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PED > SEC Filings for PED > Form 10-K on 31-Mar-2014All Recent SEC Filings

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Form 10-K for PEDEVCO CORP


31-Mar-2014

Annual Report


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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs and expected performance. We caution you that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. See "Risk Factors" and "Forward Looking Statements."

On July 27, 2012, we completed our acquisition of Pacific Energy Development Corp., which we refer to as Pacific Energy Development. The acquisition was accounted for as a "reverse acquisition," and Pacific Energy Development was deemed to be the accounting acquirer in the acquisition. Because Pacific Energy Development Corp. was deemed the acquirer for accounting purposes, the financial statements of Pacific Energy Development are presented as the continuing accounting entity and the below discussion solely relates to the financial information of Pacific Energy Development as the continuing accounting entity.

Overview

We are an energy company engaged primarily in the acquisition, exploration, development and production of oil and natural gas shale plays in the United States, and a secondary focus on conventional oil and natural gas plays. Our current operations are located primarily in the Niobrara Shale play in the DJ Basin in Weld and Morgan Counties, Colorado, and the Mississippian Lime play in Comanche, Harper, Barber and Kiowa Counties, Kansas. In March 2014, we expanded our DJ Basin position into the Wattenberg and Wattenberg Extension through the acquisition of additional oil and gas working interests from Continental, which includes approximately 14,000 net operated acres and interests in 40 wells located in Weld and Morgan Counties, Colorado. We also hold an interest in the North Sugar Valley Field in Matagorda County, Texas, though we consider this a non-core asset. We have entered into agreements to acquire an approximate 34% indirect interest (of which we are required to assign 50% of such interest, or 17%, to RJ Resources, as discussed below) in a company holding an exploration agreement covering an approximately 380,000 acre oil and gas producing asset located in the Pre-Caspian Basin in Kazakhstan, which we plan to close upon receipt of required approvals from the Kazakhstan government, anticipated to be received no later than the third quarter of 2014, as described in greater detail below.

We have approximately 16,379 net acres of oil and gas properties in the DJ Basin, including 13,995 net acres in our recently acquired Wattenberg Asset, and 2,384 net acres of oil and gas properties in our Niobrara Asset. Red Hawk holds our Wattenberg Asset with interests in 40 wells, 11 of which are operated by Red Hawk, 14 are non-operated, and Red Hawk has an after-payout interest in 15, with a two week average production from the 11 operated wells since their acquisition on March 7, 2014 of approximately 434 gross BOE per day, which does not include production from two of the wells which are currently undergoing repair. We estimate that once we bring these two wells back on production, the production from the 11 operated wells will be 504 gross BOE per day. We have not yet received enough information in regards to the 14 non-operated wells to estimate their current production. Condor, in which we own a 20% interest and manage with an affiliate of MIE Holdings Corporation, operates our Niobrara Asset, including five wells in the Niobrara Asset with daily production in the month of February 2014 of approximately 180 BOE (47 BOE net). We believe our current Wattenberg Asset could contain approximately a total of 1,256 gross (175 net) drilling locations, and our Niobrara Asset could contain a total of 212 gross (81 net) drilling locations, for a combined total of 1,468 gross (256 net) possible drilling locations in the DJ Basin, based on 40 and 80 acre spacing.

We have approximately 7,006 gross (3,443 net acres) of oil and gas properties in the Mississippian Asset, which we own an average of 49% working interest in and operate. We believe the Mississippian Asset could contain a total of 42 gross (21 net) drilling locations, based on 160 acre spacing.

