an unrealized derivative gain of $4,900 due to fair value changes (see Note 12). In the year ended December 31, 2013, we reported no realized derivative gains or losses.

(6) Long-Term Debt

As of December 31, 2014 and 2013, the Company had the following long-term debt obligations:

	December 31,
	2014			2013
$25,000,000 line of credit with a bank, expired as of January 1 2015, interest at 1.0% above prime (but not less than 5.5%) payable monthly, secured by first lien on CYMRI, LLC’s oil and gas properties, with a declining borrowing base of $1,236,000 as of December 31, 2014	$	1,286,000		$	1,836,000

Bridge loans from individuals, due in October 2015, interest at 15% per annum, payable monthly, with second position security interest on oil and gas properties pledged to the bank (see above) and first position security interest on other oil and gas properties		700,000			-

Unsecured notes payable assumed in acquisition of Cinco NRG, LLC, final installment due and paid in February 2015		25,000			60,000

Other short term notes for equipment and insurance financing, interest rates at 6% to 8%		41,040			39,032

		2,052,040			1,935,032
Current portion of long term debt		(2,052,040	)		(1,875,032	)

Long term debt, net of current portion		-		$	60,000

Future maturities of long-term debt as of December 31, 2014 are as follows:

Year ending December 31, 2015	$	2,052,040
Year ending December 31, 2016		-
Year ending December 31, 2017		-
Year ending December 31, 2018		-
Year ending December 31, 2019		-

	$	2,052,040

Borrowings under the bank credit agreement secured by the oil and gas properties of our subsidiaries, CYMRI, LLC (“CYMRI”) and Triumph Energy, Inc. (“Triumph”), are subject to a borrowing base, dependent on oil and gas reserves. Pursuant to the latest borrowing base determination, the Company was required to make principal payments of $50,000 per month during 2014. Such principal payments were made in the first eleven months of the year, however, the Company did not make the required monthly principal payment in December 2014.

As a result of such non payment, the Company is in default of the credit agreement. Under its terms, the credit agreement expired on January 1, 2015, and the bank assessed an increase in the interest rate of 4% per annum on the outstanding borrowings of $1,286,000, until such amount is repaid. The Company is continuing to negotiate with the bank on a resolution of the outstanding borrowings under the expired credit agreement, while it seeks new sources of capital.

In October 2014, the Company implemented a “bridge loan” program whereby it made short term borrowings from a group of individual lenders. Amounts advanced under the bridge loan program accrue interest at the rate of 15% per annum, payable on a monthly basis, with the principal being due and payable within one year. In the event of a prepayment, the bridge lenders will receive a prepayment penalty equal to the difference between 15% of the principal and the accrued interest earned to that point, with such penalty being paid either in cash or in restricted shares of the Company’s Common Stock at an agreed upon value of $0.30 per share. The bridge lenders have been granted a security interest in the Company’s producing oil and gas properties subordinated only to the mortgage held by its secured lender. As of December 31, 2014, the Company had made borrowings of $700,000 under this program (see Note 14).

(7) Stockholders’ Equity

In June 2014, the Company commenced a private equity offering of Unit securities with each Unit comprised of two shares of Common Stock and a Warrant to purchase one share of Common Stock, exercisable at $2.00 per share, at an offering price of $2.00 per Unit. Through December 31, 2014, the Company had sold a total of 300,000 Units to accredited investors in this offering, resulting in gross proceeds of $600,000. The 300,000 Warrants issued in the Unit offering are exercisable by the holders within a three year period; the intrinsic value of such Warrants is zero and there are no other warrants currently outstanding. The Company authorized the sale of up to 4,000,000 Units in this private equity offering, however, the Company is no longer actively marketing the sale of any additional Unit securities.

In July 2014, the Company entered into a participation agreement to acquire a 20% working interest in a non-operated gas development project in Edwards County, Texas. The Company acquired its working interest from the operator by the issuance of 120,000 shares of its restricted Common Stock, and by agreeing to assume the obligation for 20% of the costs of drilling an initial well which commenced late in the first quarter of 2015. Based on the terms in the participation agreement, the Company recorded the 120,000 shares of Common Stock at a total value of $86,000.

In the year ended December 31, 2013, a group of Cinco lenders elected to convert convertible notes payable in the total amount of $959,032 into equity units of Cinco. Such equity units were converted into 5,642,538 shares of the Company’s Common Stock in the merger of Cinco into the Company in March 2014 (see Note 2).