We have also announced the entry into Kazakhstan through an agreement whereby we plan to acquire an approximate 34% indirect interest in Aral, a Kazakhstan entity which holds a 100% operated working interest in a production license covering the contract area issued by the Republic of Kazakhstan that expires in 2034 in western Kazakhstan, from Asia Sixth, which Contract Area covers 380,000 acres within the North Block located in the Pre-Caspian Basin. Under the agreement, we plan to acquire an interest in Aral through the acquisition of a 51% interest in Asia Sixth, by way of subscription of shares of Asia Sixth, which in turn currently holds a 60% controlling interest in Aral. Asia Sixth's interest in Aral is scheduled to increase to 66.5% following the completion of certain transactions to occur between Asia Sixth and Asia Sixth's partner in Aral that currently holds the remaining 40% interest in Aral. Upon closing and completion of the Aral Transactions, Aral will be owned 66.5% by Asia Sixth. We have also entered into an agreement with our strategic partner, RJ Resources, pursuant to which we have agreed, at the option of RJ Resources, to either (a) provide for the issuance of the share certificate representing the shares of capital stock due from Asia Sixth representing 51% of the total issued and outstanding share capital of Asia Sixth which we have the right to purchase from Asia Sixth, to a Delaware limited liability company to be formed by us and to convey to RJ Resources fifty percent (50%) of the limited liability company interests issued by such Nominee or (b) provide for fifty percent (50%) of such Asia Sixth shares to be issued directly to RJ Resources or its designee. Upon the closing and completion of these contemplated transactions, the Company, through its ownership in Asia Sixth, will own an approximate 17% beneficial interest in Aral.

We believe that the Wattenberg, Niobrara, and Mississippian Shale plays represent among the most promising unconventional oil and natural gas plays in the United States. We will continue to seek additional acreage proximate to our currently held core acreage. Our strategy is to be the operator, directly or through our subsidiaries and joint ventures, in the majority of our acreage so we can dictate the pace of development in order to execute our business plan. The majority of our capital expenditure budget for 2014 will be focused on the acquisition, development and expansion of these formations.

Detailed information about our business plans and operations, including our core Niobrara, Eagle Ford and Mississippian assets, is contained under "Part 1" - "Item 1. Business" beginning on page 5 of this Annual Report.


How We Conduct Our Business and Evaluate Our Operations

Our use of capital for acquisitions and development allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve. We have historically acquired properties that we believe had significant appreciation potential. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives.

We will use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

? production volumes;

? realized prices on the sale of oil and natural gas, including the effects of our commodity derivative contracts;

? oil and natural gas production and operating expenses;

? capital expenditures;

? general and administrative expenses;

? net cash provided by operating activities; and

? net income.

Production Volumes

Production volumes will directly impact our results of operations. We currently have production from 11 gross operated wells and 14 gross non-operated wells in our recently acquired Wattenberg Asset, five gross wells in our Niobrara Asset, and two gross wells in our North Sugar Valley field, and we expect to increase production assuming drilling success in the future as we expand operations in our Wattenberg, Niobrara and Mississippian Assets.

Factors Affecting the Sales Price of Oil and Natural Gas

We expect to market our crude oil and natural gas production to a variety of purchasers based on regional pricing. The relative prices of crude oil and natural gas are determined by the factors impacting global and regional supply and demand dynamics, such as economic conditions, production levels, weather cycles and other events. In addition, relative prices are heavily influenced by product quality and location relative to consuming and refining markets.

Oil. The New York Mercantile Exchange-West Texas Intermediate (NYMEX-WTI) futures price is a widely used benchmark in the pricing of domestic crude oil in the U.S. The actual prices realized from the sale of crude oil differ from the quoted NYMEX-WTI price as a result of quality and location differentials. Quality differentials to NYMEX-WTI prices result from the fact that crude oils differ from one another in their molecular makeup, which plays an important part in their refining and subsequent sale as petroleum products. Among other things, there are two characteristics that commonly drive quality differentials: (a) the crude oil's American Petroleum Institute, or API, gravity and (b) the crude oil's percentage of sulfur content by weight. In general, lighter crude oil (with higher API gravity) produces a larger number of lighter products, such as gasoline, which have higher resale value and, therefore, normally sell at a higher price than heavier oil. Crude oil with low sulfur content ("sweet" crude oil) is less expensive to refine and, as a result, normally sells at a higher price than high sulfur-content crude oil ("sour" crude oil).

Location differentials to NYMEX-WTI prices result from variances in transportation costs based on the produced crude oil's proximity to the major consuming and refining markets to which it is ultimately delivered. Crude oil that is produced close to major consuming and refining markets, such as near Cushing, Oklahoma, is in higher demand as compared to crude oil that is produced farther from such markets. Consequently, crude oil that is produced close to major consuming and refining markets normally realizes a higher price (i.e., a lower location differential to NYMEX-WTI).

In the past, crude oil prices have been extremely volatile, and we expect this volatility to continue. For example, for the four years ended December 31, 2013, the NYMEX - WTI oil price ranged from a high of $113.93 per Bbl to a low of $68.01 per Bbl. These markets will likely continue to be volatile in the future.