(8) Stock-Based Compensation

The Company has a stock-based compensation plan which was approved by the stockholders in October 2005 and amended in October 2006. Under the plan, a maximum of 240,000 shares could be awarded to directors, employees and consultants in the form of grants of stock or stock options with underlying registration rights. The terms and other conditions applicable to each such grant are generally determined by the Board of Directors.

Pursuant to the terms of the stock-based compensation plan, the Company made a grant of 240,000 freely tradable shares of its Common Stock in March 2014 to a consultant who performed certain services for the Company. Based on quoted prices for the Company’s stock, the Company calculated the value of such issued shares at $132,000 and recorded an expense of that amount in the year ended December 31, 2014. While a new stock-based compensation plan has not been formally approved, the Company has reserved 4,000,000 shares of Common Stock for future issuance under such a plan.

In conjunction with the acquisition of Cinco, the Company issued 1,250,000 shares of its restricted Common Stock to an officer of the Company in March 2014 (see Note 2). The restricted shares will vest over a three year period and will be subject to buyback by the Company if the officer should terminate his employment prior to the end of such period. Based on quoted prices for the Company’s stock, the Company calculated the value of such issued shares at $687,500 and will amortize that total amount of expense over a three year period. During the year ended December 31, 2014, the Company recorded an amortized expense in the amount $190,970 for this grant.

In May 2014, the Company engaged a new Chief Executive Officer and granted him non-registered options to acquire 2,000,000 shares of its Common Stock at an exercise price of $0.65 per share, which was equal to the quoted price of its Common Stock on the date of the grant. Of these options, 200,000 shares vested immediately and the remaining 1,800,000 shares will vest ratably over a three year period. The estimated fair value of the option was calculated using a Black Scholes option pricing model based on the following assumptions: (a) Computed volatility – 187%; (b) Expected risk free interest rate – 1.6%; (c) Expected dividend yield – zero; (d) Expected option term – 4.4 years, calculated pursuant to the terms of ASC 718-10; and (e) Forfeitures – 0%, subject to adjustment for actual experience. On the basis of these assumptions, the Company calculated the value of such options at $1,238,000 and will amortize that total amount of expense over a three year period. During the year ended December 31, 2014, the Company recorded an amortized expense in the amount $371,400 for this grant. The intrinsic value of such non-registered options is zero and, except for the 300,000 Warrants issued by the Company in the Unit offering in June 2014 (see Note 7), there are no other options or warrants currently outstanding.

For the grants summarized above, the Company recorded aggregate stock compensation expense in the year ended December 31, 2014 in the total amount of $694,369 and has total future unrecognized compensation expense as of that date in the amount of $1,363,130.

(9) Income Taxes

The Company provided the following amounts of current and deferred income tax provision (benefit) for the years ended December 31, 2014 and 2013:

	Year ended December 31,
	2014			2013

Current income taxes	$	-		$	-
Deferred income taxes		(496,700	)		791,700
Total income tax provision (benefit)	$	(496,700	)	$	791,700

The following table shows components of income tax provision (benefit) in comparison to the U.S. statutory tax rate of 34% for the years ended December 31, 2014 and 2013:

	Year ended December 31,
	2014			2013

Tax benefit at U.S. statutory rate	$	(846,148	)	$	(146,618	)
Stock compensation expense and other non-deductible items		218,930			1,792
Operating loss carryforward adjustment		130,518			846,126
Gain on forgiveness of interest expense (see Note 10)		-			90,400
Total income tax provision (benefit)	$	(496,700	)	$	791,700

The following table indicates the tax effects of temporary differences giving rise to our deferred tax assets and liabilities as of December 31, 2014 and 2013:

	December 31,
	2014			2013
Deferred tax assets:
Operating loss carryforwards	$	531,500		$	229,800
Other, net		58,800			58,900
Gross deferred tax assets		590,300			288,700

Deferred tax liabilities:
Property and equipment		(1,394,100	)		(1,589,200	)
Gross deferred tax liabilities		(1,394,100	)		(1,589,200	)

Net deferred tax liabilities	$	(803,800	)	$	(1,300,500	)

As of December 31, 2014, we had consolidated U.S. tax operating loss carryforwards of approximately $1,563,000, expiring in future years. As a result of a “change of control” transaction in September 2013, our tax operating loss carryforwards became subject to certain annual limitations which severely restricted their availability to offset our future taxable income (see Note 1). Accordingly, we recognized an adjustment in the year ended December 31, 2013 to reduce the carrying value of the deferred tax asset associated with our tax operating loss carryforwards. Due to this adjustment, we reported a tax provision in the year ended December 31, 2013 in the amount of $791,700, notwithstanding the fact that we had a pre-tax net loss for that period.

(10) Related Party Transactions

A member of our Board of Directors, is the President of a private oil and gas company, which has a substantial number of oil and gas properties along the Gulf Coast areas of Texas and Louisiana. Among the properties that this company operates is a producing field in Texas in which Cinco has had a 10% working interest since August 2013. Additionally, this company served as the operator of an unsuccessful well drilled in Louisiana in which Cinco participated for a 5% working interest in July 2014. In both instances, this company billed Cinco for its share of the capital and operating costs of the properties, under a standard industry joint operating agreement (“JOA”). As of December 31, 2014, Cinco had accounts payable to this company of $217,724.

The Company repaid unsecured stockholder advances in the amount of $14,714 in the year ended December 31, 2013 resulting in no such further amounts remaining outstanding. The Company had previously accrued interest on such obligations at a rate of 10% per annum. As a precedent to the “change of control” transaction described in Note 1, the Company determined that past unpaid accruals of interest expense on former stockholder advances were no longer required, accordingly, a gain on forgiveness of interest expense in the amount of $265,812 was credited to Additional paid-in capital in the year ended December 31, 2013 (there was an income tax provision of $90,400 related to this gain).

In the year ended December 31, 2013, Cinco had related party note transactions in the net amount of $119,430. Also, a substantial portion of Cinco’s general and administrative expenses in that year represented “startup” business development expenditures and other related expenses paid by Cinco on behalf of its managing member.

(11) Commitments and Contingencies

The Company and its subsidiaries have operating leases for office space under which rental expense amounted to approximately $65,000 and $70,000 in the years ended December 31, 2014 and 2013, respectively. As of December 31, 2014, aggregate commitments under the Company’s operating leases were as follows:

Year ending December 31, 2015	$	60,000
Year ending December 31, 2016		61,000
Year ending December 31, 2017		41,000
Year ending December 31, 2018		-
Year ending December 31, 2019		-
	$	162,000

From time to time the Company may become involved in litigation in the ordinary course of business. At the present time, other than the Company’s disclosures below, the Company’s management is not aware of any such litigation that could have a material adverse effect on its results of operations, cash flows or financial condition.

Triumph Energy, Inc., a subsidiary in the Exploration & Production business, and a former Energy Services subsidiary which was sold in 2008, have been named as joint defendants in several lawsuits involving professional liability and other matters arising in the normal course of business in the State of Louisiana. Most of these cases have been settled with little or no net cost to Triumph. It is not practical at the present time to determine the amount or likelihood of an unfavorable outcome to the Company’s consolidated financial position or results of operations of any of the remaining actions against Triumph. The Company believes that Triumph has meritorious defenses in each case and is vigorously defending these matters. The Company has recorded no provision for estimated losses in these cases as of December 31, 2014.

In October 2008, an insurer for the Company’s inactive Construction Staffing subsidiary filed a lawsuit against the subsidiary alleging default on a premium finance obligation in the amount of approximately $200,000, plus interest and attorney’s fees. The Company believes that its inactive Construction Staffing subsidiary has a meritorious position in this matter and has not engaged legal counsel to defend this case. A default judgment was rendered in favor of the plaintiff in January 2011 and the Company has recorded an accrual for the subsidiary’s estimated loss exposure of approximately $100,000 as of December 31, 2014.

The Company, as a lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks. The Company is not aware of any environmental claims existing as of December 31, 2014, which have not been provided for, covered by insurance or otherwise have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past noncompliance with environmental laws will not be discovered on the Company’s properties.

(12) Other Required Disclosures

Asset Retirement Obligations – The Company records an asset retirement obligation (“ARO”) when the total depth of a drilled well is reached and the Company can reasonably estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs. The Company records the ARO liability on the consolidated balance sheets and capitalizes a portion of the cost in oil and gas properties equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date and adjusted for the Company’s credit risk. This amount is discounted to present value using an assumed cost of funds for the Company. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds. The Company did not drill or abandon any properties in the years ended December 31, 2014 and 2013. Therefore, the only ARO transactions were to accrue accretion expense of $40,590 and $37,130, respectively, in the years ended December 31, 2014 and 2013.