Natural Gas. The NYMEX-Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the U.S. Similar to crude oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX-Henry Hub price as a result of quality and location differentials. Quality differentials to NYMEX-Henry Hub prices result from: (a) the British thermal unit (Btu) content of natural gas, which measures its heating value, and (b) the percentage of sulfur, CO2 and other inert content by volume. Wet natural gas with a high Btu content sells at a premium to low Btu content dry natural gas because it yields a greater quantity of natural gas liquids (NGLs). Natural gas with low sulfur and CO2 content sells at a premium to natural gas with high sulfur and CO2 content because of the added cost to separate the sulfur and CO2 from the natural gas to render it marketable. Wet natural gas is processed in third-party natural gas plants and residue natural gas as well as NGLs are recovered and sold. Dry natural gas residue from our properties is generally sold based on index prices in the region from which it is produced.

Location differentials to NYMEX-Henry Hub prices result from variances in transportation costs based on the natural gas' proximity to the major consuming markets to which it is ultimately delivered. Also affecting the differential is the processing fee deduction retained by the natural gas processing plant generally in the form of percentage of proceeds. Generally, these index prices have historically been at a discount to NYMEX-Henry Hub natural gas prices.

In the past, natural gas prices have been extremely volatile, and we expect this volatility to continue. For example, for the four years ended December 31, 2013, the NYMEX - Henry Hub natural gas price ranged from a high of $7.51 per MMBtu to a low of $1.82 per MMBtu. These markets will likely continue to be volatile in the future.

Commodity Derivative Contracts. We expect to adopt a commodity derivative policy designed to minimize volatility in our cash flows from changes in commodity prices. We have not determined the portion of our estimated production, if any, for which we will mitigate our risk through the use of commodity derivative instruments, but in no event will we maintain a commodity derivative position in an amount in excess of our estimated production. Should we reduce our estimates of future production to amounts which are lower than our commodity derivative volumes, we will reduce our positions as soon as practical. If forward crude oil or natural gas prices increase to prices higher than the prices at which we have entered into commodity derivative positions, we may be required to make margin calls out of our working capital in the amounts those prices exceed the prices we have entered into commodity derivative positions.

Oil and Natural Gas Production Expenses. We will strive to increase our production levels to maximize our revenue. Oil and natural gas production expenses are the costs incurred in the operation of producing properties and workover costs. We expect expenses for utilities, direct labor, water injection and disposal, and materials and supplies to comprise the most significant portion of our oil and natural gas production expenses. Oil and natural gas production expenses do not include general and administrative costs or production and other taxes. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities may result in increased oil and natural gas production expenses in periods during which they are performed.

A majority of our operating cost components will be variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, we will incur power costs in connection with various production related activities such as pumping to recover oil and natural gas and separation and treatment of water produced in connection with our oil and natural gas production. Over the life of hydrocarbon fields, the amount of water produced may increase for a given volume of oil or natural gas production, and, as pressure declines in natural gas wells that also produce water, more power will be needed to provide energy to artificial lift systems that help to remove produced water from the wells. Thus, production of a given volume of hydrocarbons may become more expensive each year as the cumulative oil and natural gas produced from a field increases until, at some point, additional production becomes uneconomic.

Production and Ad Valorem Taxes. Texas regulates the development, production, gathering and sale of oil and natural gas, including imposing production taxes and requirements for obtaining drilling permits. For oil production, Texas currently imposes a production tax at 4.6% of the market value of the oil produced and an additional regulatory fee of 3/16 of one cent per barrel of crude petroleum produced plus an oil cleanup fee of 5/16 of a cent per barrel of crude petroleum produced, and for natural gas, Texas currently imposes a production tax at 7.5% of the market value of the natural gas produced. Colorado imposes production taxes ranging from 2% to 5% based on gross income and a conservation tax ranging from 0.07% to 1.5% based on the market value of oil and natural gas production. Ad valorem taxes are generally tied to the valuation of the oil and natural gas properties; however, these valuations are reasonably correlated to revenues, excluding the effects of any commodity derivative contracts.