Credit Risk Concentrations – As previously noted, the Company’s current operations are in the domestic Exploration & Production business. In that business, the Company sells produced oil and gas mostly to well-known commodity purchasers from whom it does not require collateral. In the years ended December 31, 2014 and 2013, there was one major customer, Gulfmark Energy, which represented 66% and 85%, respectively, of the Company’s consolidated revenues. There were no other customers representing more than 10% of the Company’s consolidated revenues in the years ended December 31, 2014 and 2013.

The Company maintains its domestic cash accounts in three different federally chartered banking institutions. Its bank accounts in each bank are government insured up to a maximum of $250,000.

Fair Value of Financial Instruments – ASC 820, “Fair Value Measurements,” establishes a framework for measuring fair value and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements. Disclosures about fair value of financial instruments are based on pertinent information available to management and are not necessarily indicative of the amounts that could be realized on disposition of the financial instruments.

The statement requires disclosure that establishes a framework for measuring fair value and expands disclosure about fair value measurements. It requires fair value measurements be classified and disclosed in one of the following categories: (1) Level 1 - Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. (2) Level 2 - Quoted prices in markets that are not active or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity price swaps, investments and interest rate swaps. (3) Level 3 - Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). Our valuation models are primarily industry-standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments, as well as other relevant information. Pursuant to ASC 820, we valued our unexpired commodity derivatives contract based on a “Level 3” input which consisted of a valuation model provided by the counterparty (see Note 5).

Management has estimated the fair values of cash, accounts receivable, accounts payable and accrued liabilities (including oil and gas revenues received on behalf of suspended revenue interest owners) to approximate their respective carrying values reported on these financial statements because of their relatively short maturities. The carrying amounts of notes receivable and notes payable approximate fair value because their interest rates approximate market for items of similar risk.

(13) Oil and Gas Producing Activities (Unaudited)

Capitalized Costs of Oil and Gas Properties – The Company has owned working interests in oil and gas properties since acquiring CYMRI in May 2006. The table below reflects the capitalized costs of such oil and gas properties as of December 31, 2014 and 2013 (in thousands):

	December 31,
	2014			2013

Proved oil and gas properties	$	16,046		$	15,475
Unproved oil and gas properties		1,006			361
Gross oil and gas properties		17,052			15,836
Less: Accumulated depreciation, depletion & amortization		(10,496	)		(9,923	)

Net oil and gas properties	$	6,556		$	5,913

Costs Incurred in Oil and Gas Producing Activities – The table below presents the costs incurred in oil and gas producing activities for the years ended December 31, 2014 and 2013 (in thousands):


	December 31,
	2014		2013

Property acquisition	$	141	$	361
Exploration		133		-
Development		942		359

Total costs incurred	$	1,216	$	720

Results of Operations for Oil and Gas Producing Activities – The table below presents the results of operations for oil and gas producing activities for the years ended December 31, 2014 and 2013 (in thousands):

	Year ended December 31,
	2014			2013

Revenues	$	2,362		$	2,728
Production costs		(2,456	)		(1,630	)
Depreciation, depletion & amortization		(573	)		(443	)
Impairment expense		-			-
Income taxes		227			(199	)

Results of operations	$	(440	)	$	456

Oil and Gas Reserves – The following table sets forth summary information with respect to the Company’s proved oil and gas reserves as of December 31, 2014, prepared by the Company’s independent reservoir engineering firm. The estimates of proved and proved developed reserve quantities and the related measure of discounted future net cash flows are estimates only and do not purport to reflect realizable values or fair market values of the Company’s reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise and generally more conservative than those of producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. All of the Company's reserves are located in the United States.

	Oil		Gas		Total		PV10 Value
	(MBbl)		(MMcf)		(MBoe)		(000's)

Proved developed reserves		271		467		349	$	5,574
Proved undeveloped reserves		8		-		8		331
Total proved reserves		279		467		357		5,905
Discounted future income taxes								(1,346	)
Standardized measure of discounted
future net cash flows							$	4,559

Proved reserves are estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment, and operating methods.

The following table sets forth changes in the Company’s proved oil and gas reserves in the years ended December 31, 2014 and 2013 (in thousands):


	Oil			Gas			Total
	(MBbl)			(MMcf)			(MBoe)

Balance at January 1, 2013		477			663			588
Revisions of previous estimates		(56	)		79			(43	)
Discoveries		20			-			20
Production		(26	)		(64	)		(37	)
Balance at December 31, 2013		415			678			528
Revisions of previous estimates		(123	)		(144	)		(147	)
Discoveries		11			-			11
Production		(24	)		(67	)		(35	)

Balance at December 31, 2014		279			467			357

The standardized measure of discounted future net cash flows is computed by applying estimated prices of oil and gas (at 2014 first of the month average monthly prices) to the estimated future production of proved oil and gas reserves, less estimated future expenditures (at year-end 2014 costs) to be incurred in developing and producing the proved reserves, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10-percent per year to reflect the estimated timing of the future net cash flows. The Company does not believe that the standardized measure of discounted future net cash flows is necessarily indicative of the fair value of its oil and gas properties. The following table sets forth the components of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves as of December 31, 2014 and 2013 (in thousands):

	December 31,
	2014			2013

Future net revenues	$	26,497		$	42,646
Future lease operating expenses and production taxes		(14,935	)		(21,885	)
Future development costs		(468	)		(190	)
Future income taxes		(2,529	)		(6,318	)
Future net cash flows		8,565			14,253
10% annual discount for estimated timing of cash flows		(4,006	)		(6,529	)

Standardized measure of discounted future net cash flows	$	4,559		$	7,724

The following table sets forth changes in the standardized measure of the Company’s discounted future cash flows (“FCF”) relating to its proved oil and gas reserves in the years ended December 31, 2014 and 2013 (in thousands):

	Year ended December 31,
	2014			2013

Net changes in prices and production costs	$	(3,143	)	$	(1,077	)
Sales and transfers of oil and gas produced		(847	)		(1,397	)
Net change due to revisions in quantity estimates		(2,150	)		(603	)
Future development costs		(176	)		673
Net change in income taxes		1,958			136
Discoveries		508			1,062
Changes in production rates, other		(87	)		(238	)
Accretion of discount		772			834
Changes in standardized measure of discounted FCF		(3,165	)		(610	)
Beginning standardized measure of discounted FCF		7,724			8,334

Ending standardized measure of discounted FCF	$	4,559		$	7,724

(14) Subsequent Events

On January 28, 2015, the Company sold its 10% working interest in the Bloomington field in Victoria County, Texas, to the company which is the operator and the owner of the remaining 90% working interest in the field (see Note 10). The cash sales price was $500,000, subject to adjustments for unpaid revenues and expenditures incurred through the effective date (January 1, 2015). After taking such adjustments into account, the Company received net cash proceeds from the sale in the amount of approximately $261,000. In conjunction with the sale of its interest in the Bloomington field, the Company made a partial payment to the bridge lenders in the total amount of $100,000 (see Note 6). Under the terms of the bridge loans, the Company was also required to remit prepayment penalties to the lenders consisting of cash in the amount of $9,273 and 5,201 shares of the Company’s restricted Common Stock.

On February 20, 2015, the Company received a short-term loan from a major shareholder in the amount of $100,000 to enable the Company to pay a portion of the estimated drilling costs of the initial well in a non-operated gas development project in Edwards County, Texas (see Note 7). At the present time, the Company expects to repay the principal amount of the short-term loan, plus an uplift of 10%, upon the closing of a new third party financing or other liquidity event.

In late February 2015, the Company received a notice from an attorney representing a suspended royalty owner claiming past due revenues owed to the owner in an amount which the Company believes could be in excess of its currently available cash resources. The Company is still investigating the claim at this time.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	CAPROCK OIL, INC.

	By:	/s/ Steven H. Mikel
		Steven H. Mikel
		President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant in the capacities indicated on March 26, 2015.

Signature		Title

/s/ Steven H. Mikel		President and Chief Executive Officer
Steven H. Mikel

/s/ D. Hughes Watler, Jr.		Director and Chief Financial Officer
D. Hughes Watler, Jr.

/s/ Robert G. Wonish		Director
Robert G. Wonish

/s/ Christopher T. George		Director
Christopher T. George