General and Administrative Expenses. General and administrative expenses related to being a publicly traded company include: Exchange Act reporting expenses; expenses associated with Sarbanes-Oxley compliance; expenses associated with our efforts to have our shares listed on the NYSE MKT; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance costs; and director compensation. As a publicly-traded company, we expect that general and administrative expenses will continue to be significant.

Income Tax Expense. We are a C-corporation for federal income tax purposes, and accordingly, we are directly subject to federal income taxes which may affect future operating results and cash flows. We are also subject to taxation through our membership interests in our joint ventures, which are limited liability companies taxed as pass-through entities.


Liquidity and Capital Resources

Liquidity Outlook

We expect to incur substantial expenses and generate significant operating losses as we continue to explore for and develop our oil and natural gas prospects, and as we opportunistically invest in additional oil and natural gas properties, develop our discoveries which we determine to be commercially viable and incur expenses related to operating as a public company and compliance with regulatory requirements.

Our future financial condition and liquidity will be impacted by, among other factors, the success of our exploration and appraisal drilling program, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, and the actual cost of exploration, appraisal and development of our prospects. Assuming that we complete one or more public or private debt or equity financings to fund our planned 2014 capital expenditures and repay our outstanding debt as it becomes due, we plan to make capital expenditures, excluding capitalized interest and general and administrative expense, of up to $22 million during the period from January 1, 2014 to December 31, 2014 in order to achieve our plans.

We expect our projected cash flow from operations combined with our existing cash on hand and the $15.5 million gross ($12.5 million net, after origination-related fees and expenses) available under our current debt facility will be sufficient to fund our operations for the next twelve months. The debt due to the holders of secured promissory notes dated March 22, 2013, as amended, in the principal amount of $2.375 million maturing on July 31, 2014, and the repayment of debt due to MIEJ under a secured subordinated promissory note dated February 14, 2013, as amended March 25, 2013 and July 9, 2013, in the principal amount of $6.17 million maturing on August 31, 2014, have been subordinated and are not eligible to be repaid until the maturity of our senior credit facility, described in greater detail below under "Secured Debt Funding", but may be paid if and when our senior creditor allows during the three year term of our senior credit facility. We may seek additional funding through asset sales, farm-out arrangements, lines of credit, or public or private debt or equity financings to fund additional 2014 capital expenditures and/or repay or refinance a portion or all of our outstanding debt if allowed to do so by our senior creditor.

Our capital budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil and natural gas prices decline or costs increase significantly, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, timing of regulatory approvals, availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control.

Historical Liquidity and Capital Resources

Amendment to PEDCO-MIEJ Note

On March 25, 2013, we and MIE Jurassic Energy Corporation ("MIEJ"), amended and restated that certain Secured Subordinated Promissory Note, dated February 14, 2013 provided to MIEJ by our wholly-owned subsidiary PEDCO (the "MIEJ Note"), to increase from $5 million the maximum amount available for us to borrow thereunder to $6.5 million, and to permit amounts borrowed under the MIEJ Note to be used by us to fund fees and expenses allocable to us with respect to our operations in the Niobrara Asset, Niobrara Asset-related acquisition expenses, and repayment of $432,433 due to Condor as a refund of the performance deposit paid by MIEJ with respect to the Mississippian Asset acquisition and applied toward our purchase price of the Mississippian Asset. The MIEJ Note converted amounts previously advanced by MIEJ to us in the amount of $2.17 million to fund operations in the Niobrara Asset through November 1, 2012, as well as an additional $2 million loaned by MIEJ to us under the MIEJ Note on February 14, 2013 and $2 million loaned by MIEJ to us under the MIEJ Note on March 25, 2013.


On July 9, 2013, we and MIEJ agreed to amend the MIEJ Note to extend the maturity date from December 31, 2013 to August 31, 2014, and to remove the maturity trigger upon the closing of a debt or equity financing transaction with gross proceeds of $10 million to the Company. The Amended and Restated Secured Subordinated Promissory Note (the "Amended Note"), dated July 9, 2013, amends and restates the MIEJ Note. Under the Amended Note, PEDCO may draw down multiple advances up to a maximum of $6.5 million outstanding principal under the Note, with repaid amounts not being permitted to be re-borrowed. Amounts borrowed under the Amended Note may be used by PEDCO to fund fees and expenses allocable to PEDCO with respect to its operations in the Niobrara Asset. When drawn, principal borrowed under the Amended Note carries an interest rate of 10.0% per annum. Principal and accrued interest under the Amended Note are due and payable within ten (10) business days of August 31, 2014. The Amended Note may be prepaid in full by the Company without penalty, and is secured by all of PEDCO's ownership and working interest in the FFT2H, Waves 1H, Logan 2H, State 16-7-60 1H and Wickstrom 18-2H wells located in the Niobrara Asset, and all corresponding leasehold rights pooled with respect to such well, and PEDCO's ownership and working interest in each future well drilled and completed in the Niobrara Asset. The total principal amount outstanding under the note is $6.17 million as of December 31, 2013. There is currently approximately $330,000 available for future borrowing by PEDCO under the note. Further, the Company owes $585,777 in accrued interest at December 31, 2013 under the Note.

Amendments to Condor-MIEJ Note

On July 9, 2013, Condor, the Company's 20% owned subsidiary, and MIEJ agreed to amend the Promissory Note (the "Original Condor-MIEJ Note") previously entered into on February 14, 2013 by Condor and MIEJ, to increase the amount available for borrowing from $14 million to $25 million for the purposes of funding drilling and development of Condor's assets. The Amended and Restated Promissory Note, executed July 9, 2013 by Condor and effective June 28, 2013 (the "Amended Condor-MIEJ Note"), amends and restates the Original Condor-MIEJ Note. Under the Amended Condor-MIEJ Note, Condor may draw down multiple advances up to a maximum of $25 million outstanding principal under the Amended Condor-MIEJ Note (previously $14 million), with repaid amounts not being permitted to be re-borrowed. When drawn, principal borrowed under the Amended Condor-MIEJ Note carries an interest rate per annum equal to the one (1) month LIBOR rate, plus four percent (4%). Principal and accrued interest due under the Amended Condor-MIEJ Note is due and payable on the date that is 36 months from the date each advance is made under the Amended Condor-MIEJ Note. The note may be prepaid in full by Condor without penalty. The total principal amount outstanding as of December 31, 2013 under the Amended Condor-MIEJ Note is $26,472,535.

Bridge Notes

On March 22, 2013, to finance the acquisition of the Mississippian Asset, we closed a private placement of $4.0 million aggregate principal amount of secured promissory notes (the "Bridge Notes"). The Company incurred debt offering costs and deferred financing costs of $40,000 in connection with the debt placement.

The bridge notes were amended effective December 16, 2013, or the effective date, to provide for (i) the extension of the maturity date of such bridge notes, which were originally due as of December 31, 2013, to July 31, 2014, which we refer to as the extension term and new maturity date, respectively,
(ii) the subordination of the bridge notes to certain of our future qualified senior indebtedness with a principal amount of at least $5.0 million, (iii) the payment in full of all accrued interest through the effective date on January 8, 2014, or the payment date, equal to an aggregate of $294,795 due and payable to the bridge investors on the payment date, (iv) the payment in full of the payment-in-kind amount, or PIK, equal to 10% of the original principal amount of such bridge notes on the payment date, equal to an aggregate of $400,000 due and payable to the bridge investors on the payment date, (v) the repayment of either none or 50% of the outstanding principal amount due under such bridge notes, as elected by the holders thereof, on the payment date, which aggregate principal repayment of $1,625,000 shall be due and payable to the bridge investors on the payment date as elected by the holders, (vi) the amendment of the interest rate of such bridge notes for the extension term from 10% per annum to 12% per annum with respect to the remaining unpaid principal amount of such bridge notes, or the deferred principal, and (vii) an additional payment-in-kind cash amount equal to 10% of the deferred principal due on the new maturity date, or the additional PIK. In total, eleven (11) bridge investors holding bridge notes with an aggregate principal amount outstanding of $3,250,000 elected to defer 50% of their principal, agreeing to defer an aggregate of $1,625,000 in principal amount of the bridge notes, and five (5) bridge investors holding bridge notes with an aggregate principal amount outstanding of $750,000 elected to defer 100% of their principal, for a total deferred principal of $2,375,000, and an aggregate additional PIK due and paid upon the new maturity date of $237,500.

As additional consideration for the amendment of the bridge notes, we granted a new warrant, which we refer to as the new warrant, exercisable on a cashless basis at an exercise price of $2.34 per share for a number of shares of our common stock equal to (x) two times the number of shares issuable under the . . .

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